CALPINE CORP - 10-Q Quarterly Report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q


x		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the quarterly period ended June 30, 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 x No o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Yes x No o

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

383,045,514 shares of Common Stock, par value $.001 per share, outstanding on August 8, 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 4. Submission of Matters to a Vote of Security Holders
	Item 6. Exhibits and Reports on Form 8-K.
EXHIBIT INDEX
SIGNATURES
EXHIBIT 4.1
EXHIBIT 4.2
EXHIBIT 4.3
EXHIBIT 4.4
EXHIBIT 10.15
EXHIBIT 10.16
EXHIBIT 10.17
EXHIBIT 10.18
EXHIBIT 10.19
EXHIBIT 10.20
EXHIBIT 10.21
EXHIBIT 10.22
EXHIBIT 10.23
EXHIBIT 10.24
EXHIBIT 10.25
EXHIBIT 10.26
EXHIBIT 10.27
EXHIBIT 10.28
EXHIBIT 10.29
EXHIBIT 10.30
EXHIBIT 10.31
EXHIBIT 10.32
EXHIBIT 10.33
EXHIBIT 10.34
EXHIBIT 10.35
EXHIBIT 10.36
EXHIBIT 10.37
EXHIBIT 10.38
EXHIBIT 10.39
EXHIBIT 31.1
EXHIBIT 31.2
EXHIBIT 32.1

CALPINE CORPORATION AND SUBSIDIARIES
REPORT ON FORM 10-Q
For the Quarter Ended June 30, 2003

INDEX


		Page No.

PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Condensed Balance Sheets June 30, 2003 and December 31, 2002		3
	Consolidated Condensed Statements of Operations for the Three and Six Months Ended June 30, 2003 and 2002 (Restated)		5
	Consolidated Condensed Statements of Cash Flows for the Six Months Ended June 30, 2003 and 2002 (Restated)		7
	Notes to Consolidated Condensed Financial Statements		9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		34
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		64
Item 4.	Controls and Procedures		64
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings		64
Item 4.	Submission of Matters to a Vote of Security Holders		66
Item 6.	Exhibits and Reports on Form 8-K		67
Signatures			72

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements.

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS
June 30, 2003 and December 31, 2002
(in thousands, except share and per share amounts)


			June 30,		December 31,
			2003		2002

			(unaudited)
ASSETS
Current assets:
	Cash and cash equivalents		$	417,954	$	579,467
	Accounts receivable, net			943,972		745,312
	Margin deposits and other prepaid expense			374,889		152,413
	Inventories			132,524		106,536
	Restricted cash			284,856		176,716
	Current derivative assets			758,161		330,244
	Other current assets			50,534		145,608

		Total current assets		2,962,890		2,236,296

Restricted cash, net of current portion				23,687		9,203
Notes receivable, net of current portion				201,192		195,398
Project development costs				133,865		116,795
Investments in power projects				402,724		421,402
Deferred financing costs				284,482		185,026
Prepaid lease, net of current portion				351,626		301,603
Property, plant and equipment, net				19,867,039		18,846,580
Goodwill				32,720		29,166
Other intangible assets, net				96,282		93,065
Long-term derivative assets				1,370,389		496,028
Other assets				290,446		296,430

		Total assets	$	26,017,342	$	23,226,992

LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
	Accounts payable		$	1,178,876	$	1,238,192
	Accrued payroll and related expense			61,047		48,322
	Accrued interest payable			203,146		189,336
	Income taxes payable			4,598		3,640
	Notes payable and borrowings under lines of credit, current portion			62,746		340,703
	Capital lease obligation, current portion			3,852		3,454
	Construction/project financing, current portion			345,743		1,307,291
	Current derivative liabilities			700,179		189,356
	Other current liabilities			315,017		246,837

		Total current liabilities		2,875,204		3,567,131

Term loan				949,565		949,565
Notes payable and borrowings under lines of credit, net of current portion				1,284,321		8,249
Capital lease obligation, net of current portion				196,486		197,653
Construction/project financing, net of current portion				4,106,585		3,212,022
Convertible Senior Notes Due 2006				1,200,000		1,200,000
Senior notes				6,920,214		6,894,801
Deferred income taxes, net				1,189,429		1,123,729
Deferred lease incentive				51,980		53,732
Deferred revenue				123,788		154,969
Long-term derivative liabilities				1,356,361		528,400
Other liabilities				220,587		175,655

		Total liabilities		20,474,520		18,065,906

Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts				1,124,498		1,123,969
Minority interests				421,597		185,203


			June 30,			December 31,
			2003			2002

			(unaudited)
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 381,260,990 shares in 2003 and 380,816,132 shares in 2002			381			381
	Additional paid-in capital			2,813,490			2,802,503
	Retained earnings			1,211,105			1,286,487
	Accumulated other comprehensive loss			(28,249	)		(237,457	)

		Total stockholders’ equity	$	3,996,727		$	3,851,914

		Total liabilities and stockholders’ equity	$	26,017,342		$	23,226,992

The accompanying notes are an integral part of these consolidated condensed financial statements.

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
For the Three and Six Months Ended June 30, 2003 and 2002


					Three Months Ended						Six Months Ended
					June 30,						June 30,

					2003			2002			2003			2002

								Restated(1)						Restated(1)
					(In thousands, except per share amounts)
					(Unaudited)
Revenue:
	Electric generation and marketing revenue
		Electricity and steam revenue			$	1,072,636		$	707,312		$	2,194,674		$	1,329,712
		Sales of purchased power for hedging and optimization				744,805			718,157			1,426,089			1,238,208

			Total electric generation and marketing revenue			1,817,441			1,425,469			3,620,763			2,567,920
	Oil and gas production and marketing revenue
		Oil and gas sales				29,490			16,128			55,479			69,204
		Sales of purchased gas for hedging and optimization				328,478			309,352			655,946			432,756

			Total oil and gas production and marketing revenue			357,968			325,480			711,425			501,960
	Trading revenue, net
		Realized revenue on power and gas trading transactions, net				9,060			2,202			30,274			8,431
		Unrealized mark-to-market gain (loss) on power and gas transactions, net				(7,221	)		1,974			(7,992	)		4,791

			Total trading revenue, net			1,839			4,176			22,282			13,222
	Other revenue					8,808			3,247			16,100			5,978

				Total revenue		2,186,056			1,758,372			4,370,570			3,089,080

Cost of revenue:
	Electric generation and marketing expense
		Plant operating expense				164,448			118,415			329,428			234,889
		Royalty expense				6,461			4,194			11,818			8,349
		Purchased power expense for hedging and optimization				738,719			550,879			1,418,668			980,114

			Total electric generation and marketing expense			909,628			673,488			1,759,914			1,223,352
	Oil and gas operating and marketing expense
		Oil and gas operating expense				29,082			22,788			54,773			44,427
		Purchased gas expense for hedging and optimization				331,122			331,392			648,070			452,753

			Total oil and gas operating and marketing expense			360,204			354,180			702,843			497,180
	Fuel expense					555,368			350,298			1,205,604			682,832
	Depreciation, depletion and amortization expense					140,187			103,674			274,897			198,643
	Operating lease expense					28,168			28,239			55,860			56,380
	Other expense					6,870			1,146			12,121			3,098

			Total cost of revenue			2,000,425			1,511,025			4,011,239			2,661,485

				Gross profit		185,631			247,347			359,331			427,595
Loss (income) from unconsolidated investments in power projects						(59,352	)		1,111			(64,475	)		(386	)
Equipment cancellation and impairment charge						19,222			14,200			19,309			182,671
Project development expense						6,072			10,513			11,158			21,851
General and administrative expense						63,820			52,422			117,520			110,248

	Income from operations					155,869			169,101			275,819			113,211
Interest expense						148,879			79,117			291,840			152,822
Distributions on trust preferred securities						15,656			15,655			31,313			31,309
Interest income						(9,002	)		(9,762	)		(17,039	)		(21,938	)
Minority interest expense						5,333			681			7,612			411
Other expense (income)						13,702			(3,718	)		48,293			(16,301	)

	Income (loss) before provision (benefit) for income taxes					(18,699	)		87,128			(86,200	)		(33,092	)
Provision (benefit) for income taxes						(3,881	)		27,767			(20,433	)		(14,801	)

	Income (loss) before discontinued operations and cumulative effect of a change in accounting principle					(14,818	)		59,361			(65,767	)		(18,291	)
Discontinued operations, net of tax provision (benefit) of $(5,330), $4,771, $(6,439) and $5,768						(8,548	)		8,960			(10,144	)		10,939
Cumulative effect of a change in accounting principle, net of tax provision of $—, $—, $450 and $—						—			—			529			—


		Three Months Ended					Six Months Ended
		June 30,					June 30,

		2003			2002		2003			2002

					Restated(1)					Restated(1)
		(In thousands, except per share amounts)
		(Unaudited)
	Net income (loss)	$	(23,366	)	$	68,321	$	(75,382	)	$	(7,352	)

Basic earnings (loss) per common share:
	Weighted average shares of common stock outstanding		381,219			356,158		381,089			331,745
	Income (loss) before discontinued operations and cumulative effect of a change in accounting principle	$	(0.04	)	$	0.17	$	(0.17	)	$	(0.06	)
	Discontinued operations, net of tax	$	(0.02	)	$	0.02	$	(0.03	)	$	0.04
	Cumulative affect of a change in accounting principle, net of tax	$	—		$	—	$	—		$	—

	Net income (loss)	$	(0.06	)	$	0.19	$	(0.20	)	$	(0.02	)

Diluted earnings (loss) per common share:
	Weighted average shares of common stock outstanding before dilutive effect of certain convertible securities		381,219			365,606		381,089			331,745

	Income (loss) before dilutive effect of certain convertible securities, discontinued operations and cumulative effect of a change in accounting principle	$	(0.04	)	$	0.16	$	(0.17	)	$	(0.06	)
	Dilutive effect of certain convertible securities	$	—		$	—	$	—		$	—

	Income (loss) before discontinued operations and cumulative effect of a change in accounting principle	$	(0.04	)	$	0.16	$	(0.17	)	$	(0.06	)
	Discontinued operations, net of tax	$	(0.02	)	$	0.02	$	(0.03	)	$	0.04
	Cumulative effect of a change in accounting principle, net of tax	$	—		$	—	$	—		$	—

	Net income (loss)	$	(0.06	)	$	0.18	$	(0.20	)	$	(0.02	)

(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.

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2003 and 2002
(in thousands)
(unaudited)


					Six Months
					Ended
					June 30,

					2003			2002

								Restated(1)
Cash flows from operating activities:
	Net loss				$	(75,382	)	$	(7,352	)
		Adjustments to reconcile net loss to net cash provided by operating activities:
		Depreciation, depletion and amortization				325,112			243,887
		Equipment cancellation and impairment cost				17,179			182,671
		Deferred income taxes, net				101,802			109,486
		Loss (gain) on sale of assets and development cost write-offs, net				9,367			(3,413	)
		Foreign currency translation loss				44,304			—
		Income from unconsolidated investments in power projects				(64,475	)		(386	)
		Distributions from unconsolidated investments in power projects				121,015			18
		Stock compensation expense				8,423			—
		Gain on repurchase of debt				(6,763	)		(4,773	)
		Other				7,935			(948	)
		Change in operating assets and liabilities, net of effects of acquisitions:
			Accounts receivable			(191,717	)		(33,361	)
			Change in net derivative liability			33,099			(244,088	)
			Other current assets			(145,349	)		167,075
			Other assets			(58,536	)		(4,664	)
			Accounts payable and accrued expense			(34,659	)		(34,295	)
			Other liabilities			21,949			62,738

				Net cash provided by operating activities		113,304			432,595

Cash flows from investing activities:
	Purchases of property, plant and equipment					(1,135,549	)		(2,510,141	)
	Acquisitions, net of cash acquired					(6,818	)		—
	Disposals of property, plant and equipment					13,681			49,822
	Advances to joint ventures					(49,683	)		(43,823	)
	Decrease (increase) in notes receivable					(5,794	)		1,401
	Maturities of collateral securities					3,702			3,325
	Project development costs					(20,513	)		(63,654	)
	Decrease (increase) in restricted cash					(122,623	)		1,041
	Cash flows from derivatives not designated as hedges					30,274			8,431
	Other					(4,480	)		2,164

		Net cash used in investing activities				(1,297,803	)		(2,551,434	)

Cash flows from financing activities:
	Repurchase of Zero-Coupon Convertible Debentures Due 2021					—			(873,227	)
	Repurchases of senior notes					(16,100	)		—
	Borrowings from notes payable and lines of credit					1,013,384			1,077,453
	Repayments of notes payable and lines of credit					(15,269	)		(87,465	)
	Borrowings from project financing					77,013			280,248
	Repayments of project financing					(143,998	)		(92,198	)
	Proceeds from issuance of Convertible Senior Notes Due 2006					—			100,000
	Proceeds from income trust secondary offering					126,462			—
	Proceeds from issuance of common stock					—			751,175
	Proceeds from King City financing transaction					82,000			—
	Financing costs					(134,443	)		(40,024	)
	Other					28,265			562

Net cash provided by financing activities						1,017,314			1,116,524

Effect of exchange rate changes on cash and cash equivalents						5,672			3,958
Net decrease in cash and cash equivalents						(161,513	)		(998,357	)


		Six Months
		Ended
		June 30,

		2003		2002

				Restated(1)
Cash and cash equivalents, beginning of period			579,467		1,594,144

Cash and cash equivalents, end of period		$	417,954	$	595,787

Cash paid during the period for:
	Interest, net of amounts capitalized	$	217,543	$	96,260
	Income taxes	$	10,761	$	12,853

(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.

CALPINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
June 30, 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 and second 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 June 30, 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 and six months ended June 30, 2002, to reflect the adoption of new accounting standards. The reclassifications include (a) treatment as discontinued operations pursuant to Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS No. 144”) of the 2002 sales of certain oil and gas properties, the Company’s specialty engineering unit 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 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 and six months ended June 30, 2002, have been restated and differ from amounts previously reported in the Company’s Quarterly Report on Form 10Q for the quarter ended June 30, 2002.

A summary of the significant effects of restatement, along with certain reclassification adjustments, to the consolidated condensed statement of operations for the three and six months ended June 30, 2002 is as follows:


	As Previously
Three months ended June 30, 2002	Reported		As Restated

Sales of purchased power	$	868,606	$	718,157
Oil and gas sales		52,163		16,128
Sales of purchased gas		302,044		309,352
Total revenue		1,941,806		1,758,372
Purchased power expense		698,176		550,879
Purchased gas expense		333,724		331,392
Depreciation, depletion and amortization expense		110,122		103,674
Operating lease expense		36,263		28,239
Gross profit		256,306		247,347
Interest expense		67,058		79,117
Income before discontinued operations and extraordinary items		72,516		59,361
Net income		72,516		68,321
Income per share — basic		0.20		0.19
Income per share — diluted		0.19		0.18


	As Previously
Six months ended June 30, 2002	Reported			As Restated

Sales of purchased power	$	1,776,907		$	1,238,208
Oil and gas sales		119,651			69,204
Sales of purchased gas		434,202			432,756
Total revenue		3,680,153			3,089,080
Purchased power expense		1,513,481			980,114
Purchased gas expense		457,418			452,753
Depreciation, depletion and amortization expense		213,995			198,643
Operating lease expense		72,397			56,380
Gross profit		434,270			427,595
Interest expense		128,369			152,822
Loss before discontinued operations and extraordinary items		(3,881	)		(18,291	)
Net loss		(1,751	)		(7,352	)
Loss per share — basic and diluted		(0.01	)		(0.02	)

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.

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 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 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 and six months ended June 30, 2003 and 2002, had the Company applied the accounting provisions of SFAS No. 123 to its prior years’ financial statements.


			Three Months Ended					Six Months Ended
			June 30,					June 30,

			2003			2002		2003			2002

Net income (loss)
	As reported		$	(23,366	)	$	68,321	$	(75,382	)	$	(7,352	)
	Pro Forma			(26,860	)		61,059		(83,657	)		(27,784	)
Earnings per share data:
	Basic earnings (loss) per share
		As reported	$	(0.06	)	$	0.19	$	(0.20	)	$	(0.02	)
		Pro Forma		(0.07	)		0.17		(0.22	)		(0.08	)
	Diluted earnings (loss) per share
		As reported	$	(0.06	)	$	0.18	$	(0.20	)	$	(0.02	)
		Pro Forma		(0.07	)		0.16		(0.22	)		(0.08	)
Stock-based compensation cost, net of tax, included in net income, as reported			$	2,909		$	—	$	6,276		$	—
Stock-based compensation cost, net of tax, included in net income, pro forma				6,403			7,262		14,551			20,432

The range of fair values of the Company’s stock options granted for the three months ended June 30, 2003 and 2002, respectively, was as follows, based on varying historical stock option exercise patterns by different levels of Calpine employees: $2.52-$4.38 in 2003, $4.86-$6.98 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 70.82%-84.93% and 61.20%-68.72% for the three months ended June 30, 2003 and 2002, respectively, risk-free interest rates of 2.47%-3.40% and 3.73%-4.86% for the three months ended June 30, 2003 and 2002, respectively, and expected option terms of 4-9 1/2 years and 4-9 1/2 years for the three months ended June 30, 2003 and 2002, respectively.

The range of fair values of the Company’s stock options granted for the six months ended June 30, 2003 and 2002, respectively, was as follows, based on varying historical stock option exercise patterns by different levels of Calpine employees: $2.43-$3.41 in 2003, $4.05-$13.83 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%-112.99% and 59.30%-68.72% for the six months ended June 30, 2003 and 2002, respectively, risk-free interest rates of 1.39%-4.04% and 3.73%-5.42% for the six months ended June 30, 2003 and 2002, respectively, and expected option terms of 2 1/2-9 1/2 years and 4-9 1/2 years for the six months ended June 30, 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 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 the Company’s Consolidated Condensed Financial Statements, relative to VIEs created after January 31, 2003. One possible consequence of FIN 46 is that certain investments accounted for under the equity method might have to be consolidated. However, based on the Company’s preliminary assessment, and subject to further analysis, the Company does not believe that FIN 46 will require any of the Company’s pre-February 1, 2003 equity method investments to be consolidated.

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. However, the Company believes that adoption of SFAS No. 150 might require the Company to reclassify its $1.1 billion trust preferred securities (“HIGH TIDES”) which are shown on the balance sheet as “Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts,” as debt. Similarly, the Company may be required to reclassify some portion of its $422 million of “Minority interests” on the balance sheet as debt. These reclassifications would not affect net income or total stockholders equity but would impact the Company’s debt-to-equity and debt-to-capitalization ratios.

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 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 contracts currently identified as potentially being subject to DIG Issue No. C20 and market prices as of August 4, 2003, the Company estimates that it will recognize net derivative assets between $237 million and $356 million and a cumulative effect adjustment to net income between $147 million and $221 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.

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):


	June 30,			December 31,
	2003			2002

Buildings, machinery, and equipment	$	13,139,352		$	10,290,250
Oil and gas properties, including pipelines		2,247,005			2,031,026
Geothermal properties		407,912			402,643
Other		222,566			183,580

		16,016,835			12,907,499
Less: accumulated depreciation, depletion and amortization		(1,563,061	)		(1,220,094	)

		14,453,774			11,687,405
Land		86,993			82,158
Construction in progress		5,326,272			7,077,017

Property, plant and equipment, net	$	19,867,039		$	18,846,580

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 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 June 30, 2003 and 2002, the total amount of interest capitalized was $116.5 million and $171.0 million, respectively, including $18.8 million and $37.0 million, respectively, of interest incurred on funds borrowed for specific construction projects and $97.7 million and $134.0 million, respectively, of interest incurred on general corporate funds used for construction. For the six months ended June 30, 2003 and 2002, the total amount of interest capitalized was $235.0 million and $334.1 million, respectively, including $38.4 million and $72.1 million, respectively, of interest incurred on funds borrowed for specific construction projects and $196.6 million and $262.0 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 June 30, 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 secured working capital revolving credit facilities.

Capital Spending — Development and Construction

Construction and development costs consisted of the following at June 30, 2003 (in thousands):


						Equipment		Project		Equipment for
		# of				Included in		Development		Future Use in
		Projects		CIP		CIP		Costs		Other Assets

Projects in active construction			13	$	3,888,748	$	1,470,038	$	—	$	—
Projects in advanced development			11		732,498		646,380		112,940		—
Projects in suspended development			6		598,014		326,577		12,767		—
Projects in early development			3		3,800		—		8,158		—
Other capital projects		NA			103,212		—		—		—
Unassigned turbines		NA			—		—		—		133,447

	Total construction and development costs			$	5,326,272	$	2,442,995	$	133,865	$	133,447

Projects in Active Construction — The 13 projects in active construction are estimated to come on line from November 2003 to June 2005. These projects will bring on line approximately 6,485 and 7,558 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 $1.1 billion.

Projects in Advanced Development — There are 11 projects in advanced development. Of the total amount capitalized approximately $646.4 million relates to equipment, primarily turbine progress payments. These projects will bring on line approximately 6,011 and 7,209 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 $3.6 billion. The Company’s current plan is to project finance these costs as power purchase agreements are arranged.

Suspended Development Projects — Due to current electric market conditions, the Company has ceased capitalization of additional development costs and interest expense on certain development projects on which work has been suspended. Capitalization of costs may recommence as work on these projects resumes, if certain milestones and criteria are met 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 2,938 and 3,418 MW of base load and base load with peaking capacity, respectively. The estimated cost to complete these projects is approximately $1.5 billion. Of the amount capitalized approximately $326.6 million relates to equipment cost, primarily turbine progress payments.

Projects in Early Development — Costs for projects that are in early stages of development are capitalized only when it is highly probable that such costs are ultimately recoverable and significant project milestones are achieved. Until then all costs, including interest costs are expensed. The projects in early development with capitalized costs relate to three projects and include geothermal drilling costs and equipment purchases.

Other Capital Projects — Other capital projects primarily consist of enhancements to operating power plants, oil and gas and geothermal resource and facilities development as well as software developed for internal use.

Unassigned Equipment — As of June 30, 2003, the Company had made progress payments on 7 turbines, 14 heat recovery steam generators, and other equipment with an aggregate carrying value of $110.4 million classified on the balance sheet as other assets, 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 has $23.1 million, net of impairment in other current assets relating to turbines that the Company considers held for sale. SFAS No. 144 requires long-lived assets classified as held for sale to be written down to their fair market value, less disposal costs. During the quarter ended June 30, 2003, the Company recorded an impairment of $17.2 million on the turbines classified as held for sale. The Company reviews its other unassigned equipment for potential impairment based on probability-weighted alternatives of utilizing it for future projects versus selling it. Utilizing this methodology, the Company does not believe that the equipment not committed to

sale 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 SFAS No. 144.

4. Goodwill and Other Intangible Assets

Recorded goodwill was $32.7 million and $29.2 million as of June 30, 2003, and December 31, 2002, respectively, and is included in the corporate and other reporting unit.

The increase in goodwill during 2003 is due to a $3.5 million accrual in anticipation of certain contingent payments that the Company will pay in December 2003 related to performance incentives under the terms of the PSM purchase agreement.

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 June 30, 2003					As of December 31, 2002
		Useful
		Life/Contract		Carrying		Accumulated			Carrying		Accumulated
		Life		Amount		Amortization			Amount		Amortization

Patents			5	$	485	$	(279	)	$	485	$	(231	)
Power sales agreements			14		156,814		(108,394	)		156,814		(106,227	)
Fuel supply and fuel management contracts			26		22,198		(4,549	)		22,198		(4,105	)
Geothermal lease rights			20		19,518		(400	)		19,518		(350	)
Steam purchase agreement			14		5,340		(687	)		5,201		(486	)
Other			8		6,386		(150	)		319		(71	)

	Total			$	210,741	$	(114,459	)	$	204,535	$	(111,470	)

Amortization expense of other intangible assets was $1.2 million and $6.0 million in the three months ended June 30, 2003 and 2002, respectively, and $3.0 million and $12.1 million in the six months ended June 30, 2003 and 2002, respectively. Assuming no future impairments of these assets or additions as the result of acquisitions, amortization expense for the twelve months ended December 31 will be $5.5 million in 2003, $5.0 million in 2004, $5.0 million in 2005, $4.9 million in 2006 and $4.9 million in 2007.

5. Financing

As of June 30, 2003, $930.1 million outstanding under the Company’s $1.0 billion construction revolving credit facility, $453.4 million outstanding under the Company’s working capital revolving credit facility and $949.6 million outstanding under the term facility were classified as long-term debt in the accompanying consolidated condensed balance sheet as the Company has since replaced (or will imminently replace) the debt with other long-term debt instruments, as disclosed in Note 15. Comparable reclassifications were made to the accompanying consolidated condensed balance sheet as of December 31, 2002.

On April 29, 2003, the Company sold a preferred interest in a subsidiary that leases and operates the 115-megawatt (“MW”) King City Power Plant to GE Structured Finance for $82 million. The preferred interest holder will receive approximately 60% of future cash flow distributions based on current projections. Due to its beneficial interest, the Company will continue to fully consolidate the entity and will continue to provide O&M services.

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-MW 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 terms of both agreements are 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. 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 and are non-recourse to the Company’s other consolidated subsidiaries. The two tranches of Senior Secured Notes have been rated Baa2 by Moody’s Investor Service, Inc. and BBB (with a negative outlook) by S&P.

In June 2003 the Company repurchased Pound Sterling 14.0 million (US$23.3 million) in aggregate outstanding principal amount of its 8 7/8% Senior Notes Due 2011 at a redemption price of Pound Sterling 9.7 million (US$16.1 million) plus accrued interest to the redemption date. The Company recorded a pre-tax gain on these transactions in the amount of $6.8 million.

One of the Company’s wholly-owned subsidiaries, South Point Energy Center, LLC, leases the 530-MW South Point power facility located in Arizona, pursuant to certain facility lease agreements. The Company has recently become aware that a technical default has occurred under such facility lease agreements as a result of an inadvertent pledge of the ownership interests in such subsidiary granted pursuant to certain separate loan facilities entered into by the Company. The Company is currently working with the lenders of such loan facilities to release the inadvertent pledge. The South Point facility lease was entered into as part of a larger transaction, which also involved the lease by two other subsidiaries of the Company of the following two power facilities: the 850-MW Broad River power facility located in South Carolina, and the 520-MW RockGen power facility located in Wisconsin. As all three lease transactions were part of the same overall transaction, the facility lease agreements for Broad River and RockGen contain cross-default provisions to the South Point facility lease agreements and, therefore, a technical default also exists under the Broad River and RockGen facility lease agreements. However, upon the anticipated release of the inadvertent South Point pledge, the default under the Broad River and RockGen facility lease agreements will also be cured. The Company believes that this release will occur and the default will be cured and, therefore, will not have a material adverse effect on the Company.

6. Investments in Power Projects

The Company’s investments in power projects are integral to its operations. In accordance with APB Opinion No. 18, “The Equity Method of Accounting For Investments in Common Stock” and FASB Interpretation No. 35, “Criteria for Applying the Equity Method of Accounting for Investments in Common Stock (An Interpretation of APB Opinion No. 18),” they are accounted for under the equity method, and are as follows (in thousands):


		Ownership			Investment Balance at
		Interest as of			June 30,
		June 30,
		2003			2003		2002

Acadia Power Plant			50.0	%	$	228,888	$	261,233
Grays Ferry Power Plant			40.0	%		39,361		29,791
Aries Power Plant			50.0	%		56,446		29,708
Gordonsville Power Plant			50.0	%		22,347		24,865
Androscoggin Power Plant			32.3	%		10,849		12,493
Whitby Cogeneration			20.8	%		43,810		45,383
Other			—			1,023		17,929

	Total investments in power projects				$	402,724	$	421,402

The debt on the books of the unconsolidated power projects is not reflected on the Company’s balance sheet. At June 30, 2003, based on the Company’s pro rata ownership share of each of the investments, the Company’s share of the combined debt balance of $543.5 million would be approximately $195.7 million. However, all such debt is non-recourse to the Company.

One of the Company’s unconsolidated equity method investees, Androscoggin Energy LLC (“AELLC”), which owns the 160-MW Androscoggin Energy Center located in Maine, in which the Company owns a 32.3% interest, has construction debt with $63 million outstanding as of June 30, 2003, that is non-recourse to Calpine Corporation (the “AELLC Non-Recourse Financing”). On June 30, 2003, the Company’s investment balance was $10.8 million and its notes receivable balance due from AELLC was $7.4 million. On August 8, 2003, AELLC received a letter from the lenders claiming that certain events of default have occurred under the credit agreement for the AELLC Non-Recourse Financing, including, among other things, that the project has been and remains in

default under its debt agreement because the lending syndication has declined to extend the dates for the conversion of the construction loan by a certain date. AELLC is currently discussing with the banks a forbearance arrangement until an agreement is reached concerning the extension, conversion or repayment of the debt; however, the outcome is uncertain at this point. Also, the steam host for the AELLC project, International Paper Company (“IP”), filed a complaint against AELLC in October 2000, which is disclosed in Note 12. IP’s complaint has been a complicating factor in converting the construction debt to long term financing.

Another of the Company’s unconsolidated 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 $195 million of debt as of June 30, 2003, that was due on June 26, 2003. Due to the default, the partners were required to contribute their proportionate share of $75 million in additional equity. During the quarter, the Company drew down $37.5 million under its working capital revolver to fund its equity contribution. The management of Aries is in negotiation with the lenders to extend the debt 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. The Company 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 $56.5 million investment in the Aries project and believes that the investment is not impaired.

The following details the Company’s income and distributions from investments in unconsolidated power projects (in thousands):


					Income						Distributions
		Ownership
		Interest			For the Six Months Ended June 30,

					2003			2002			2003		2002

Acadia Power Plant (1)			50.0	%	$	66,057		$	—		$	119,950	$	—
Gordonsville Power Plant			50.0	%		3,210			3,184			1,050		—
Lockport Power Plant (2)			—	%		—			1,570			—		—
Whitby Power Plant			20.8	%		1,231			370			—		—
Aries Power Plant			50.0	%		(599	)		571			—		—
Androscoggin Power Plant			32.3	%		(3,690	)		(1,039	)		—		—
Grays Ferry Power Plant			40.0	%		(1,929	)		(2,191	)		—		—
Other			—			195			(2,079	)		15		18

	Total				$	64,475		$	386		$	121,015	$	18

The Company provides for deferred taxes to the extent that distributions exceed earnings.

(1) On May 12, 2003, the Company completed the 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, the partnership terminated its 580-MW, 20-year tolling arrangement with a subsidiary of Aquila in return for a cash payment of $105.5 million. Acadia recorded a gain of $105.5 million and then made a $105.5 million distribution to Calpine. Subsequently, CES, a wholly owned subsidiary of Calpine, entered into a new 20-year, 580-MW 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. As a result of this transaction, the Company recorded, as its share of the termination payment from the Aquila subsidiary, a $52.8 million gain which was recorded within income from unconsolidated investments in power projects.

(2) On March 29, 2002, the Company sold its 11.4% interest in the Lockport Power Plant in exchange for a $27.3 million note receivable, which was subsequently paid in full, from Fortistar Tuscarora LLC, a wholly owned subsidiary of Fortistar LLC, the project’s managing general partner. This transaction resulted in a pre-tax gain of $9.7 million recorded in other income.

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 six months ended June 30, 2003:

Corporate and Other

In June 2003 the Company agreed to the divestiture of its specialty data center engineering business and estimated and recorded a pre-tax loss on the sale of $3.3 million. The Company subsequently completed the transaction on July 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-MW 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.

Summary

The table below presents significant components of the Company’s income from discontinued operations for the three and six months ended June 30, 2003 and 2002, respectively (in thousands):


	Three Months Ended June 30, 2003

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

Total revenue	$	—	$	—	$	1,985		$	1,985

Loss on disposal before taxes	$	—	$	—	$	(3,294	)	$	(3,294	)
Operating loss from discontinued operations before taxes		—		—		(10,584	)		(10,584	)

Loss from discontinued operations, before taxes	$	—	$	—	$	(13,878	)	$	(13,878	)

Loss on disposal, net of tax	$	—	$	—	$	(2,042	)	$	(2,042	)
Operating loss from discontinued operations, net of tax		—		—		(6,506	)		(6,506	)

Loss from discontinued operations, net of tax	$	—	$	—	$	(8,548	)	$	(8,548	)


	Six Months Ended June 30, 2003

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

Total revenue	$	—	$	—	$	3,748		$	3,748

Loss on disposal before taxes	$	—	$	—	$	(3,294	)	$	(3,294	)


	Six Months Ended June 30, 2003

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

Operating loss from discontinued operations before taxes		—		—		(13,289	)		(13,289	)

Loss from discontinued operations, before taxes	$	—	$	—	$	(16,583	)	$	(16,583	)

Loss on disposal, net of tax	$	—	$	—	$	(2,042	)	$	(2,042	)
Operating loss from discontinued operations, net of tax		—		—		(8,102	)		(8,102	)

Loss from discontinued operations, net of tax	$	—	$	—	$	(10,144	)	$	(10,144	)


	Three Months Ended June 30, 2002

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

Total revenue	$	4,469	$	29,439	$	2,002	$	35,909

Loss on disposal before taxes	$	—	$	—	$	—	$	—
Operating income from discontinued operations before taxes		1,347		12,263		121		13,731

Income from discontinued operations, before taxes	$	1,347	$	12,263	$	121	$	13,731

Loss on disposal, net of tax	$	—	$	—	$	—	$	—
Operating income from discontinued operations, net of tax		915		7,971		74		8,960

Income from discontinued operations, net of tax	$	915	$	7,971	$	74	$	8,960


	Six Months Ended June 30, 2002

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

Total revenue	$	6,962	$	47,563	$	3,829	$	58,353

Loss on disposal before taxes	$	—	$	—	$	—	$	—
Operating income from discontinued operations before taxes		2,581		14,114		13		16,707

Income from discontinued operations, before taxes	$	2,581	$	14,114	$	13	$	16,707

Loss on disposal, net of tax	$	—	$	—	$	—	$	—
Operating income from discontinued operations, net of tax		1,757		9,174		8		10,939

Income from discontinued operations, net of tax	$	1,757	$	9,174	$	8	$	10,939

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 and six months ended June 30, 2002, the Company allocated interest expense of $1.9 million and $3.0 million, respectively, to its discontinued operations. No interest expense was allocated to discontinued operations in 2003.

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 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.

The Company also routinely enters into physical commodity contracts for sales of its generated electricity and purchases of natural gas 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 June 30, 2003, for the Company’s derivative instruments:


		Interest			Commodity
		Rate			Derivative			Total
		Derivative			Instruments			Derivative
		Instruments			Net			Instruments

Current derivative assets		$	—		$	758,161		$	758,161
Long-term derivative assets			—			1,370,389			1,370,389

	Total assets	$	—		$	2,128,550		$	2,128,550

Current derivative liabilities		$	(15,088	)	$	(685,091	)	$	(700,179	)
Long-term derivative liabilities			(32,204	)		(1,324,157	)		(1,356,361	)

	Total liabilities	$	(47,292	)	$	(2,009,248	)	$	(2,056,540	)

Net derivative assets (liabilities)		$	(47,292	)	$	119,302		$	72,010

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 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 June 30, 2003 (in thousands):


Net derivative assets	$	72,010
Derivatives not designated as cash flow hedges and recognized hedge ineffectiveness		(160,460	)
Cash flow hedges terminated prior to maturity		(177,963	)
Deferred tax asset attributable to accumulated other comprehensive loss on cash flow hedges		105,578
Accumulated OCI from unconsolidated investees		(1,967	)
Other reconciling items		40

Accumulated other comprehensive loss from derivative instruments, net of tax (1)	$	(162,762	)

(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 June 30, 2003.


		June 30, 2003

		Gross			Net

Current derivative assets		$	1,774,801		$	758,161
Long-term derivative assets			1,617,994			1,370,389

	Total derivative assets	$	3,392,795		$	2,128,550

Current derivative liabilities		$	(1,701,732	)	$	(685,091	)
Long-term derivative liabilities			(1,571,761	)		(1,324,157	)

	Total derivative liabilities	$	(3,273,493	)	$	(2,009,248	)

	Net commodity derivative assets	$	119,302		$	119,302

The table above excludes the value of interest rate and currency derivative instruments.

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 unrealized mark-to-market activity of derivatives not designated as hedges of cash flows, for the three and six months ended June 30, 2003 and 2002, respectively (in thousands):


		Three Months Ended June 30,

		2003									2002

		Hedge			Undesignated						Hedge			Undesignated
		Ineffectiveness			Derivatives			Total			Ineffectiveness			Derivatives			Total

Natural gas derivatives (1)		$	2,067		$	3,556		$	5,623		$	279		$	(4,194	)	$	(3,915	)
Power derivatives (1)			(1,612	)		(11,232	)		(12,844	)		(1,002	)		6,891			5,889
Interest rate derivatives (2)			(275	)		—			(275	)		(188	)		—			(188	)

	Total	$	180		$	(7,676	)	$	(7,496	)	$	(911	)	$	2,698		$	1,787


		Six Months Ended June 30,

		2003									2002

		Hedge			Undesignated						Hedge			Undesignated
		Ineffectiveness			Derivatives			Total			Ineffectiveness			Derivatives			Total

Natural gas derivatives (1)		$	8,180		$	1,579		$	9,759		$	5,764		$	(11,029	)	$	(5,265	)
Power derivatives (1)			(4,638	)		(13,113	)		(17,751	)		(1,224	)		11,280			10,056
Interest rate derivatives (2)			(484	)		—			(484	)		(340	)		—			(340	)

	Total	$	3,058		$	(11,534	)	$	(8,476	)	$	4,200		$	252		$	4,452

(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 and six months ended June 30, 2003 and 2002, respectively (in thousands):


		Three Months Ended June 30,

		2003			2002

Natural gas and crude oil derivatives		$	(2,998	)	$	(39,277	)
Power derivatives			(4,223	)		75,313
Interest rate derivatives			(3,451	)		(2,550	)
Foreign currency derivatives			(729	)		15,439

	Total derivatives	$	(11,401	)	$	48,925


		Six Months Ended June 30,

		2003			2002

Natural gas and crude oil derivatives		$	32,164		$	(75,043	)
Power derivatives			(55,549	)		161,780
Interest rate derivatives			(14,093	)		(4,474	)
Foreign currency derivatives			11,828			15,152

	Total derivatives	$	(25,650	)	$	97,415

As of June 30, 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 8 1/2 and 11 1/2 years, for commodity and interest rate derivative instruments, respectively. The Company estimates that pre-tax losses of $85.9 million would be reclassified from accumulated OCI into earnings during the twelve months ended June 30, 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.


																2008
	2003			2004			2005			2006			2007			& After		Total

Crude oil OCI	$	(1,135	)	$	—		$	—		$	—		$	—		$	—	$	(1,135	)
Gas OCI		47,575			20,982			(36,691	)		16,162			1,413			4,960		54,401
Power OCI		(51,622	)		(69,054	)		(43,190	)		(27,686	)		(1,441	)		361		(192,632	)


																	2008
		2003			2004			2005			2006			2007			& After			Total

Interest rates OCI			(13,196	)		(23,298	)		(18,505	)		(14,079	)		(10,641	)		(40,376	)		(120,095	)
Foreign currency OCI			(974	)		(1,984	)		(2,020	)		(2,048	)		(1,678	)		(175	)		(8,879	)

	Total OCI	$	(19,352	)	$	(73,354	)	$	(100,406	)	$	(27,651	)	$	(12,347	)	$	(35,230	)	$	(268,340	)

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 Condensed Balance Sheets. 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			Comprehensive
									Accumulated			Income (Loss)
									Other			for the Three
						Foreign			Comprehensive			Months Ended
			Cash Flow			Currency			Income			March 31, 2003
			Hedges			Translation			(Loss)			and June 30, 2003

Accumulated other comprehensive loss at January 1, 2003			$	(224,414	)	$	(13,043	)	$	(237,457	)
Net loss for the three months ended March 31, 2003												$	(52,016	)
	Cash flow hedges:
		Comprehensive pre-tax gain on cash flow hedges before reclassification adjustment during the three months ended March 31, 2003		27,827
		Reclassification adjustment for loss included in net loss for the three months ended March 31, 2003		14,249
		Income tax provision for the three months ended March 31, 2003		(10,927	)

				31,149						31,149			31,149
		Foreign currency translation gain for the three months ended March 31, 2003		—			84,062			84,062			84,062

Total comprehensive income for the three months ended March 31, 2003												$	63,195

Accumulated other comprehensive loss at March 31, 2003			$	(193,265	)	$	71,019		$	(122,246	)

Net loss for the three months ended June 30, 2003												$	(23,366	)
	Cash flow hedges:
		Comprehensive pre-tax gain on cash flow hedges before reclassification adjustment during the three months ended June 30, 2003	$	47,892
		Reclassification adjustment for loss included in net loss for the three months ended June 30, 2003		11,401
		Income tax provision for the three months ended June 30, 2003		(28,790	)

				30,503						30,503			30,503
		Foreign currency translation gain for the three months ended June 30, 2003					63,494			63,494			63,494

Total comprehensive income for the three months ended June 30, 2003												$	70,631

Total comprehensive income for the six months ended June 30, 2003												$	133,826

Accumulated other comprehensive loss at June 30, 2003			$	(162,762	)	$	134,513		$	(28,249	)


									Total			Comprehensive
									Accumulated			Income (Loss)
									Other			for the Three
						Foreign			Comprehensive			Months Ended
			Cash Flow			Currency			Income			March 31, 2002
			Hedges			Translation			(Loss)			and June 30, 2002

Accumulated other comprehensive loss at January 1, 2002			$	(180,819	)	$	(60,061	)	$	(240,880	)
Net loss for the three months ended March 31, 2002												$	(75,673	)
	Cash flow hedges:
		Comprehensive pre-tax gain 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		(48,490	)
		Income tax provision for the three months ended March 31, 2002		(32,034	)

				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	)

Net income for the three months ended June 30, 2002												$	68,321
	Cash flow hedges:
		Comprehensive pre-tax gain on cash flow hedges before reclassification adjustment during the three months ended June 30, 2002	$	49,035
		Reclassification adjustment for gain included in net income for the three months ended June 30, 2002		(48,925	)
		Income tax benefit for the three months ended June 30, 2002		9,490

				9,600						9,600			9,600
		Foreign currency translation gain for the three months ended June 30, 2002					78,776			78,776			78,776

Total comprehensive income for the three months ended June 30, 2002												$	156,697

Total comprehensive income for the six months ended June 30, 2002												$	105,765

Accumulated other comprehensive loss at June 30, 2002			$	(121,307	)	$	(6,456	)	$	(127,763	)

10. Counterparties

The Company’s customer and supplier base is concentrated within the energy industry. As a result, the Company has exposure to trends within the energy industry, including declines in the creditworthiness of its risk management transactional counterparties. Currently, multiple companies within the energy industry are in bankruptcy or have below investment grade credit ratings. The Company has exposure to two counterparties, NRG Power Marketing, Inc. (“NRG”) and Americas Energy Marketing, L.P. (“Mirant”), which have filed for bankruptcy. Additionally, the Company has exposure to Aquila, Inc. and its affiliate, Aquila Merchant Services, Inc. (collectively “Aquila”) and Williams Energy Marketing & Trading Company (“Williams”), which are rated less than investment grade by the credit rating agencies. The Company believes that its credit exposure to other companies in the energy industry is not significant either by individual company or in the aggregate. The table below shows our exposure to the two bankrupt companies, NRG and Mirant, as well as the two largest exposures to below investment grade companies, Aquila and Williams, at June 30, 2003 (in thousands):


				Net Accounts
	Net			Receivable
	Derivative			and						Letters of Credit,
	Assets and			Accounts						Margin or Other			Net
	Liabilities			Payable			Reserve			Offsets			Exposure

NRG	$	(1,799	)	$	13,133		$	(2,354	)	$	—		$	8,980
Mirant	$	(926	)	$	1,833		$	—		$	—		$	907
Aquila	$	75,028		$	3,309		$	(2,948	)	$	(65,660	)(1)	$	9,729
Williams	$	29,560		$	(9,266	)	$	(416	)	$	2,300	(2)	$	22,178

(1)		$37.6 million margin deposit held by the Company on its balance sheet classified as other current liabilities plus $28.1 million of fair value of contractual commitments, which the Company has not recognized in its balance sheet because they are accounted for as normal purchases and sales.

(2)		Margin deposits held by Williams.

On May 14, 2003, NRG Energy, Inc. (“NRG”) and several affiliates filed chapter 11 bankruptcy petitions in the United States Bankruptcy Court for the Southern District of New York. Calpine has filed proofs of claim in the NRG bankruptcy for certain contingent, unliquidated amounts, and pre-bankruptcy petition and post-bankruptcy petition delivery of electric energy by Calpine to NRG for April and the first half of May 2003. At June 30, 2003, the Company had approximately $9.0 million in net exposure.

At June 30, 2003, the Company had approximately $0.9 million in net exposure to Mirant. On July 14, 2003, Mirant Americas Energy Marketing, L.P. (“Mirant”) and several affiliates filed chapter 11 bankruptcy petitions in the United States Bankruptcy Court for the Northern District of Texas. As of June 30, 2003, the Company’s exposure to Mirant is subject to defenses, counterclaims, rights of setoff, recoupment and other mitigating factors, under an existing Master Power Purchase and Sale Agreement between the parties (the “Master Agreement”). Pursuant to an order entered by the bankruptcy court on July 15, 2003, Mirant has timely made all payments under the Master Agreement, on both pre- and post-petition obligations. The Company has also executed a post-petition assurance agreement with Mirant, covering continued performance of Mirant’s post-petition obligations on its contracts with Calpine. If Mirant’s motion for approval of the assumption of the Master Agreement is granted by the bankruptcy court, Mirant will be required to continue to timely pay all post-petition obligations under the Master Agreement. Additionally, the post-petition assurance agreement provides certain other protections to Calpine.

11. Earnings (Loss) per Share

Basic earnings (loss) per common share (“EPS”) 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 June 30,

	2003								2002

	Net			Weighted					Net		Weighted
	Income			Average					Income		Average
	(Loss)			Shares		EPS			(Loss)		Shares		EPS

THREE MONTHS:
Basic earnings (loss) per common share:
Income (loss) before discontinued operations	$	(14,818	)		381,219	$	(0.04	)	$	59,361		356,158	$	0.17
Discontinued operations, net of tax		(8,548	)		—		(0.02	)		8,960		—		0.02

Net income (loss)	$	(23,366	)		381,219	$	(0.06	)	$	68,321		356,158	$	0.19

Diluted earnings (loss) per common share:
Common shares issuable upon exercise of stock options using treasury stock method					—							9,448


	Periods Ended June 30,

	2003								2002

	Net			Weighted					Net		Weighted
	Income			Average					Income		Average
	(Loss)			Shares		EPS			(Loss)		Shares		EPS

Income (loss) before dilutive effect of certain convertible securities, discontinued operations and cumulative effect of a change in accounting principle	$	(14,818	)		381,219	$	(0.04	)	$	59,361		365,606	$	0.16
Dilutive effect of certain convertible securities		—			—		—			11,306		85,320		—
Income (loss) before discontinued operations and cumulative effect of a change in accounting principle		(14,818	)		381,219		(0.04	)		70,667		450,926		0.16
Discontinued operations, net of tax		(8,548	)		—		(0.02	)		8,960				0.02
Cumulative effect of a change in accounting principle, net of tax		—			—		—							—

Net income (loss)	$	(23,366	)		381,219	$	(0.06	)	$	79,627		450,926	$	0.18


	Periods Ended June 30,

	2003								2002

	Net			Weighted					Net			Weighted
	Income			Average					Income			Average
	(Loss)			Shares		EPS			(Loss)			Shares		EPS

SIX MONTHS:
Basic and diluted loss per common share:
Loss before discontinued operations and cumulative effect of a change in accounting principle	$	(65,767	)		381,089	$	(0.17	)	$	(18,291	)		331,745	$	(0.06	)
Discontinued operations, net of tax		(10,144	)				(0.03	)		10,939					0.04
Cumulative effect of a change in accounting principle, net of tax		529			—		—			—			—		—

Net loss	$	(75,382	)		381,089	$	(0.20	)	$	(7,352	)		331,745	$	(0.02	)

Because of the Company’s losses for the three months ended June 30, 2003, and the six months ended June 30, 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 118,701,972 and 148,183,384 shares of the Company’s common stock were not included in the computation of diluted shares outstanding during the six months ended June 30, 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 has enabled the Company to cancel up to 131 steam and gas turbines. The Company recorded a pre-tax charge of $207.4 million in the quarter ending December 31, 2002, in connection with fees paid to vendors to restructure these contracts. To date 39 of these turbines have been cancelled, leaving the disposition of 92 turbines still to be determined.

In July 2003 the Company completed a restructuring of its existing agreements for 20 gas and 2 steam turbines. The new agreement provides for later payment dates, which are in line with the Company’s construction program. The table below sets forth future turbine payments for construction and development projects, as well as for unassigned turbines. It includes previously delivered turbines, payments and delivery year for the remaining 10 turbines to be delivered as well as payment required for the potential cancellation costs of the remaining 92 gas and steam turbines. The table does not include payments that would result if the Company were to release for manufacturing any of these remaining 92 turbines.


Year	Total (in thousands)		Units To Be Delivered

2003	$	83,573		2
2004		158,673		8
2005		19,597		—

Total	$	261,843		10

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.

Securities Class Action Lawsuits. Since March 11, 2002, fourteen shareholder lawsuits have been filed against Calpine and certain of its officers in the United States District Court, Northern District of California. The actions captioned Weisz vs. Calpine Corp., et al., filed March 11, 2002, and Labyrinth Technologies, Inc. v. Calpine Corp., et al., filed March 28, 2002, are purported class actions on behalf of purchasers of Calpine stock between March 15, 2001 and December 13, 2001. Gustaferro v. Calpine Corp., filed April 18, 2002, is a purported class action on behalf of purchasers of Calpine stock between February 6, 2001 and December 13, 2001. The eleven other actions, captioned Local 144 Nursing Home Pension Fund vs. Calpine Corp., Lukowski vs. Calpine Corp., Hart vs. Calpine Corp., Atchison vs. Calpine Corp., Laborers Local 1298 v. Calpine Corp., Bell v. Calpine Corp., Nowicki v. Calpine Corp. Pallotta v. Calpine Corp., Knepell v. Calpine Corp., Staub v. Calpine Corp, and Rose v. Calpine Corp. were filed between March 18, 2002 and April 23, 2002. The complaints in these eleven actions are virtually identical – they are filed by three law firms, in conjunction with other law firms as co-counsel. All eleven lawsuits are purported class actions on behalf of purchasers of Calpine’s securities between January 5, 2001 and December 13, 2001.

The complaints in these fourteen actions allege that, during the purported class periods, certain Calpine executives issued false and misleading statements about Calpine’s financial condition in violation of Sections 10(b) and 20(1) of the Securities Exchange Act of 1934, as well as Rule 10b-5. These actions seek an unspecified amount of damages, in addition to other forms of relief.

In addition, a fifteenth securities class action, Ser v. Calpine, et al., was filed on May 13, 2002. The underlying allegations in the Ser action are substantially the same as those in the above-referenced actions. However, the Ser action is brought on behalf of a purported class of purchasers of Calpine’s 8.5% Senior Notes due February 15, 2011 (“2011 Notes”) and the alleged class period is October 15, 2001 through December 13, 2001. The Ser complaint alleges that, in violation of Sections 11 and 15 of the Securities Act of 1933, the Supplemental Prospectus for the 2011 Notes contained false and misleading statements regarding Calpine’s financial condition. This action names Calpine, certain of its officers and directors, and the underwriters of the 2011 Notes offering as defendants, and seeks an unspecified amount of damages, in addition to other forms of relief.

All fifteen of these securities class action lawsuits were consolidated in the U.S. District Court Northern District Court of California. The plaintiffs filed a first amended complaint in October 2002. The amended complaint does not include the 1933 Act complaints raised in the bondholders’ complaint, and the number of defendants named was reduced. On January 16, 2003, before our response was due to this amended complaint, the plaintiffs filed a further amended complaint. This further amended complaint added a few additional Calpine executives as defendants and addressed a few more issues. We filed a motion to dismiss this consolidated action in early April 2003. A hearing on this motion was scheduled for July 29, 2003. However, the court took the motions to dismiss and the plaintiffs’ motion in opposition under submission without a hearing. A ruling on these motions is expected in the fall. We consider the lawsuit to be without merit and we intend to defend vigorously against these allegations.

Hawaii Structural Ironworkers Pension Fund v. Calpine, et al. A securities class action, Hawaii Structural Ironworkers Pension Fund v. Calpine, et al., was filed on March 11, 2003, against Calpine, its directors and certain investment banks in 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 above. 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 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. The plaintiff has sought to have the action remanded to state court. As of the date of this periodic filing, we are awaiting the court’s ruling with respect to the motion to remand. The Company considers this lawsuit to be without merit and intends to defend vigorously against it.

Phelps v. Calpine Corporation, et al. On April 17, 2003, a participant in the Calpine Corporation Retirement Savings Plan (the “401(k) Plan”) filed a class action lawsuit in the Northern District Court of California. The underlying allegations in this action (“Phelps action”) are substantially the same as those in the securities class actions described above. However, the Phelps action is brought on behalf of a purported class of participants in the 401(k) Plan. The Phelps action alleges that various filings and statements made by Calpine during the class period were materially false and misleading, and that 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 also in the Northern District of California. Plaintiffs’ counsel is the same in both of these actions, and they have agreed to consolidate these two cases and to coordinate them with the consolidated federal securities class actions described above. The Company considers these lawsuits to be without merit and intends to vigorously defend against them.

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 and motions to stay this proceeding in favor of the federal securities class actions described above. In July 2003 the Court granted the motions to stay this proceeding in favor of the federal securities class actions. The Company considers this lawsuit to be without merit and intends to vigorously defend against it.

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 July 10, 2003, Howard Grobstein, the Trustee in the EonXchange bankruptcy, filed a complaint for avoidance against Calpine, seeking recovery of the $7 million (plus interest and costs) paid to Calpine in the March 29, 2002 Settlement Agreement. The complaint claims that the $7 million received by Calpine in the Settlement Agreement was transferred within 90 days of the filing of bankruptcy and therefore should be avoided and preserved for the benefit of the bankruptcy estate. Calpine believes that it has valid defenses to this claim and will vigorously defend against this complaint.

International Paper Company v. Androscoggin Energy LLC. In October 2000 International Paper Company (“IP”) filed a complaint in the Federal District Court for the Northern District of Illinois against Androscoggin Energy LLC (“AELLC”) alleging that AELLC breached certain contractual representations and warranties by failing to disclose facts surrounding the termination, effective May 8, 1998, of one of AELLC’s fixed-cost gas supply agreements. The Company had acquired a 32.3% interest in AELLC as part of the SkyGen transaction which closed in October 2000. AELLC filed a counterclaim against IP that has been referred to arbitration. AELLC may commence the arbitration counterclaim after discovery has progressed further. On November 7, 2002, the court issued an opinion on the parties’ cross motions for summary judgment finding in AELLC’s favor on certain matters though granting summary judgment to IP on the liability aspect of a particular claim against AELLC. The Court also denied a motion submitted by IP for preliminary injunction to permit IP to make payment of funds into escrow (not directly to AELLC) and require AELLC to post a significant bond. 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. On June 26, 2003, the court entered an order dismissing AELLC’s Amended Counterclaim without prejudice to AELLC refilling the claims as breach of contract claims in a separate lawsuit. On June 30, 2003, AELLC filed a motion to reconsider the order dismissing AELLC’s Amended Counterclaim. The Company believes it has adequately reserved for the possible loss, if any, it may ultimately incur as a result of this matter.

On July 22, 2003, Pacific Gas and Electric Company (“PG&E”) filed with the California Public Utilities Commission (“CPUC”) a Compliant of PG&E and Request for Immediate Issuance of an Order to Show Cause (“Complaint”) against Calpine Corporation, CPN Pipeline Company, Calpine Energy Services, L.P., Calpine Natural Gas Company, Lodi Gas Storage, LLC (“LGS”) and Doe Defendants 1-10. The complaint requests the CPUC to issue an order requiring the defendants to show cause why they should not be ordered to cease and desist from using any direct interconnections between the facilities of CPN Pipeline and those of LGS unless LGS and Calpine first seek and obtain regulatory approval from the CPUC. The Complaint also seeks an order directing defendants to pay to PG&E any underpayments of PG&E’s tariffed transportation rates and to make restitution for any profits earned from any business activity related to LGS’ direct interconnections to any entity other than PG&E. The Complaint also alleges that various natural gas consumers, including Company-affiliated generation projects within California, are engaged with defendants in the acts complained of, and that the defendants unlawfully bypass PG&E’s system and operate as an unregulated local distribution company within PG&E’s service territory. The Company believes this Complaint to be without merit and intends to vigorously defend its position at the CPUC. The Company is contractually obligated to indemnify LGS for certain damages it may suffer as a result of the Complaint.

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 produce at a level of approximately 25% of its fuel consumption requirements from its own natural gas reserves (“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 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 June 30,
	Revenue from external customers	$	2,153,382	$	1,769,413	$	23,323	$	(9,120	)	$	9,351		$	(1,921	)	$	2,186,056		$	1,758,372
	Intersegment Revenue		—		—		102,495		52,313			—			—			102,495			52,313
	Segment profit (loss)		3,381		140,968		25,901		1,553			(47,981	)		(55,393	)		(18,699	)		87,128
	Equipment cancellation cost		19,222		14,200		—		—			—			—			19,222			14,200


		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 six months ended June 30,
	Revenue from external customers	$	4,309,852		$	3,042,973	$	49,436	$	45,721	$	11,282		$	386		$	4,370,570		$	3,089,080
	Intersegment Revenue		—			—		227,708		69,954		—			—			227,708			69,954
	Segment profit (loss)		(44,052	)		74,412		69,519		2,996		(111,667	)		(110,500	)		(86,200	)		(33,092	)
	Equipment cancellation cost		19,309			182,671		—		—		—						19,309			182,671


		Electric		Oil and Gas		Corporate, Other
		Generation		Production		and
		and Marketing		and Marketing		Eliminations		Total

		(In thousands)
Total assets:
	June 30, 2003	$	23,780,506	$	1,703,952	$	532,884	$	26,017,342
	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 eliminated in the oil and gas production and marketing segment revenue, but have been included in the segment’s measure of income before taxes.

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. Calpine believes that it did not violate these tariffs and that, to the extent that such a finding could be made, any potential liability would not be material. On June 25, 2003, FERC rejected various complaints to invalidate certain long-term energy supply.

Also, on June 25, 2003, FERC issued a number of orders associated with these investigations, including the issuance of two show cause orders to certain industry participants. FERC did not subject Calpine to either of the show cause orders. FERC also issued an order directing the FERC Office of Markets and Investigations to investigate further whether market participants who bid a price in excess of $250 per megawatt hour into markets operated by either the CAISO or the CalPX during the period of May 1, 2000, to October 2, 2000, may have violated CAISO and CalPX tariff prohibitions. No individual market participant was identified. The Company believes that it did not violate the CAISO and CalPX tariff prohibitions referred to by FERC in this order; however, we are unable to predict at this time the final outcome of this proceeding or its impact on Calpine.

15. Subsequent Events

On July 10, 2003, the Company renegotiated its financing agreement with Siemens Westinghouse Power Corporation to extend the monthly payment due dates through January 28, 2005. At June 30, 2003, there was $214.8 million in borrowings outstanding under this agreement. The Company repaid $35.6 million of the outstanding balance in July 2003.

On July 16, 2003, the Company closed its $3.3 billion term loan and second-priority senior secured notes offering. The term loan and senior notes are secured by substantially all of the assets owned directly by Calpine Corporation, including natural gas and power plant assets and the stock of Calpine Energy Services and other subsidiaries. The offering was comprised of two tranches of floating rate securities and two tranches of fixed rate securities. The floating rate securities included a $750 million, four-year term loan priced at LIBOR plus 575 basis points and $500 million of Second-Priority Senior Secured Floating Rate Notes due 2007 also priced at LIBOR plus 575 basis points. The fixed rate securities included $1.15 billion of 8.5% Second Priority Senior Secured Notes due 2010, and $900 million of 8.75% Second Priority Senior Secured Notes due 2013.

On July 16, 2003, the Company entered into agreements for a new $500 million working capital facility. The new first-priority senior secured facility will consist of a two-year, $300 million working capital revolver and a four-year, $200 million term loan that together will provide up to $500 million in combined cash borrowing and letter of credit capacity. The new facility replaces the Company’s existing working capital facilities. It will be secured by a first-priority lien on the same assets that collateralize the Company’s recently completed $3.3 billion term loan and second-priority senior secured notes offering.

On July 24, 2003, the Company announced that Gilroy Energy Center, LLC (“GEC”), a wholly owned, stand-alone subsidiary of the Calpine subsidiary GEC Holdings, LLC, intends to sell, under Rule 144A, approximately $270 million of Senior Secured Notes Due 2011. The senior secured notes will be secured by GEC’s and its subsidiaries’ 11 peaking units, located at nine power generating sites in northern California. The notes will also be secured by a long-term power sales agreement for 495 megawatts of peaking capacity with the State of California Department of Water Resources, which is being served by the 11 peaking units. The noteholders’ recourse will be limited to the assets of GEC and its subsidiaries. Calpine will not provide a guarantee of the Senior Secured Notes Due 2011 or any other form of credit support.

In connection with this offering, GEC is negotiating with a third party on a preferred equity investment in GEC, totaling approximately $74 million, which the Company does not expect to complete by the closing of the Senior Secured Notes Due 2011. Therefore, the net proceeds of the senior notes offering will be held in an escrow account, pending completion of this preferred equity investment. If the preferred equity investment is not completed, GEC will offer to repurchase the Senior Secured Notes Due 2011 at a price of 101%, plus accrued interest.

Debt securities repurchased by the Company subsequent to June 30, 2003, were approximately $1,185.7 million in aggregate outstanding aggregate outstanding principal amount at a redemption price of approximately $987.5 million plus accrued interest to the redemption dates. The Company expects to record a pre-tax gain on these transactions in the amount of $184.0 million, net of write-offs of unamortized deferred financing costs and the associated unamortized premiums or discounts associated with the issuance of these Senior Notes. Repurchases in 2003 prior to June 30, 2003, are discussed in Note 5. The following table summarizes the total debt securities repurchased by the Company from July 1, 2003, through August 8, 2003 (in millions):


	Principal		Redemption
Debt Security	Amount		Amount

Convertible Senior Notes Due 2006	$	112.0	$	100.5
8-1/4% Senior Notes Due 2005		25.0		24.5
10-1/2% Senior Notes Due 2006		5.2		5.1
7-5/8% Senior Notes Due 2006		35.3		32.5
8-3/4% Senior Notes Due 2007		48.9		45.0
7-7/8% Senior Notes Due 2008		52.4		41.1
8-1/2% Senior Notes Due 2008		48.3		42.3
8-3/8% Senior Notes Due 2008		56.2		44.5
7-3/4% Senior Notes Due 2009		77.0		61.1
8-5/8% Senior Notes Due 2010		159.9		133.9
8-1/2% Senior Notes Due 2011		437.6		361.1
8-7/8% Senior Notes Due 2011		127.9		95.8

	$	1,185.7	$	987.5

On August 4, 2003, the Company announced plans to sell its unconsolidated, 50-percent interest in the 240-MW Gordonsville Power Plant to Dominion Virginia Power, an affiliate of Dominion. Under the terms of the transaction, the Company will receive a $31.5 million cash payment, which includes a $26 million payment from Dominion and a separate $5.5 million payment from the

project for return of a debt service reserve. The Company’s 50-percent share of the project’s non-recourse debt at closing was approximately $44 million. The company expects to complete the transaction in the fourth quarter of 2003, pending regulatory and other third-party approvals.

On August 7, 2003, the Company’s wholly owned subsidiary, Calpine Construction Finance Company, L.P. (“CCFC I”), priced its $750 million institutional term loans and secured notes offering. The offering includes $385 million of First Priority Secured Institutional Term Loans Due 2009 offered at 99% of par and priced at LIBOR plus 600 basis points, with a LIBOR floor of 150 basis points and $365 million of Second Priority Senior Secured Floating Rate Notes Due 2011 offered at 98.01% of par and priced at LIBOR plus 850 basis points, with a LIBOR floor of 125 basis points. The noteholders’ recourse will be limited to seven of CCFC’s natural gas-fired electric generating facilities located in various power markets in the United States, and related assets and contracts. The transaction is expected to close on August 14, 2003. In anticipation of the financing, S&P assigned a B corporate credit rating to CCFC I. S&P also assigned a B+ rating (with a negative outlook) to the First Priority Secured Institutional Term Loans Due 2009 and a B- rating (with a negative outlook) to the Second Priority Secured Floating Rate Notes Due 2011. Net proceeds will be used to refinance the majority of the amount currently outstanding under the CCFCI project financing. The remainder of the facility will be repaid from cash proceeds from the $3.3 billion term loan and second-priority senior secured notes offering.

Enron Corporation, and a number of its subsidiaries and affiliates (including Enron North America (“ENA”) and Enron Power Marketing (“EPM”))(collectively “Enron Bankrupt Entities”) filed for Chapter 11 bankruptcy protection on December 2, 2001. At the time of the filing, CES was a party to various open energy derivatives, swaps, and forward power and gas transactions stemming from agreements with ENA and EPM. On November 14, 2001, CES, ENA, and EPM entered into a Master Netting Agreement, which granted the parties a contractual right to setoff amounts owed between them pursuant to the above agreements. The above agreements were terminated by CES on December 10, 2001. The Master Netting Agreement however remained in place. In October 2002, Calpine and various affiliates filed proofs of claim against the Enron Bankrupt Entities.

Final settlement of this matter has been reached with Enron and was approved by the bankruptcy court on August 7, 2003, subject to a 10-day appeal period, expiring on August 18, 2003. The Company will provide information on the terms of the settlement at that time and does not expect any adverse consequences to its financial results or operations as a result of settling this matter.

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, and the impact of related derivatives transactions, (iii) unscheduled outages of operating plants, (iv) unseasonable weather patterns that produce reduced demand for power, (v) systemic economic slowdowns, which can adversely affect consumption of power by businesses and consumers, (vi) 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 project financing on acceptable terms, (vii) cost estimates are preliminary and actual costs may be higher than estimated, (viii) a competitor’s development of lower-cost power plants or of a lower cost means of operating a fleet of 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) our estimates of oil and gas reserves many not be accurate, (xii) the effects on the Company’s business resulting from reduced liquidity in the trading and power industry, (xiii) the Company’s ability to access the capital markets on attractive terms or at all, (xiv) sources and uses of cash are estimates based on current expectations; actual sources may be lower and actual uses may be higher than estimated, (xv) 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, (xvi) possible future claims, litigation and enforcement actions pertaining to the foregoing or (xvii) other risks as identified herein. Current information set forth in this filing has been updated to August 8, 2003, and Calpine undertakes no duty to update this information. All other information in this filing is presented as of the specific date noted and has not been updated since that time. 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 and second 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 capacity revenues, which are not related to production, and variable energy payments, which are related to production. Capacity revenues include, 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				Six Months Ended
		June 30,				June 30,

		2003		2002		2003		2002

				Restated (1)				Restated (1)
		(In thousands, except
		production and pricing data)
Power Plants:
Electricity and steam (“E&S”) revenues:
	Energy	$	730,298	$	544,660	$	1,560,655	$	1,058,896
	Capacity		224,650		120,422		385,280		196,901
	Thermal and other		117,688		42,230		248,739		73,915

	Subtotal	$	1,072,636	$	707,312	$	2,194,674	$	1,329,712
Spread on sales of purchased power (2)			6,086		167,278		7,421		258,094

Adjusted E&S revenues (non-GAAP)		$	1,078,722	$	874,590	$	2,202,095	$	1,587,806
Megawatt hours produced			17,909,325		15,681,706		37,331,224		30,390,521
All-in electricity price per megawatt hour generated		$	60.23	$	55.77	$	58.99	$	52.25

(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 and six months ended June 30, 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						Six Months Ended
	June 30,						June 30,

	2003			2002			2003			2002

				Restated (1)						Restated (1)
Total revenue	$	2,186,056		$	1,758,372		$	4,370,570		$	3,089,080
Sales of purchased power		744,805			718,157			1,426,089			1,238,208
As a percentage of total revenue		34.1	%		40.8	%		32.6	%		40.1	%
Sale of purchased gas		328,478			309,352			655,946			432,756
As a percentage of total revenue		15	%		17.6	%		15.0	%		14.0	%
Total cost of revenue (“COR”)		2,000,425			1,511,025			4,011,239			2,661,485
Purchased power expense		738,719			550,879			1,418,668			980,114
As a percentage of total COR		36.9	%		36.5	%		35.4	%		36.8	%
Purchased gas expense		331,122			331,392			648,070			452,753
As a percentage of total COR		16.6	%		21.9	%		16.2	%		17.0	%

(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 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. The table below details the financial extent of our transactions with NEPOOL for the period indicated.


		Three Months Ended				Six Months Ended
		June 30,				June 30,

		2003		2002		2003		2002

				Restated (1)				Restated (1)
		(In thousands)
Sales to NEPOOL from power we generated		$	75,642	$	63,455	$	152,540	$	114,036
Sales to NEPOOL from hedging and other activity			22,952		20,148		105,963		44,805

	Total sales to NEPOOL	$	98,594	$	83,603	$	258,503	$	158,841
	Total purchases from NEPOOL	$	76,697	$	85,344	$	210,865	$	161,178

(1)

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

Results of Operations

Three Months Ended June 30, 2003, Compared to Three Months Ended June 30, 2002 (in millions, except for unit pricing information, MW volumes and percentage data).


	Three Months Ended
	June 30,

	2003		2002		$ Change		% Change

			Restated (1)
Total revenue	$	2,186.1	$	1,758.4	$	427.7		24.3	%

The increase in total revenue is explained by category below.


		Three Months Ended
		June 30,

		2003		2002		$ Change		% Change

				Restated (1)
Electricity and steam revenue		$	1,072.6	$	707.3	$	365.3		51.6	%
Sales of purchased power for hedging and optimization			744.8		718.2		26.6		3.7	%

	Total electric generation and marketing revenue	$	1,817.4	$	1,425.5	$	391.9		27.5	%

Electricity and steam revenue increased as we completed construction and brought into operation 5 new baseload power plants, 2 new peaker facilities and 3 expansion projects completed subsequent to June 30, 2002. Average megawatts in operation of our consolidated plants increased by 55% to 19,455 MW while generation increased by 14%. The increase in generation lagged behind the increase in average MW in operation as our baseload capacity factor dropped to 49% in the three months ended June 30, 2003, from 66% in the three months ended June 30, 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 $44.99/MWh in 2002 to $59.89/MWh in 2003.

Sales of purchased power for hedging and optimization increased in the three months ended June 30, 2003, due primarily to higher electricity pricing in 2003.


		Three Months Ended
		June 30,

		2003		2002		$ Change		% Change

				Restated (1)
Oil and gas sales		$	29.5	$	16.1	$	13.4		83.2	%
Sales of purchased gas for hedging and optimization			328.5		309.4		19.1		6.2	%

	Total oil and gas production and marketing revenue	$	358.0	$	325.5	$	32.5		10.0	%

Oil and gas sales are net of internal consumption, which is eliminated in consolidation. Internal consumption increased by $50.2 to $102.5 in 2003. Before intercompany eliminations, oil and gas sales increased by $63.6 to $132.0 in 2003 from $68.4 in 2002 due primarily to 81% 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, and due to a higher price environment.


		Three Months Ended
		June 30,

		2003			2002		$ Change			% Change

					Restated (1)
Realized revenue on power and gas trading transactions, net		$	9.0		$	2.2	$	6.8			309.1	%
Unrealized mark-to-market gain (loss) on power and gas transactions, net			(7.2	)		2.0		(9.2	)		(460.0	)%

	Total trading revenue, net	$	1.8		$	4.2	$	(2.4	)		(57.1	)%

Total trading revenue, which is shown on a net basis, results from general market price movements against our open commodity positions accounted for as trading under EITF Issue No. 02-3, “Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (“EITF Issue No. 02-3”). These commodity positions represent a small portion of our overall commodity contract position. Realized revenue represents the portion of contracts actually settled, while unrealized revenue represents changes in the fair value of open contracts, the ineffective portion of cash flow hedges, and the effects of settling previously open positions.


	Three Months Ended
	June 30,

	2003		2002		$ Change		% Change

			Restated (1)
Other revenue	$	8.8	$	3.2	$	5.6		175.0	%

Other revenue increased during the three months ended June 30, 2003, primarily due to a $7.0 revenue contribution from Thomassen Turbine Systems (“TTS”), which we acquired in February 2003. This was partially offset by a decline in third party revenue recorded by Power Systems Mfg. LLC (“PSM”), our subsidiary that designs and manufactures certain spare parts for gas turbines, as more of PSM’s activity was related to intercompany orders with our power generation segment.


	Three Months Ended
	June 30,

	2003		2002		$ Change		% Change

			Restated (1)
Cost of revenue	$	2,000.4	$	1,511.0	$	489.4		32.4	%

The increase in total cost of revenue is explained by category below.


		Three Months Ended
		June 30,

		2003		2002		$ Change		% Change

				Restated (1)
Plant operating expense		$	164.4	$	118.4	$	46.0		38.9	%
Royalty expense			6.5		4.2		2.3		54.8	%
Purchased power expense for hedging and optimization			738.7		550.9		187.8		34.1	%

	Total electric generation and marketing expense	$	909.6	$	673.5	$	236.1		35.1	%

Plant operating expense increased due to 5 new baseload power plants, 2 new peaker facilities and 3 expansion projects completed subsequent to June 30, 2002. This was partially offset by reducing reserves by $10.3 for generator and turbine combustor equipment repairs, based on reaching an agreement with a vendor relating thereto.

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
		June 30,

		2003		2002		$ Change		% Change

				Restated (1)
Oil and gas production expense		$	22.6	$	21.2	$	1.4		6.6	%
Oil and gas exploration expense			6.5		1.6		4.9		306.3	%

	Oil and gas operating expense		29.1		22.8		6.3		27.6	%


	Three Months Ended
	June 30,

	2003		2002		$ Change			% Change

			Restated (1)
Purchased gas expense for hedging and optimization		331.1		331.4		(0.3	)		(0.1	)%

Total oil and gas operating and marketing expense	$	360.2	$	354.2	$	6.0			1.7	%

Oil and gas production expense increased primarily as a result of an increase in the Canadian foreign exchange rate.

Oil and gas exploration expense increased primarily as a result of expensing $4.3 of dry hole drilling costs during the three months ended June 30, 2003.


	Three Months Ended
	June 30,

	2003		2002		$ Change		% Change

			Restated (1)
Fuel expense	$	555.4	$	350.3	$	205.1		58.5	%

Fuel expense increased for the three months ended June 30, 2003, due to a 15% increase in gas-fired megawatt hours generated and 42% higher gas prices excluding the effects of hedging, balancing and optimization. This was partially offset by increased usage of internally produced gas, which is eliminated in consolidation, and a 3% improved average heat rate for our generation portfolio in 2003.


	Three Months Ended
	June 30,

	2003		2002		$ Change		% Change

			Restated (1)
Depreciation, depletion and amortization expense	$	140.2	$	103.7	$	36.5		35.2	%

Depreciation, depletion and amortization expense increased primarily due to the additional power facilities in consolidated operations subsequent to June 30, 2002.


	Three Months Ended
	June 30,

	2003		2002		$ Change		% Change

			Restated (1)
Other expense	$	6.9	$	1.1	$	5.8		527.3	%

The increase is primarily due to $4.8 of TTS expense. TTS was acquired in February 2003.


	Three Months Ended
	June 30,

	2003			2002		$ Change			% Change

				Restated (1)
Loss (income) from unconsolidated investments in power projects	$	(59.4	)	$	1.1	$	(60.5	)		(5500	)%

The increase in income is due primarily to a $52.8 gain recognized on the termination of the tolling arrangement with Aquila Merchant Services, Inc.

(“AMS”) on the Acadia Energy Center (see Note 6 of the Notes to Consolidated Condensed Financial Statements) and due to $5.6 in earnings generated by this facility. The Aries Power project contributed $1.6 in earnings during the second quarter of 2003. These two projects were not operational in the second quarter of 2002.


	Three Months Ended
	June 30,

	2003		2002		$ Change		% Change

			Restated (1)
Equipment cancellation and impairment cost	$	19.2	$	14.2	$	5.0		35.2	%

The pre-tax equipment cancellation and impairment charge in the three months ended June 30, 2003, was primarily a result of a loss of $17.2 in connection with the sale of two turbines and also commitment cancellation costs and storage and suspension costs for unassigned equipment. The 2002 charge of $14.2 was due to turbine impairment write-downs.


	Three Months Ended
	June 30,

	2003		2002		$ Change			% Change

			Restated (1)
Project development expense	$	6.1	$	10.5	$	(4.4	)		(41.9	)%

Project development expense decreased as we placed certain existing development projects on hold and scaled back new development activity. Additionally, impairment write-offs of capitalized project costs decreased to $3.4 in the three months ended June 30, 2003, from $5.7 in the prior year period.


	Three Months Ended
	June 30,

	2003		2002		$ Change		% Change

			Restated (1)
General and administrative expense	$	63.8	$	52.4	$	11.4		21.8	%

General and administrative expense increased due primarily to $3.9 of stock-based compensation expense associated with the Company’s adoption of Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 123, “Accounting for Stock-Based Compensation” (“SFAS No, 123”) effective January 1, 2003, on a prospective basis and due to higher outside consulting expense, and higher cash-based employee compensation costs.


	Three Months Ended
	June 30,

	2003		2002		$ Change		% Change

			Restated (1)
Interest expense	$	148.9	$	79.1	$	69.8		88.2	%

Interest expense increased primarily due to the new plants entering commercial operations (at which point capitalization of interest expense ceases). Interest capitalized decreased from $171.0 for the three months ended June 30, 2002, to $116.5 for the three months ended June 30, 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 increase in average indebtedness and an increase in the amortization of terminated interest rate swaps.


	Three Months Ended
	June 30,

	2003		2002		$ Change		% Change

			Restated (1)
Minority interest expense	$	5.3	$	0.7	$	4.6		657.1	%

The increase is primarily due to $4.5 associated with the Canadian Power Income Fund and $1.7 related to the King City Power Plant in which we sold a preferred interest on April 29, 2003. See Note 5 of the Notes to Consolidated Condensed Financial Statements for more information.


	Three Months Ended
	June 30,

	2003		2002			$ Change		% Change

			Restated (1)
Other expense (income)	$	13.7	$	(3.7	)	$	17.4		470.3	%

The other expense in the three months ended June 30, 2003, is comprised primarily of foreign exchange translation losses of $19.1 due to the strong Canadian dollar and letter of credit fees of $3.2. These losses were offset by a gain of $6.8 recorded in connection with the redemption of Senior Notes at a discount. In 2002 we recorded $7.0 of recovery from Automated Credit Exchange for losses incurred on reclaim trading credit transactions, and additionally, we recognized gains from asset sales of $7.6 million. These gains were partially offset by letter of credit fees of $6.2, foreign exchange translation losses of $2.0, and $3.6 for cost of a forfeited deposit on an asset purchase that did not close in 2002.


	Three Months Ended
	June 30,

	2003			2002		$ Change			% Change

				Restated (1)
Provision (benefit) for income taxes	$	(3.9	)	$	27.8	$	(31.7	)		(114.0	)%

The provision (benefit) for income taxes increased primarily due to the decrease in income from continuing operations in 2003 compared to 2002 and from a reduction in the estimated annual effective tax rate for continuing operations from 32% to 21%. This effective rate variance is due to the inclusion of significant permanent items in the calculation of the effective rate, which are fixed in amount but have the effect of producing different overall effective rates when such items become more material to net income.


	Three Months Ended
	June 30,

	2003			2002		$ Change			% Change

				Restated (1)
Discontinued operations, net of tax	$	(8.5	)	$	9.0	$	(17.5	)		(194.4	)%

During the three months ended June 30, 2003, we decided to sell our specialty engineering unit, reflecting the soft market for data centers for the foreseeable future. The 2002 activity represents the results of our discontinued operations, which included the engineering unit, the DePere Energy Center and Drakes Bay Field, British Columbia and Medicine River oil and gas assets. With the exception of the engineering unit, the sales of these assets were completed by December 31, 2002, so their operations are not included in the 2003 activity.


	Three Months Ended
	June 30,

	2003			2002		$ Change			% Change

				Restated (1)
Net income (loss)	$	(23.4	)	$	68.3	$	(91.7	)		(134.3	)%

Our growing portfolio of operating generation facilities contributed to a 14% increase in electric generation production for the three months ended June 30, 2003, compared to the same period in 2002, allowing us to achieve approximately $2.2 billion of revenue for the second quarter of 2003, compared to approximately $1.8 billion for the second quarter of 2002. Electric generation and marketing revenues increased 27% for the three months ended June 30, 2003, as a result of this new production and as a result of hedging and optimization activity, compared with the same period in 2002. Operating results for the three months ended June 30, 2003, reflect an increase in realized electricity prices. However, we experienced a decrease in average spark spreads per megawatt-hour compared with the same period in 2002, reflecting proportionately higher fuel expense.

Plant operating expense, interest expense 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 period due to higher realized oil and gas pricing. In the second quarter of 2003, financial results were affected by a $17.2 loss in connection with the sale of two turbines. In addition, we recorded $19.1 in foreign exchange translation losses relating to intercompany transactions due mainly to a strong Canadian dollar in the quarter. We also recorded in income from unconsolidated investments, a $52.8 gain on the termination of the tolling arrangement on the Acadia facility and an $8.5 after-tax charge to discontinued operations as we decided to sell our specialty engineering unit. As a result of the above, gross profit for the three months ended June 30, 2003, decreased approximately 25%, respectively, compared to the same period in 2002.

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

Six Months Ended June 30, 2003, Compared to Six Months Ended June 30, 2002 (in millions, except for unit pricing information, MW volumes and percentage data).


	Six Months Ended
	June 30,

	2003		2002		$ Change		% Change

			Restated (1)
Total revenue	$	4,370.6	$	3,089.1	$	1,281.5		41.5	%

The increase in total revenue is explained by category below.


		Six Months Ended
		June 30,

		2003		2002		$ Change		% Change

				Restated (1)
Electricity and steam revenue		$	2,194.7	$	1,329.7	$	865.0		65.1	%
Sales of purchased power for hedging and optimization			1,426.1		1,238.2		187.9		15.2	%

	Total electric generation and marketing revenue	$	3,620.8	$	2,567.9	$	1,052.9		41.0	%

Electricity and steam revenue increased as we completed construction and brought into operation 5 new baseload power plants, 7 new peaker facilities and 3 expansion projects completed subsequent to June 30, 2002. Average megawatts in operation of our consolidated plants increased by 60% to 19,019 MW while generation increased by 23%. The increase in generation lagged behind the increase in average MW in operation as our baseload capacity factor dropped to 51% in the six months ended June 30, 2003 from 68% in the six months ended June 30, 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 $43.69/MWh in 2002 to $58.79/MWh in 2003.

Sales of purchased power for hedging and optimization increased in the six months ended June 30, 2003, due primarily to higher electricity pricing in 2003.


		Six Months Ended
		June 30,

		2003		2002		$ Change			% Change

				Restated (1)
Oil and gas sales		$	55.5	$	69.2	$	(13.7	)		(19.8	)%
Sales of purchased gas for hedging and optimization			655.9		432.8		223.1			51.5	%

	Total oil and gas production and marketing revenue	$	711.4	$	502.0	$	209.4			41.7	%

Oil and gas sales are net of internal consumption, which is eliminated in consolidation. Internal consumption increased by $157.8 to $227.7 in 2003. Before intercompany eliminations, oil and gas sales increased by $144.0 to $283.2 in 2003 from $139.2 in 2002 due primarily to 107% higher average realized natural gas pricing in 2003.


		Six Months Ended
		June 30,

		2003			2002		$ Change			% Change

					Restated (1)
Realized revenue on power and gas trading transactions, net		$	30.3		$	8.4	$	21.9			260.7	%
Unrealized mark-to-market gain (loss) on power and gas transactions, net			(8.0	)		4.8		(12.8	)		(266.7	)%

	Total trading revenue, net	$	22.3		$	13.2	$	9.1			68.9	%

Total trading revenue, which is shown on a net basis, results from general market price movements against our open commodity positions accounted for as trading under EITF Issue No. 02-3. These commodity positions represent a small portion of our overall commodity contract position. It 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, the ineffective portion of cash flow hedges, and the effects of settling previously open positions.


	Six Months Ended
	June 30,

	2003		2002		$ Change		% Change

			Restated (1)
Other revenue	$	16.1	$	6.0	$	10.1		168.3	%

Other revenue increased during the six months ended June 30, 2003, primarily due to $9.1 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 $3.2 in 2003.


	Six Months Ended
	June 30,

	2003		2002		$ Change		% Change

			Restated (1)
Cost of revenue	$	4,011.2	$	2,661.5	$	1,349.7		50.7	%

The increase in total cost of revenue is explained by category below.


		Six Months Ended
		June 30,

		2003		2002		$ Change		% Change

				Restated (1)
Plant operating expense		$	329.4	$	234.9	$	94.5		40.2	%
Royalty expense			11.8		8.4		3.4		40.5	%
Purchased power expense for hedging and optimization			1,418.7		980.1		438.6		44.8	%

	Total electric generation and marketing expense	$	1,759.9	$	1,223.4	$	536.5		43.9	%

Plant operating expense increased due to 5 new baseload power plants, 7 new peaker facilities and 3 expansion projects completed subsequent to June 30, 2002. In addition, during the six months ended June 30, 2003, we recorded reserves of $6.6 for generator and turbine combustor equipment repairs after reaching agreement with a vendor, which accepted responsibility for most of the total costs incurred.

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.


			Six Months Ended
			June 30,

			2003		2002		$ Change		% Change

					Restated (1)
Oil and gas production expense			$	45.9	$	39.5	$	6.4		16.2	%
Oil and gas exploration expense				8.9		4.9		4.0		81.6	%

	Oil and gas operating expense			54.8		44.4		10.4		23.4	%
Purchased gas expense for hedging and optimization				648.0		452.8		195.2		43.1	%

		Total oil and gas operating and marketing expense	$	702.8	$	497.2	$	205.6		41.4	%

Oil and gas production expense increased primarily due to higher production taxes, and treating and transportation costs which were primarily the result of higher oil and gas revenues and an increase in the Canadian foreign exchange rate in the six months ended June 30, 2003.

Oil and gas exploration expense increased primarily as a result of expensing $4.3 of dry hole drilling costs during the six months ended June 30, 2003.

Purchased gas expense for hedging and optimization increased in the six months ended June 30, 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.


	Six Months Ended
	June 30,

	2003		2002		$ Change		% Change

			Restated (1)
Fuel expense	$	1,205.6	$	682.8	$	522.8		76.6	%

Fuel expense increased for the six months ended June 30, 2003 due to a 25% increase in gas-fired megawatt hours generated and 54% higher gas prices excluding the effects of hedging, balancing and optimization, which was partially offset by increased usage of internally produced gas, which is eliminated in consolidation, and a 3% improved average heat rate for our generation portfolio in 2003.


	Six Months Ended
	June 30,

	2003		2002		$ Change		% Change

			Restated (1)
Depreciation, depletion and amortization expense	$	274.9	$	198.6	$	76.3		38.4	%

Depreciation, depletion and amortization expense increased primarily due to the additional power facilities in consolidated operations subsequent to June 30, 2002.


	Six Months Ended
	June 30,

	2003		2002		$ Change		% Change

			Restated (1)
Other expense	$	12.1	$	3.1	$	9.0		290.3	%

The increase is primarily due to $6.2 of TTS expense. TTS was acquired in February 2003.


	Six Months Ended
	June 30,

	2003			2002			$ Change			% Change

				Restated (1)
(Income) from unconsolidated investments in power projects	$	(64.5	)	$	(0.4	)	$	(64.1	)		16,025.0	%

The increase is primarily due to a $52.8 gain recognized on the termination of the tolling arrangement with AMS on the Acadia Energy Center (see Note 6 of the Notes to Consolidated Condensed Financial Statements) and due to $13.3 in earnings contributed by this facility. This facility was not operational in the six months ended June 30, 2002.


	Six Months Ended
	June 30,

	2003		2002		$ Change			% Change

			Restated (1)
Equipment cancellation and impairment charge	$	19.3	$	182.7	$	(163.4	)		(89.4	)%

In the six months ended June 30, 2002, the pre-tax equipment cancellation and impairment charge was primarily a result of a loss of $17.2 in connection with the sale of two turbines and also commitment cancellation costs and storage and suspension costs for unassigned equipment. The pre-tax equipment cancellation and impairment charge of $182.7 in the six months ended June 30, 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.


	Six Months Ended
	June 30,

	2003		2002		$ Change			% Change

			Restated (1)
Project development expense	$	11.2	$	21.9	$	(10.7	)		(48.9	)%

Project development expense decreased as we placed certain existing development projects on hold and scaled back new development activity. Additionally, impairment write-offs of capitalized project costs decreased to $3.4 in the six months ended June 30, 2003, from $6.2 in the prior year.


	Six Months Ended
	June 30,

	2003		2002		$ Change		% Change

			Restated (1)
General and administrative expense	$	117.5	$	110.2	$	7.3		6.6	%

The increase is due primarily to $8.4 of stock-based compensation expense associated with the Company’s adoption of SFAS No. 123 prospectively effective January 1, 2003.


	Six Months Ended
	June 30,

	2003		2002		$ Change		% Change

			Restated (1)
Interest expense	$	291.8	$	152.8	$	139.0		91.0	%

Interest expense increased primarily due to the new plants entering commercial operations (at which point capitalization of interest expense ceases). Interest capitalized decreased from $334.1 for the six months ended June 30, 2002, to $235.0 for the six months ended June 30, 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 increase in average indebtedness and an increase in the amortization of terminated interest rate swaps.


	Six Months Ended
	June 30,

	2003			2002			$ Change		% Change

				Restated (1)
Interest (income)	$	(17.0	)	$	(21.9	)	$	4.9		(22.4	)%

The decrease is primarily due to lower cash balances and lower interest rates in 2003.


	Six Months Ended
	June 30,

	2003		2002		$ Change		% Change

			Restated (1)
Minority interest expense	$	7.6	$	0.4	$	7.2		1,800	%

The increase is primarily due to $6.7 associated with the Canadian Power Income Fund.


	Six Months Ended
	June 30,

	2003		2002			$ Change		% Change

			Restated (1)
Other expense (income)	$	48.3	$	(16.3	)	$	64.6		(396.3	)%

The other expense in the six months ended June 30, 2003, is comprised primarily of $44.3 of foreign exchange translation losses, and $7.6 of letter of credit fees. The foreign exchange translation losses recognized into income were mainly due to a strong Canadian dollar in the six-month period. These losses were partially offset by a gain of $6.8 recorded in connection with the redemption of Senior Notes at a discount in 2003. In 2002 we recorded a $9.7 gain from the sale of our interest in the Lockport facility, $7.0 of recovery from Automated Credit Exchange for losses incurred on reclaim trading credit transactions, gains from asset sales of $9.1 million and a gain of $3.5 from the repurchase of our Zero-Coupon Convertible Debentures Due 2021 at a discount. These gains were partially offset by letter of credit fees of $6.2, foreign exchange translation losses of $2.2, and $3.6 for cost of a forfeited deposit on an asset purchase that did not close in 2002.


	Six Months Ended
	June 30,

	2003			2002			$ Change			% Change

				Restated (1)
Benefit for income taxes	$	(20.4	)	$	(14.8	)	$	(5.6	)		37.8	%

The benefit for income taxes increased primarily due to the decrease in income from continuing operations in 2003 compared to 2002 and from a reduction in the estimated annual effective tax rate for continuing operations from 45% to 24%. This effective rate is due to the inclusion of significant permanent items, which are fixed in amount but have the effect of producing different overall effective rates when such items become more material to net income.


	Six Months Ended
	June 30,

	2003			2002		$ Change			% Change

				Restated (1)
Discontinued operations, net of tax	$	(10.1	)	$	10.9	$	(21.0	)		(192.7	)%

During the six months ended June 30, 2003, we decided to sell our specialty engineering unit, reflecting the soft market for data centers for the foreseeable future. The 2002 discontinued operations activity included the engineering unit, the DePere Energy Center as well as the Drakes Bay Field, British Columbia and Medicine River oil and gas assets. With the exception of the engineering unit, the sales of these assets were completed by December 31, 2002; therefore, their results are not included in the 2003 activity.


	Six Months Ended
	June 30,

	2003		2002		$ Change		% Change

			Restated (1)
Cumulative effect of a change in accounting 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.”


	Six Months Ended
	June 30,

	2003			2002			$ Change			% Change

				Restated (1)
Net loss	$	(75.4	)	$	(7.4	)	$	(68.0	)		918.9	%

Our growing portfolio of operating generation facilities contributed to a 23% increase in electric generation production for the six months ended June 30, 2003, compared to the same period in 2002, allowing us to achieve approximately $4.4 billion of revenue for the six months ended June 30, 2003, compared to approximately $3.1 billion for the six months ended June 30, 2002. Electric generation and marketing revenues increased 41% for the six months ended June 30, 2003, as a result of this new production and as a result of hedging and optimization activity, compared with the same period in 2002. Operating results for the six months ended June 30, 2003, reflect an increase in realized electricity prices. However, we experienced a decrease in average spark spreads per megawatt-hour compared with the same period in 2002, reflecting proportionately higher fuel expense.

Plant operating expenses, interest expense 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 period due to higher realized oil and gas pricing. Financial results for the six months ended June 30, 2003, were affected by a $52.8 gain on the termination of the tolling arrangement on the Acadia facility, foreign exchange translation losses of $44.3 and a loss in connection with the sale of two turbines of $17.2. In addition, results were affected by a $10.1 after-tax charge to discontinued operations and unscheduled outages and charges, including reserves for equipment repairs of $6.6. As a result of the above, gross profit for the six months ended June 30, 2003, decreased approximately 16%, compared to the same period in 2002.

(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 2002 and 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 contraction has been due to a range of factors, including uncertainty arising from the collapse of Enron Corp. and a perceived near-term surplus supply of electric generating capacity. 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. Upon completion by Calpine Construction Finance Company, L.P. of the institutional term loan and secured note offering described below, we will have refinanced all of our debt facilities of significance coming due in 2003 and the first half of 2004. The obligations coming due in the second half of 2004 and our plan for refinancing or extending them are discussed below.

To date, we have obtained cash from our operations; borrowings under our term loan and revolving credit facilities; issuance of debt, equity, trust preferred securities and convertible debentures; proceeds from sale/ leaseback transactions, sale or partial sale of certain assets, contract monetizations and project financing. We have utilized this cash to fund our operations, service or prepay debt

obligations, fund acquisitions, develop and construct power generation facilities, finance capital expenditures, support our hedging, balancing, optimization and trading activities at CES, and meet our other cash and liquidity needs. Our 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.

In May and June 2003 our $950 million in secured working capital revolving credit facilities matured and were extended, ultimately to July 16, 2003. At June 30, 2003, we had $453.4 million in funded borrowings under these revolving credit facilities. On July 16, 2003, the Company closed a $3.3 billion term loan and second-priority senior secured notes offering and repaid the outstanding balance on the revolving credit facilities. We also repaid the $949.6 million in funded borrowings outstanding under our $1.0 billion secured term credit facility which was to mature in May 2004. Additionally, as indicated below, we have retired nearly $1.2 billion under various senior note issuances since June 30, 2003 with proceeds of the $3.3 billion term loan and second-priority senior secured notes offering.

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 June 30, 2003, there was $930.1 million and $2,390.3 million outstanding, respectively, under these facilities. On August 7, 2003, our Calpine Construction Finance Company, L.P. (“CCFC I”) subsidiary had priced $750 million of institutional term loans and secured notes in a transaction expected to close on August 14, 2003. The net proceeds of this offering will, together with proceeds from the $3.3 billion term loan and second-priority senior secured notes offering, be used to repay the outstanding balance on the $1.0 billion secured revolving construction financing facility.

We intend to refinance or extend the $2.5 billion secured revolving construction facility sometime in 2004, prior to its expiration in November 2004. Since this facility bears a very low interest rate, it is not economical to refinance it too far in advance of its expiration.

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.

The holders of our $1.2 billion 4% Convertible Senior Notes Due 2006 (“convertibles”) have a right to require us to repurchase them at 100% of their principal amount plus any accrued and unpaid interest on December 25, 2004. We can effect such a repurchase with cash, shares of Calpine stock or a combination of the two. To date we have repurchased in the open market approximately $112 million of the outstanding principal amount with proceeds of the $3.3 billion term loan and second-priority senior secured notes offering discussed above.

In addition, $268.7 million of our outstanding Remarketable Term Income Deferrable Equity Securities (“HIGH TIDES”) are scheduled to be remarketed no later than November 1, 2004, $351.6 million of our HIGH TIDES are scheduled to be remarketed no later than February 1, 2005 and $504.0 million of our HIGH TIDES are scheduled to be remarketed no later than August 1, 2005. In the event of a failed remarketing, the relevant HIGH TIDES will remain outstanding as convertible securities at a term rate equal to the treasury rate plus 6% per annum and with a term conversion price equal to 105% of the average closing price of our common stock for the five consecutive trading days after the applicable final failed remarketing termination date. While a failed remarketing of our HIGH TIDES would not have an effect on our liquidity position, it would impact our calculation of diluted earnings per share.

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.

Cash Flow Activities The following table summarizes our cash flow activities for the periods indicated:


	Six Months Ended
	June 30,

	2003		2002

			Restated (1)

	(In thousands)
Beginning cash and cash equivalents	$	579,467	$	1,594,144


		Six Months Ended
		June 30,

		2003			2002

					Restated (1)

		(In thousands)
Net cash provided by (used in):
	Operating activities		113,304			432,595
	Investing activities		(1,297,803	)		(2,551,434	)
	Financing activities		1,017,314			1,116,524
	Effect of exchange rates changes on cash and cash equivalents		5,672			3,958

	Net increase (decrease) in cash and cash equivalents		(161,513	)		(998,357	)

Ending cash and cash equivalents		$	417,954		$	595,787

(1)

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

Operating activities for the six months ended June 30, 2003, provided net cash of $113.3 million, compared to $432.6 million for the same period in 2002. The decrease in operating cash flow between periods is primarily due to the working capital funding requirements. During the six months ended June 30, 2003, working capital used approximately $375.2 million, as compared to $86.6 million in the same period last year. The growth in short term assets such as margin deposits and accounts receivable accounted for the majority of this difference, which is the result of hedging activities, the overall growth in our revenues, and the timing of receivables collections. For example, 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 augmented operating cash flow in 2002 when compared to 2003. Excluding the effects of working capital reflected as “Changes in operating assets and liabilities, net of effects of acquisitions,” our operating cash flow decreased by approximately $30.7 million. Although average spark spreads were lower in 2003 than in 2002, increased electrical generation resulted in higher revenues, and subsequently, higher receivables balances. Similarly, natural gas price increases benefited our oil and gas operating results on similar production. Additionally, in 2003, we received $105.5 million from the restructuring of our interest in our Acadia joint venture. See Note 6 of the Notes to Consolidated Condensed Financial Statements for further discussion.

Investing activities for the six months ended June 30, 2003, consumed net cash of $1,297.8 million, as compared to $2,551.4 million 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 reduces capital investments.

Financing activities for the six months ended June 30, 2003, provided $1,017.3 million, compared to $1,116.5 million in the prior year. Current year cash inflows are primarily the result of several financing transactions, including $802.2 million from the Power Contract Financing, L.L.C. (“PCF”) financing transaction, $126.5 million from secondary trust unit offerings from our Canadian Income Trust, $82.8 million from the monetization of one of our power sales agreements, $82.0 million from the sale of a preferred interest in the cash flows of our King City facility and additional borrowings under our revolvers. This was partially offset by financing costs and $175.4 million in debt repayments and repurchases. We expect that the significant financing transactions will allow us to continue to retire short term debt and will also enable us to make further repurchases of other long term securities. In the same period of 2002, financing inflows were comprised of $751.2 million from the issuance of common stock, and $1,457.7 million in debt financing, partially offset by the use of $873.2 million used to repay our Zero Coupon Convertible Debentures Due 2021, in addition to other repayments of project financing.

Counterparties — As of June 30, 2003, we had collection exposures after established reserves from certain of our counterparties as follows: approximately $9.0 million with NRG Power Marketing, Inc. (“NRG”); approximately $9.7 million with Aquila Merchant Services, Inc. and Aquila; approximately $22.2 million with Williams and approximately $0.9 million with Mirant. 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. See Note 10 of the Notes to Consolidated Condensed Financial Statements for more information.

Enron Corporation, and a number of its subsidiaries and affiliates (including Enron North America (“ENA”) and Enron Power Marketing (“EPM”) (collectively “Enron Bankrupt Entities”) filed for Chapter 11 bankruptcy protection on December 2, 2001. At the time of the filing, CES was a party to various open energy derivatives, swaps, and forward power and gas transactions stemming from agreements with ENA and EPM. On November 14, 2001, CES, ENA, and EPM entered into a Master Netting Agreement, which granted the parties a contractual right to setoff amounts owed between them pursuant to the above agreements. The above agreements were terminated by CES on December 10, 2001. The Master Netting Agreement however remained in place. In October 2002 Calpine and various affiliates filed proofs of claim against the Enron Bankrupt Entities.

Final settlement of this matter has been reached with Enron and was approved by the bankruptcy court on August 7, 2003, subject to a 10-day appeal period, which expires on August 18, 2003. We will provide information on the terms of the settlement at that time and we do not expect any adverse consequences to our financial results or operations as a result of settling this matter.

We have a $160.6 million note receivable from Pacific Gas and Electric Company (“PG&E”) and are receiving our monthly note repayments of approximately $1.7 million as scheduled per the contract, as well as current payments on our trade receivables. See Note 10 of the Notes to Consolidated Financial Statements in our 2002 Form 10-K for more information on our contract activity with PG&E.

Letter of Credit Facilities — At June 30, 2003 and December 31, 2002, we had approximately $548.7 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, $436.5 million and $573.9 million, respectively, were issued under the corporate revolving credit facilities at June 30, 2003 and December 31, 2002.

CES Margin Deposits and Other Credit Support — As of June 30, 2003 and December 31, 2002, CES had deposited net amounts of $171.7 million and $25.2 million, respectively, in cash as margin deposits with third parties and had letters of credit outstanding of $18.6 million and $106.1 million, respectively. CES uses these margin deposits and letters of credit as credit support for the gas procurement as well as risk management activities it conducts on the Company’s behalf. 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.

Contractual Obligations — Our contractual obligations as of June 30, 2003, are as follows (in thousands):


		July
		Through
		December
Contractual Obligations		2003		2004		2005		2006		2007		Thereafter		Total

Notes payable and borrowings under lines of credit and term loan (1)		$	8,343	$	138,517	$	175,011	$	179,505	$	134,291	$	257,998	$	893,665
Notes payable and borrowings under lines of credit and term loan (2)			453,402		949,565		—		—		—		—		1,402,967
Capital lease obligation (1)			2,938		3,687		4,406		5,468		5,980		177,859		200,338
Construction/project financing (1)			1,305,628		2,413,970		19,192		22,202		34,152		657,184		4,452,328
Convertible Senior Notes Due 2006 (2)			—		—		—		1,200,000		—		—		1,200,000
Senior Notes (2)			—		—		249,531		421,646		421,920		5,827,117		6,920,214
Total operating lease			141,466		226,914		209,909		196,069		193,491		1,927,825		2,895,674
Turbine commitments			83,573		158,673		19,597		—		—		—		261,843
HIGH TIDES			—		—		—		—		—		1,153,500		1,153,500

	Total	$	1,995,350	$	3,891,326	$	677,646	$	2,024,890	$	789,834	$	10,001,483	$	19,380,529

(1)		Structured as an obligation(s) of certain subsidiaries of Calpine Corporation without recourse to Calpine Corporation. However, default on these instruments could potentially trigger cross-default provisions in the Company’s recourse financings.

(2)		An obligation of or with recourse to Calpine Corporation.

As of June 30, 2003, $930.1 outstanding under our $1.0 billion construction revolving credit facility, $453.4 outstanding under our working capital revolving credit facility and $949.6 million outstanding under our term facility were classified as long-term debt in the consolidated condensed balance sheet as we have since replaced (or will imminently replace) the debt with other long-term debt instruments, as disclosed in Note 15 of the Notes to Consolidated Condensed Financial Statements. Comparable reclassifications were made to the accompanying consolidated condensed balance sheet as of December 31, 2002. The above table reflects the maturity dates of the debt instruments prior to refinancing.

In June 2003 we repurchased Pound Sterling 14.0 million (US$23.3 million) in aggregate outstanding principal amount of our 8 7/8% Senior Notes Due 2011 at a redemption price of Pound Sterling 9.7 million (US$16.1 million) plus accrued interest to the redemption date. We recorded a pre-tax gain on these transactions in the amount of $6.8 million.

The table below sets forth our contractual obligations, giving effect to the refinancing transactions and debt repurchases subsequent to June 30, 2003, as described above:


		July
		Through
		December
Contractual Obligations		2003		2004		2005		2006		2007		Thereafter		Total

Notes payable and borrowings under lines of credit and term loan (1)		$	8,343	$	138,517	$	175,011	$	179,505	$	134,291	$	257,998	$	893,665
Notes payable and borrowings under lines of credit and term loan (2)			2,375		9,500		9,500		9,500		919,125		—		950,000
Capital lease obligation (1)			2,938		3,687		4,406		5,468		5,980		177,859		200,338
Construction/project financing (1)			325,518		2,417,820		23,042		26,052		38,002		1,391,784		4,222,218
Convertible Senior Notes Due 2006 (2)			—		—		—		1,087,996		—		—		1,087,996
Senior Notes (2)			—		—		224,484		381,134		373,032		4,866,017		5,844,667
Second Secured Senior Notes (2)			—		—		—		—		500,000		2,050,000		2,550,000
Total operating lease			141,466		226,914		209,909		196,069		193,491		1,927,825		2,895,674
Turbine commitments			83,573		158,673		19,597		—		—		—		261,843
HIGH TIDES			—		—		—		—		—		1,153,500		1,153,500

	Total	$	564,213	$	2,955,111	$	665,949	$	1,885,724	$	2,163,921	$	11,824,983	$	20,059,901

(1)		Structured as an obligation(s) of certain subsidiaries of Calpine Corporation without recourse to Calpine Corporation. However, default on these instruments could potentially trigger cross-default provisions in our recourse financings.

(2)		An obligation of or with recourse to Calpine Corporation.

Debt securities that we repurchased subsequent to June 30, 2003, were approximately $1,185.7 million in aggregate outstanding principal amount at a redemption price of approximately $987.5 million plus accrued interest to the redemption dates. We expect to record a pre-tax gain on these transactions in the amount of $184.0 million in the third quarter of 2003. For a summary of our debt securities repurchased through August 8, 2003, see Note 15 of the Notes to Consolidated Condensed Financial Statements.

Our senior notes indentures 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 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.

In July 2003 we completed a restructuring of our agreements for 20 gas and 2 steam turbines. The new agreement provides for later payment dates, which are in line with our construction program. The table above sets forth future turbine payments for construction and development projects, as well as for unassigned turbines. It includes previously delivered turbines, payments and delivery year for the remaining 10 turbines to be delivered as well as payment required for the potential cancellation costs of the remaining 92 gas and steam turbines. The table above does not include payments that would result if we were to release for manufacturing any of these remaining 92 turbines.

On July 10, 2003, we renegotiated our financing agreement with Siemens Westinghouse Power Corporation to extend the monthly payment due dates through January 28, 2005. At June 30, 2003, there was $214.8 million in borrowings outstanding under this agreement. We repaid $35.6 million of the outstanding balance in July 2003.

One of our wholly-owned subsidiaries, South Point Energy Center, LLC, leases the 530-MW South Point power facility located in Arizona, pursuant to certain facility lease agreements. We have recently become aware that a technical default has occurred under such facility lease agreements as a result of an inadvertent pledge of the ownership interests in such subsidiary granted pursuant to certain separate loan facilities entered into by us. We are currently working with the lenders of such loan facilities to release the inadvertent pledge. The South Point facility lease was entered into as part of a larger transaction, which also involved the lease by two of our other subsidiaries of the following two power facilities: the 850-MW Broad River power facility located in South Carolina, and the 520-MW RockGen power facility located in Wisconsin. As all three lease transactions were part of the same overall transaction, the facility lease agreements for Broad River and RockGen contain cross-default provisions to the South Point facility lease agreements and, therefore, a technical default also exists under the Broad River and RockGen facility lease agreements. However, upon the anticipated release of the inadvertent South Point pledge, the default under the Broad River and RockGen facility lease agreements will also be cured. We believe that this release will occur and the default will be cured and, therefore, will not have a material adverse effect on us.

One of our unconsolidated equity method investees, Androscoggin Energy LLC (“AELLC”), which owns the 160-megawatt Androscoggin Energy Center located in Maine, in which we own a 32.3% interest, has construction debt with $63 million outstanding as of June 30, 2003, that is non-recourse to Calpine Corporation (the “AELLC Non-Recourse Financing”). On June 30, 2003, our investment balance was $10.8 million and our notes receivable balance due from AELLC was $7.4 million. On August 8, 2003, AELLC received a letter from the lenders claiming that certain events of default have occurred under the credit agreement for the AELLC Non-Recourse Financing, including, among other things, that the project has been and remains in default under its debt agreement because the lending syndication has declined to extend the dates for the conversion of the construction loan by a certain date. AELLC is currently discussing with the banks a forbearance arrangement until an agreement is reached concerning the extension, conversion or repayment of the debt; however, the outcome is uncertain at this point. Also, the steam host for the AELLC project, International Paper Company (“IP”), filed a complaint against AELLC in October 2000, which is disclosed in Note 12 in the

Notes to Consolidated Condensed Financial Statements. IP’s complaint has been a complicating factor in converting the construction debt to long term financing.

Another of our unconsolidated 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 $195 million of debt as of June 30, 2003, that was due on June 26, 2003. Due to the default, the partners were required to contribute their proportionate share of $75 million in additional equity. During the quarter, we drew down $37.5 million under our working capital revolver to fund our equity contribution. The management of Aries is in negotiation with the lenders to extend the debt 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 $56.5 million investment in the Aries project and believe that the investment is not impaired.

Capital Spending — Development and Construction

Construction and development costs consisted of the following at June 30, 2003 (dollars in thousands):


						Equipment		Project
		# of				Included in		Development		Equipment for
		Projects		CIP		CIP		Costs		Future Use

Projects in active construction			13	$	3,888,748	$	1,470,038	$	—	$	—
Projects in advanced development			11		732,498		646,380		112,940		—
Projects in suspended development			6		598,014		326,577		12,767		—
Projects in early development			3		3,800		—		8,158		—
Other capital projects		NA			103,212		—		—		—
Unassigned turbines		NA			—		—		—		133,447

	Total construction and development costs			$	5,326,272	$	2,442,995	$	133,865	$	133,447

Projects in Active Construction — The 13 projects in active construction are estimated to come on line from November 2003 to June 2005. These projects will bring on line approximately 6,485 and 7,558 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 $1.1 billion. We plan to spend $0.5 billion, $0.5 billion and $0.1 billion in 2003, 2004 and 2005, respectively.

Projects in Advanced Development — There are 11 projects in advanced development. Of the total amount capitalized approximately $646.4 million relates to equipment, primarily turbine progress payments. These projects will bring on line approximately 6,011 and 7,209 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 $3.6 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 operations, the carrying values of the projects would be written down to the recoverable value. These projects would bring on line approximately 2,938 and 3,418 MW of base load and base load with peaking capacity, respectively. The estimated cost to complete these projects is approximately $1.5 billion. Of the amount capitalized approximately $326.6 million relates to equipment cost, primarily turbine progress payments.

Projects in Early Development — Costs for projects that are in early stages of development are capitalized only when it is highly probable that such costs are ultimately recoverable and significant project milestones are achieved. Until then, all costs, including interest costs are expensed. The projects in early development with capitalized costs relate to three projects and include geothermal drilling costs and equipment purchases.

Other Capital Projects — Other capital projects primarily consist of enhancements to operating power plants, oil and gas and geothermal resource and facilities development as well as software developed for internal use.

Unassigned Equipment — As of June 30, 2003, we had made progress payments on 7 turbines, 14 heat recovery steam generators, and other equipment with an aggregate carrying value of $110.4 million classified on the balance sheet as other assets, 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 have $23.1 million, net of impairment in other current assets relating to turbines that we consider held for sale. SFAS No. 144, “Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of” (“SFAS No. 144”) requires long-lived assets classified as held for sale to be written down to their fair market value, less disposal costs. During the quarter ended June 30, 2003, we recorded an impairment of $17.2 million on the turbines classified as held for sale. We review our other unassigned the equipment for potential impairment based on probability-weighted alternatives of utilizing it for future projects versus selling it. Utilizing this methodology, we do not believe that the equipment not committed to sale 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 and again in the first half of 2003 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 as well as our debt issuances have 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 company has completed or announced more than $1.6 billion of liquidity-enhancing transactions since the beginning of the year. Over the past few months Calpine has:

• Sold a preferred interest in a subsidiary that leases and operates the 115-megawatt King City Power Plant to GE Structured Finance for $82 million. The preferred interest holder will receive approximately 60% of future cash flow distributions based on current projection.

• Monetized one of its long-term power sales contracts with the California Department of Water Resources through an $802 million senior secured notes offering by Power Contract Financing, L.L.C. (“PCF”), a Calpine stand-alone subsidiary. As part of the PCF financing transaction, PCF issued two tranches of Senior Secured Notes totaling $802.2 million in aggregate. The two tranches of Senior Secured Notes have been rated Baa2 by Moody’s Investors Service, Inc. and BBB (with a negative outlook) by S&P.

• Received $105.5 million for a contract monetization and a restructuring of its 50-percent interest in a partnership that owns and operates the 1,160-megawatt Acadia Power Project in Louisiana.

• Completed an $82.8 million monetization of its 100-megawatt power sales agreement with the Bonneville Power Administration.

• Announced plans for its stand-alone subsidiary Gilroy Energy Center, LLC (GEC) to sell approximately $270 million of senior secured notes, net proceeds of which will be used to reimburse costs incurred in connection with Calpine’s 11 northern California peaking units. Calpine also announced negotiations for a $74 million third-party equity investment in GEC.

• Agreed to sell its unconsolidated, 50-percent interest in the 240-megawatt Gordonsville Power Plant. As a result of the transaction, Calpine will receive a $31.5 million cash payment, which includes a $5.5 million payment from the project for return of a debt service reserve.

• Announced that our CCFC I subsidiary had priced $750 million of institutional term loans and secured notes under a transaction expected to close on August 14, 2003. The offering includes $385 million of First Priority Secured Institutional Term Loans Due 2009 offered at 99% of par and priced at LIBOR plus 600 basis points, with a LIBOR floor of 150 basis points and $365 million of Second Priority Senior Secured Floating Rate Notes Due 2011 offered at 98.01% of par and priced at LIBOR plus 850 basis points, with a LIBOR floor of 125 basis points. In anticipation of the financing, S&P assigned a B corporate credit rating to CCFC I. S&P also assigned a B+ rating (with a negative outlook) to the First Priority Secured Institutional Term Loans Due 2009 and a B– rating (with a negative outlook) to the Second Priority Secured Floating Rate Notes Due 2011.

The company continues to make progress on the remaining liquidity transactions, including additional asset sales, the construction financing for the Riverside and Rocky Mountain projects and the receipt of the balance due from warrants issued as part of the Calpine Power Income Fund secondary offering. All of these transactions are scheduled to be completed during the second half of 2003.

Credit Considerations — On June 2, 2003, Standard & Poor’s (“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 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 baseload capacity factor or operating rate. Availability represents the percent of total hours during the period that our plants were available to run after taking into account the downtime associated with both scheduled and unscheduled outages. The baseload capacity factor, sometimes called operating rate, is calculated by dividing (a) total baseload megawatt hours generated by our power plants (excluding pure peaker facilities (“peakers”)) by the product of multiplying (b) the weighted average baseload megawatts in operation during the period by (c) the total hours in the period. The baseload capacity factor is thus a measure of total actual baseload generation as a percent of total potential baseload generation. If we elect not to generate during periods when electricity pricing is too low or gas prices too high to operate profitably, the baseload capacity factor will reflect that decision as well as both scheduled and unscheduled outages due to maintenance and repair requirements. Peakers are designed to operate infrequently, generally only during periods of high demand, and so are excluded from the calculation of baseload capacity factor.

• 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 intercompany “equity” gas from Calpine Natural Gas, which is eliminated in consolidation), and the spread on sales of purchased gas for hedging, balancing, and optimization activity by (b) the heat content in millions of Btu’s of the fuel we consumed in our power plants for the period.

• 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
				June 30,						June 30,

				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)		$	1,072,636		$	707,312		$	1,078,722		$	874,590
		Sales of purchased power for hedging and optimization (3)			744,805			718,157			—			—

	Total electric generation and marketing revenue				1,817,441			1,425,469			1,078,722			874,590
	Oil and gas production and marketing revenue
		Oil and gas production sales			29,490			16,128			29,490			16,128
		Sales of purchased gas for hedging and optimization (3)			328,478			309,352			—			—

	Total oil and gas production and marketing revenue				357,968			325,480			29,490			16,128
	Trading revenue, net
		Realized net revenue on power and gas trading, net			9,060			2,202			9,060			2,202
		Unrealized mark-to-market gain (loss) on power and gas transactions, net			(7,221	)		1,974			(7,221	)		1,974

	Total trading revenue, net				1,839			4,176			1,839			4,176
	Other revenue				8,808			3,247			8,808			3,247

			Total revenue		2,186,056			1,758,372			1,118,859			898,141

Cost of revenue:
	Electric generation and marketing expense
		Plant operating expense			164,448			118,415			164,448			118,415
		Royalty expense			6,461			4,194			6,461			4,194
		Purchased power expense (2)			738,719			550,879			—			—

	Total electric generation and marketing expense				909,628			673,488			170,909			122,609
	Oil and gas production and marketing expense
		Oil and gas production expense			29,082			22,788			29,082			22,788
		Purchased gas expense (2)			331,122			331,392			—			—

	Total oil and gas production and marketing expense				360,204			354,180			29,082			22,788
	Total fuel expense				555,368			350,298			558,012			372,338
	Depreciation, depletion and amortization expense				140,187			103,674			140,187			103,674
	Operating lease expense				28,168			28,239			28,168			28,239
	Other expense				6,870			1,146			6,870			1,146

			Total cost of revenue		2,000,425			1,511,025			933,228			650,794
		Gross profit		$	185,631		$	247,347		$	185,631		$	247,347

		Gross profit margin			8	%		14	%		17	%		28	%


			GAAP Presentation				Presentation
			Six Months Ended				Six Months Ended
			June 30,				June 30,

			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)	$	2,194,674	$	1,329,712	$	2,202,095	$	1,587,806
		Sales of purchased power for hedging and optimization (3)		1,426,089		1,238,208		—		—

	Total electric generation and marketing revenue			3,620,763		2,567,920		2,202,095		1,587,806
	Oil and gas production and marketing revenue
		Oil and gas production sales		55,479		69,204		55,479		69,204
		Sales of purchased gas for hedging and optimization (3)		655,946		432,756		—		—

	Total oil and gas production and marketing revenue			711,425		501,960		55,479		69,204
	Trading revenue, net
		Realized net revenue on power and gas trading, net		30,274		8,431		30,274		8,431


				GAAP Presentation						Presentation
				Six Months Ended						Six Months Ended
				June 30,						June 30,

				2003			2002			2003			2002

							Restated (1)
				(In thousands)
		Unrealized mark-to-market gain (loss) on power and gas transactions, net			(7,992	)		4,791			(7,992	)		4,791

	Total trading revenue, net				22,282			13,222			22,282			13,222
	Other revenue				16,100			5,978			16,100			5,978

			Total revenue		4,370,570			3,089,080			2,295,956			1,676,210

Cost of revenue:
	Electric generation and marketing expense
		Plant operating expense			329,428			234,889			329,428			234,889
		Royalty expense			11,818			8,349			11,818			8,349
		Purchased power expense (3)			1,418,668			980,114			—			—

	Total electric generation and marketing expense				1,759,914			1,223,352			341,246			243,238
	Oil and gas production and marketing expense
		Oil and gas production expense			54,773			44,427			54,773			44,427
		Purchased gas expense (3)			648,070			452,753			—			—

	Total oil and gas production and marketing expense				702,843			497,180			54,773			44,427
	Total fuel expense				1,205,604			682,832			1,197,728			702,829
	Depreciation, depletion and amortization expense				274,897			198,643			274,897			198,643
	Operating lease expense				55,860			56,380			55,860			56,380
	Other expense				12,121			3,098			12,121			3,098

			Total cost of revenue		4,011,239			2,661,485			1,936,625			1,248,615
		Gross profit		$	359,331		$	427,595		$	359,331		$	427,595

		Gross profit margin			8	%		14	%		16	%		26	%


		Non-GAAP Netted						Non-GAAP Netted
		Presentation						Presentation
		Three Months Ended						Six Months Ended
		June 30,						June 30,

		2003			2002			2003			2002

		(In thousands)
Other Non-GAAP Performance Metrics
Average availability and baseload capacity factor:
	Average availability		87	%		93	%		87	%		91	%
	Average baseload capacity factor:
	Average total MW in operation		19,455			12,557			19,019			11,877
	Less: Average MW of pure peakers		2,685			1,760			2,453			1,679
	Average baseload MW in operation		16,770			10,797			16,566			10,198
	Hours in the period		2,184			2,184			4,344			4,344
	Potential baseload generation		36,626			23,581			71,963			44,300
	Actual total generation		17,909			15,682			37,331			30,391
	Less: Actual pure peakers’ generation		140			217			311			283
	Actual baseload generation		17,769			15,465			37,020			30,108
	Average baseload capacity factor		49	%		66	%		51	%		68	%
Average heat rate for gas-fired power plants (excluding peakers) (Btu’s/kWh):
	Not steam adjusted		7,997			8,158			7,975			8,165
	Steam adjusted		7,232			7,455			7,230			7,416
Average all-in realized electric price:
	Adjusted electricity and steam revenue (in thousands)	$	1,078,722		$	874,590		$	2,202,095		$	1,587,806
	MWh generated (in thousands)		17,909			15,682			37,331			30,391
	Average all-in realized electric price per MWh	$	60.23		$	55.77		$	58.99		$	52.25
Average cost of natural gas:
	Cost of oil and natural gas burned by power plants (in thousands)	$	558,012		$	372,338		$	1,197,728		$	702,829
	Fuel cost elimination		96,461			52,313			206,795			69,954

	Adjusted fuel expense	$	654,473		$	424,651		$	1,404,523		$	772,783
	Million Btu’s (“MMBtu”) of fuel consumed by generating plants (in thousands)		125,209			112,153			250,534			218,617


			Non-GAAP Netted				Non-GAAP Netted
			Presentation				Presentation
			Three Months Ended				Six Months Ended
			June 30,				June 30,

			2003		2002		2003		2002

			(In thousands)
	Average cost of natural gas per MMBtu		$	5.23	$	3.79	$	5.61	$	3.53
	MWh generated (in thousands)			17,909		15,682		37,331		30,391
	Average cost of oil and natural gas burned by power plants per MWh		$	36.54	$	27.08	$	37.62	$	25.43
Equity gas contribution margin:
	Oil and gas production sales			29,490		16,128		55,479		69,204
	Add: Fuel cost eliminated in consolidation			96,461		52,313		206,795		69,954

		Subtotal		125,951		68,441		262,274		139,158
	Less: Oil and gas production expense			29,082		22,788		54,773		44,427
	Less: Depletion, depreciation and amortization			38,769		37,292		78,095		72,928

	Equity gas contribution margin			58,100		8,361		129,406		21,803
	MWh generated (in thousands)			17,909		15,682		37,331		30,391
	Equity gas contribution margin per MWh			3.24		0.53		3.47		0.72
Average spark spread:
	Adjusted electricity and steam revenue (in thousands)		$	1,078,722	$	874,590	$	2,202,095	$	1,587,806
	Less: Adjusted fuel expense (in thousands)		$	654,473	$	424,651	$	1,404,523	$	772,783

		Spark spread (in thousands)	$	424,249	$	449,939	$	797,572	$	815,023
	MWh generated (in thousands)			17,909		15,682		37,331		30,391
	Average spark spread per MWh		$	23.69	$	28.69	$	21.36	$	26.82
	Add: Equity gas contribution			58,100		8,361		129,406		21,803
	Spark spread with equity gas benefits (in thousands)			482,349		458,300		926,978		836,826
	Average spark spread with equity gas benefits per MWh			26.93		29.22		24.83		27.54

The non-GAAP presentation above also facilitates a look at the total “trading” activity impact on gross profit. For the three and six months ended June 30, 2003 and 2002, trading revenue, net consisted of (dollars in thousands):


		Three Months Ended						Six Months Ended
		June 30,						June 30,

		2003			2002			2003			2002

					Restated (1)						Restated (1)
ELECTRICITY
Realized gain (loss) Realized revenue on power trading transactions, net		$	9,826		$	819		$	24,662		$	976
Unrealized Unrealized mark-to-market gain (loss) on power transactions, net			(12,844	)		5,889			(17,751	)		10,056

	Total	$	(3,018	)	$	6,708		$	6,911		$	11,032

GAS
Realized gain (loss) Realized revenue on gas trading transactions, net		$	(766	)	$	1,383		$	5,612		$	7,455
Unrealized Unrealized mark-to-market gain (loss) on gas transactions, net			5,623			(3,915	)		9,759			(5,265	)

	Total	$	4,857		$	(2,532	)	$	15,371		$	2,190


	Three Months						Three Months
	Ended						Ended

	June 30,			Percent of			June 30,		Percent of
	2003			Gross Profit			2002		Gross Profit

							Restated (1)

Total trading activity gain (loss)	$	1,839			1	%	$	4,176		2	%
Realized gain	$	9,060			5	%	$	2,202		1	%
Unrealized (mark-to-market) gains (loss)(2)	$	(7,221	)		(4	)%	$	1,974		1	%


	Six Months						Six Months
	Ended						Ended

	June 30,			Percent of			June 30,		Percent of
	2003			Gross Profit			2002		Gross Profit

							Restated (1)

Total trading activity gain (loss)	$	22,282			6	%	$	13,222		3	%
Realized gain	$	30,274			8	%	$	8,431		2	%
Unrealized (mark-to-market) gains (loss)(2)	$	(7,992	)		(2	)%	$	4,791		1	%

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

(2)		For the three and six months ended June 30, 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 June 30, 2003
Electricity and steam revenue	$	1,072,636	$	6,086		$	1,078,722
Sales of purchased power		744,805		(744,805	)		—
Sales of purchased gas		328,478		(328,478	)		—
Purchased power expense		738,719		(738,719	)		—
Purchased gas expense		331,122		(331,122	)		—
Fuel expense		555,368		2,644			558,012
Three months ended June 30, 2002, Restated (1)
Electricity and steam revenue	$	707,312	$	167,278		$	874,590
Sales of purchased power		718,157		(718,157	)		—
Sales of purchased gas		309,352		(309,352	)		—
Purchased power expense		550,879		(550,879	)		—
Purchased gas expense		331,392		(331,392	)		—
Fuel expense		350,298		22,040			372,338


			To Net
			Hedging,
			Balancing &			Netted
	GAAP		Optimization			Non-GAAP
	Balance		Activity			Balance

Six months ended June 30, 2003
Electricity and steam revenue	$	2,194,674	$	7,421		$	2,202,095
Sales of purchased power		1,426,089		(1,426,089	)		—
Sales of purchased gas		655,946		(655,946	)		—
Purchased power expense		1,418,668		(1,418,668	)		—
Purchased gas expense		648,070		(648,070	)		—
Fuel expense		1,205,604		(7,876	)		1,197,728
Six months ended June 30, 2002, Restated (1)
Electricity and steam revenue	$	1,329,712	$	258,094		$	1,587,806
Sales of purchased power		1,238,208		(1,238,208	)		—
Sales of purchased gas		432,756		(432,756	)		—
Purchased power expense		980,114		(980,114	)		—
Purchased gas expense		452,753		(452,753	)		—
Fuel expense		682,832		19,997			702,829

(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

4/03	Blue Spruce Energy Center	Commercial Operation
4/03	Calgary Energy Centre	Commercial Operation
5/03	Riverview Energy Center	Commercial Operation
6/03	Carville Energy Center	Commercial Operation
6/03	Santa Rosa Energy Center	Commercial Operation
6/03	Oneta Energy Center, Phase II	Commercial Operation
6/03	Deer Park Energy Center, Phases I and IA	Commercial Operation
6/03	Decatur Energy Center, Phase II	Commercial Operation
6/03	Morgan Energy Center, Units 2 and 3	Commercial Operation
6/03	Zion Energy Center Expansion, Unit 3	Commercial Operation

Finance


Date	Amount	Description

6/03	$802 million	Power Contract Financing, L.L.C., 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 Rule 144A.
6/03	Pound Sterling 14.0 million (US$23.3 million)	We repurchased Pound Sterling 14.0 million (US$23.3 million) in aggregate outstanding principal amount of our 8 7/8% Senior Notes Due 2011 at a redemption price of Pound Sterling 9.7 million (US$16.1 million) plus accrued interest to the redemption date. We recorded a pre-tax gain on these transactions in the amount of $6.8 million.

Other:


Date		Description

April 29,2003		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.
May 12, 2003		Completed the contract monetization and a restructuring of our interest in Acadia, a 50/50 joint venture between us and Cleco. See Note 6 of the Notes to Consolidated Condensed Financial Statements for additional information regarding this monetization.
May 15, 2003		Our wholly owned subsidiary, Calpine Northbrook Energy Marketing, LLC, completed the $82.8 million monetization of an existing power sales agreement with the Bonneville Power Administration.
June 2, 2003		Standard & Poor’s downgraded our corporate credit rating to B from BB.

California Power Market — See Note 14 of the Notes to Consolidated Condensed Financial Statements regarding the California Power Market.

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 June 30, 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)		(85,890	)
Changes in fair value attributable to changes in valuation techniques and assumptions		—
Changes in fair value attributable to new contracts		3,351
Changes in fair value attributable to price movements		105,852
Terminated derivatives (2)		(55,120	)
Other changes in fair value		482

Fair value of contracts outstanding at June 30, 2003 (3)	$	119,302

(1)		Recognized gains from commodity cash flow hedges of $55.6 million (represents realized value of cash flow hedge activity of $(23.4) million as disclosed in Note 8 of the Notes to Consolidated Condensed Financial Statements, net of terminated derivatives of $(79.0) million) and $30.3 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

The fair value of outstanding derivative commodity instruments at June 30, 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	$	131,974		$	52,853		$	—	$	—		$	184,827
Prices provided by other external sources		(33,745	)		1,679			14,765		—			(17,301	)
Prices based on models and other valuation methods		—			(7,094	)		7,441		(48,571	)		(48,224	)

Total fair value	$	98,229		$	47,438		$	22,206	$	(48,571	)	$	119,302

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 June 30, 2003, and the period during which the instruments will mature are summarized in the table below (in thousands):


Credit Quality
(based on June 30, 2003, ratings)	2003			2004-2005			2006-2007			After 2007			Total

Investment grade	$	63,578		$	7,088		$	16,334		$	(56,974	)	$	30,026
Non-investment grade		41,907			45,010			6,512			8,403			101,832
No external ratings		(7,256	)		(4,660	)		(640	)		—			(12,556	)

Total fair value	$	98,229		$	47,438		$	22,206		$	(48,571	)	$	119,302

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 June 30, 2003:
	Crude oil		$	(1,649	)	$	(2,077	)
	Electricity			(85,872	)		(205,245	)
	Natural gas			206,823			93,892

		Total	$	119,302		$	(113,430	)

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 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 20% from December 31, 2002, to June 30, 2003, and the total volume of open power derivative positions increased 21% for the same period. In that prices for electricity and natural gas are among the most volatile of all commodity prices, there may be material changes in the fair value of our derivatives over time, driven both by price volatility and the changes in volume of open derivative transactions. Under SFAS No. 133, the change since the last balance sheet date in the total value of the derivatives (both assets and liabilities) is reflected either in Other Comprehensive Income (“OCI”), net of tax, or in the statement of operations as an item (gain or loss) of current earnings. As of June 30, 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 six months ended June 30, 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 $82.4 million at June 30, 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 June 30, 2003, (dollars in thousands):


		Weighted
		Average
		Interest Rate			2003		2004		2005		2006		2007		Thereafter		Total

Corporate Debt Securities			7.3	%	$	—	$	6,050	$	7,825	$	—	$	—	$	—	$	13,875
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				$	2,065	$	6,050	$	9,800	$	9,700	$	9,100	$	96,150	$	132,865


		Fair Market Value

Corporate Debt Securities		$	14,806
U.S. Treasury Notes			2,189
U.S. Treasury Securities (non-interest bearing)			86,251

	Total	$	103,246

Interest Rate Swaps and Cross Currency Swaps — From time to time, we use interest rate swap agreements to mitigate our exposure to interest rate fluctuations associated with certain of our debt instruments. We do not use interest rate swap agreements for speculative or trading purposes. The following tables summarize the fair market values of our existing interest rate swap agreements as of June 30, 2003, (dollars in thousands):


		Weighted Average		Weighted Average
		Notional		Interest Rate
Maturity Date		Principal Amount		(Pay)			Interest Rate (Receive)			Fair Market Value

2008		$	106,294		4.2	%		(1	)	$	(7,026	)
2011			45,338		6.9	%	3-month US$ LIBOR				(8,037	)
2012			113,526		6.5	%	3-month US$ LIBOR				(21,359	)
2014			63,451		6.7	%	3-month US$ LIBOR				(10,870	)

	Total	$	328,609		5.9	%				$	(47,292	)

(1)

1-month US$ LIBOR until July 2003. 3-month US$ LIBOR thereafter.

Debt financing — Because of the significant capital requirements within our industry, debt financing is often needed to fund our growth. Certain debt instruments may affect us adversely because of changes in market conditions. We have used two primary forms of debt which are subject to market risk: (1) Variable rate construction/project financing; (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.

The following table summarizes our variable-rate debt exposed to interest rate risk as of June 30, 2003 (dollars in thousands):


			Outstanding		Weighted Average	Fair Market
			Balance		Interest Rate	Value

Variable-rate construction/project financing and other variable-rate instruments:
Short-term
	Siemens Westinghouse Power Corporation		$	214,781	6-month US$LIBOR	$	214,781

		Total short-term	$	214,781		$	214,781

Long-term
	Blue Spruce Energy Center Project financing		$	97,715	1-month US$ LIBOR	$	97,715
	Calpine Construction Finance Company L.P. (“CCFC I”)			930,110	1-month US$ LIBOR		930,110
	Corporate revolving line of credit			453,402	1-month US$ LIBOR		453,402
	Term loan due			949,565	3-month US$ LIBOR		949,565
	Calpine Construction Finance Company II, LLC (“CCFC II”)			2,390,270	1-month US$ LIBOR		2,390,270

		Total long-term	$	4,821,062		$	4,821,062

Total variable-rate construction/project financing and other variable-rate instruments			$	5,035,843		$	5,035,843

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. On August 7, 2003, our wholly owned subsidiary, Calpine Construction Finance Company, L.P. (“CCFC I”), priced its $750 million institutional term loans and secured notes offering. The offering includes $385 million of First Priority Secured Institutional Term Loans Due 2009 offered at 99% of par and priced at LIBOR plus 600 basis points, with a LIBOR floor of 150 basis points and $365 million of Second Priority Senior Secured Floating Rate Notes Due 2011 offered at 98.01% of par and priced at LIBOR plus 850 basis

points, with a LIBOR floor of 125 basis points. In anticipation of the financing, S&P assigned a B corporate credit rating to CCFCI. S&P also assigned a B+ rating (with a negative outlook) to the First Priority Secured Institutional Term Loans Due 2009 and a B- ratios (with a negative outlook) to the Second Priority Secured Floating Rate Notes Due 2011. The noteholders’ recourse will be limited to seven of CCFC’s natural gas-fired electric generating facilities located in various power markets in the United States, and related assets and contracts. The transaction is expected to close on August 14, 2003. Net proceeds will be used to refinance the majority of the amount currently outstanding under the CCFCI project financing. The remainder of the facility will be repaid from proceeds from the $3.3 billion term loan and second-priority senior secured notes offering.

Revolving credit and term loan facilities — At June 30, 2003, we had $949.6 million in funded borrowings outstanding under the term loan, which matures in May 2004. Additionally we had $453.4 million in funded borrowings outstanding and $436.5 million in outstanding letters of credit under the revolving credit facilities, of which $148.4 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. On July 16, 2003, we closed our $3.3 billion term loan and second-priority senior secured notes offering. The term loan and senior notes are secured by substantially all of the assets owned directly by Calpine Corporation, including natural gas and power plant assets and the stock of Calpine Energy Services and other subsidiaries. The offering was comprised of two tranches of floating rate securities and two tranches of fixed rate securities. The floating rate securities included a $750 million, four-year term loan and a $500 million of Second-Priority Senior Secured Floating Rate Notes due 2007. The fixed rate securities included $1.15 billion of 8.5% Second Priority Senior Secured Notes due 2010 and $900 million of 8.75% Second Priority Senior Secured Notes due 2013. 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.

Concurrent with the $3.3 billion term loan and second-priority senior secured notes offering, on July 16, 2003, we entered into agreements for a new $500 million working capital facility. The new first-priority senior secured facility will consist of a two-year, $300 million working capital revolver and a four-year, $200 million term loan that together will provide up to $500 million in combined cash borrowing and letter of credit capacity. The new facility replaces our existing working capital facilities. It will be secured by a first-priority lien on the same assets that collateralize our recently completed $3.3 billion term loan and second-priority senior secured notes offering.

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 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, 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 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 relative to VIEs created after January 31, 2003. One possible consequence of FIN 46 is that certain investments accounted for under the equity method might have to be consolidated. However, based on our preliminary assessment, and subject to further analysis, we do not think that FIN 46 will require any of our pre-February 1, 2003 equity method investments to be consolidated.

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.

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. However, we believe that adoption of SFAS No. 150 might require us to reclassify our $1.1 billion trust preferred securities (“HIGH TIDES”) which are shown on the balance sheet as “Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts,” as debt. Similarly, we may be required to reclassify some portion of our $422 million of “Minority interests” on the balance sheet as debt. These reclassifications would not affect net income or total stockholders equity but would impact our debt-to-equity and debt-to-capitalization ratios.

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 contracts currently identified as being subject to DIG Issue No. C20 and market prices as of August 4, 2003, we estimate that we will recognize net derivative assets between $237 million and $356 million, and cumulative effect adjustment to net income between $147 million and $221 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 as of the end of the period covered by 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 information we are required to disclose in reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms. There was no change in our internal control over financial reporting that occurred during the period covered by this Quarterly Report on Form 10-Q that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. The certificates required by this item are filed as a Exhibit 31 to this Form 10-Q.

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.

International Paper Company v. Androscoggin Energy LLC. In October 2000 International Paper Company (“IP”) filed a complaint in the Federal District Court for the Northern District of Illinois against Androscoggin Energy LLC (“AELLC”) alleging that AELLC breached certain contractual representations and warranties by failing to disclose facts surrounding the termination, effective May 8, 1998, of one of AELLC’s fixed-cost gas supply agreements. The Company had acquired a 32.3% interest in AELLC as part of the SkyGen transaction which closed in October 2000. AELLC filed a counterclaim against IP that has been referred to arbitration. AELLC may commence the arbitration counterclaim after discovery has progressed further. On November 7, 2002, the Court issued an opinion on the parties’ cross motions for summary judgment finding in AELLC’s favor on certain matters though granting summary judgment to IP on the liability aspect of a particular claim against AELLC. The Court also denied a motion submitted by IP for preliminary injunction to permit IP to make payment of funds into escrow (not directly to AELLC) and require AELLC to post a significant bond. 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.

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. On June 26, 2003, the court entered an order dismissing AELLC’s Amended Counterclaim without prejudice to AELLC refilling the claims as breach of contract claims in separate lawsuit. On June 30, 2003, AELLC filed a motion to reconsider the order dismissing AELLC’s Amended Counterclaim. The Company believes it has adequately reserved for the possible loss, if any, it may ultimately incur as a result of this matter.

Pacific Gas and Electric Company v. Calpine Corporation, et. al.

On July 22, 2003, Pacific Gas and Electric Company (“PG&E”) filed with the California Public Utilities Commission (“CPUC”) a Complaint of PG&E and Request for Immediate Issuance of an Order to Show Cause (“Complaint”) against Calpine Corporation, CPN Pipeline Company, Calpine Energy Services, L.P., Calpine Natural Gas Company, Lodi Gas Storage, LLC (“LGS”) and Doe Defendants 1-10. The complaint requests the CPUC to issue an order requiring the defendants to show cause why they should not be ordered to cease and desist from using any direct interconnections between the facilities of CPN Pipeline and those of LGS unless LGS and Calpine first seek and obtain regulatory approval from the CPUC. The Complaint also seeks an order directing defendants to pay to PG&E any underpayments of PG&E’s tariffed transportation rates and to make restitution for any profits earned from any business activity related to LGS’ direct interconnections to any entity other than PG&E. The Complaint also alleges that various natural gas consumers, including Company-affiliated generation projects within California, are engaged with defendants in the acts complained of, and that the defendants unlawfully bypass PG&E’s system and operate as an unregulated local distribution company within PG&E’s service territory. The Company believes this Complaint to be without merit and intends to vigorously defend its position at the CPUC. The Company is contractually obligated to indemnify LGS for certain damages it may suffer as a result of the Complaint.

Item 4. Submission of Matters to a Vote of Security Holders

Our Annual Meeting of Stockholders was held on May 28, 2003 (the “Annual Meeting”), in Aptos, California. At the Annual Meeting, the stockholders voted on the following matters: (i) the proposal to elect three Class I Directors to the Board of Directors for a term of three years expiring in 2006, (ii) two stockholder proposals regarding (a) the Company’s stockholder rights plan and (b) the classified status of the Board of Directors, and (iii) the proposal to ratify the appointment of PricewaterhouseCoopers LLP as independent accountants for the Company for the fiscal year ending December 31, 2003. The stockholders elected management’s nominees as the Class I Directors in an uncontested election, approved the stockholder proposal requesting that the Board of Directors redeem the stockholders right plan unless such plan is approved by a majority vote of the stockholders to be held as soon as may be practicable, approved the stockholder proposal that the Board of Directors take the necessary steps to declassify the Board of Directors for the purpose of establishing elections for directors, and ratified the appointment of independent accountants by the following votes, respectively:

(i) Election of Jeffrey E. Garten as Class I Director for a three-year term expiring 2006: 342,194,260 FOR and 12,394,554 ABSTAIN;

Election of George J. Stathakis as Class I Director for a three-year term expiring 2006: 342,503,334 FOR and 12,085,480 ABSTAIN;

Election of John O. Wilson as Class I Director for a three-year term expiring 2006: 342,299,478 FOR and 12,289,337 ABSTAIN;

(ii) Proposal that the Board of Directors be requested to redeem the stockholders right plan unless such plan is approved by a majority vote of the stockholders to be held as soon as may be practicable: 114,024,314 FOR, 52,519,839 AGAINST, 5,427,930 ABSTAIN, and 182,616,732 Broker non-votes;

(iii) Proposal that the Board of Directors take the necessary steps to declassify the Board of Directors for the purpose of establishing elections for directors: 107,998,279 FOR, 58,400,060 AGAINST, 5,573,744 ABSTAIN, and 182,616,732 Broker non-votes.

(iv) Ratification of the appointment of PricewaterhouseCoopers LLP as independent accountants for the fiscal year ending December 31, 2003: 345,740,875 FOR, 5,993,176 AGAINST, and 2,854,762 ABSTAIN.

The three-year terms of Class II and Class III Directors continued after the Annual Meeting and will expire in 2004 and 2005, respectively. The Class II Directors are Ann B. Curtis, Kenneth T. Derr and Gerald Greenwald. The Class III Directors are Susan C. Schwab and Peter Cartwright.

Item 6. Exhibits and Reports on Form 8-K.

(a) Exhibits

The following exhibits are filed herewith unless otherwise indicated:

EXHIBIT INDEX


Exhibit
Number		Description

*3.1		Amended and Restated Certificate of Incorporation of Calpine Corporation (a)
*3.2		Certificate of Correction of Calpine Corporation (b)
*3.3		Certificate of Amendment of Amended and Restated Certificate of Incorporation of Calpine Corporation (c)
*3.4		Certificate of Designation of Series A Participating Preferred Stock of Calpine Corporation (b)
*3.5		Amended Certificate of Designation of Series A Participating Preferred Stock of Calpine Corporation (b)
*3.6		Amended Certificate of Designation of Series A Participating Preferred Stock of Calpine Corporation (c)
*3.7		Certificate of Designation of Special Voting Preferred Stock of Calpine Corporation (d)
*3.8		Certificate of Ownership and Merger Merging Calpine Natural Gas GP, Inc. into Calpine Corporation (e)
*3.9		Certificate of Ownership and Merger Merging Calpine Natural Gas Company into Calpine Corporation (e)
*3.10		Amended and Restated By-laws of Calpine Corporation (f)
+4.1		Indenture dated as of July 16, 2003, between Calpine Corporation and Wilmington Trust Company, as Trustee, including form of Notes
+4.2		Indenture dated as of July 16, 2003, between Calpine Corporation and Wilmington Trust Company, as Trustee, including form of Notes
+4.3		Indenture dated as of July 16, 2003, between Calpine Corporation and Wilmington Trust Company, as Trustee, including form of Notes
+4.4		Indenture dated as of June 13, 2003, between Power Contract Financing, L.L.C. and Wilmington Trust Company, as Trustee, Accounts Agent, Paying Agent and Registrar, including form of Notes
*10.1		Second Amended and Restated Credit Agreement (“Second Amended and Restated Credit Agreement”) dated as of May 23, 2000, among Calpine Corporation, 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 Calpine Corporation, 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 Calpine Corporation, 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 Calpine Corporation, 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 Calpine Corporation, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein (h)
*10.6		Fifth Amendment to Second Amended and Restated Credit Agreement, dated as of March 12, 2003, among Calpine Corporation, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein (i)
*10.7		Sixth Amendment to Second Amended and Restated Credit Agreement, dated as of May 23, 2003, among Calpine Corporation, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein (j)
*10.8		Seventh Amendment to Second Amended and Restated Credit Agreement, dated as of June 16, 2003, among Calpine Corporation, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein (j)
*10.9		Credit Agreement, dated as of March 8, 2002, among Calpine Corporation, 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 Calpine Corporation, 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 (k)
*10.12		Second Amendment to Credit Agreement, dated as of May 23, 2003, among Calpine Corporation, The Bank of Nova Scotia, as Joint Administrative Agent and Funding Agent, Citicorp USA, Inc., as Joint Administrative Agent, and the Lenders named therein (j)
*10.13		Third Amendment to Credit Agreement, dated as of June 16, 2003, among Calpine Corporation, The Bank of Nova Scotia, as Joint Administrative Agent and Funding Agent, Citicorp USA, Inc., as Joint Administrative Agent, and the Lenders named therein (j)

CTB Comments — Exhibits


Exhibit
Number		Description

10.14		[intentionally omitted]
+10.15		Amended and Restated Credit Agreement, dated as of July 16, 2003 (“Amended and Restated Credit Agreement”), among Calpine Corporation, the Lenders named therein, The Bank of Nova Scotia, as Administrative Agent, Funding Agent, Lead Arranger and Bookrunner, Bayerische Landesbank, Cayman Islands Branch, as Lead Arranger, Co-Bookrunner and Documentation Agent, and ING Capital LLC and Toronto Dominion (Texas) Inc., as Lead Arrangers, Co-Bookrunners and Co-Syndication Agents
+10.16		First Amendment to Amended and Restated Credit Agreement, dated as of August 7, 2003, among Calpine Corporation, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent
+10.17		Credit Agreement, dated as of July 16, 2003, among Calpine Corporation, the Lenders named therein, Goldman Sachs Credit Partners L.P., as Sole Lead Arranger, Sole Bookrunner and Administrative Agent, The Bank of Nova Scotia, as Arranger and Syndication Agent, TD Securities (USA) Inc., ING (U.S.) Capital LLC and Landesbank Hessen-Thuringen, as Co-Arrangers and Credit Lyonnais New York Branch and Union Bank of California, N.A., as Managing Agents
+10.18		Letter of Credit Agreement, dated as of July 16, 2003, among Calpine Corporation, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent
+10.19		Guarantee and Collateral Agreement, dated as of July 16, 2003, made by Calpine Corporation, JOQ Canada, Inc., Quintana Minerals (USA) Inc., and Quintana Canada Holdings LLC, in favor of The Bank of New York, as Collateral Trustee
+10.20		First Amendment Pledge Agreement, dated as of July 16, 2003, made by JOQ Canada, Inc., Quintana Minerals (USA) Inc., and Quintana Canada Holdings LLC in favor of The Bank of New York, as Collateral Trustee
+10.21		First Amendment Assignment and Security Agreement, dated as of July 16, 2003, made by Calpine Corporation in favor of The Bank of New York, as Collateral Trustee
+10.22		Second Amendment Pledge Agreement (Stock Interests), dated as of July 16, 2003, made by Calpine Corporation in favor of The Bank of New York, as Collateral Trustee
+10.23		Second Amendment Pledge Agreement (Membership Interests), dated as of July 16, 2003, made by Calpine Corporation in favor of The Bank of New York, as Collateral Trustee
+10.24		First Amendment Note Pledge Agreement, dated as of July 16, 2003, made by Calpine Corporation in favor of The Bank of New York, as Collateral Trustee
+10.25		Collateral Trust Agreement, dated as of July 16, 2003, among Calpine Corporation, JOQ Canada, Inc., Quintana Minerals (USA) Inc., Quintana Canada Holdings LLC, Wilmington Trust Company, as Trustee, The Bank of Nova Scotia, as Agent, Goldman Sachs Credit Partners L.P., as Administrative Agent, and The Bank of New York, as Collateral Trustee
+10.26		Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Multistate), dated as of July 16, 2003, from Calpine Corporation to Messrs. Denis O’Meara and James Trimble, as Trustees, and The Bank of New York, as Collateral Trustee
+10.27		Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Multistate), dated as of July 16, 2003, from Calpine Corporation to Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of New York, as Collateral Trustee
+10.28		Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Colorado), dated as of July 16, 2003, from Calpine Corporation to Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of New York, as Collateral Trustee
+10.29		Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (New Mexico), dated as of July 16, 2003, from Calpine Corporation to Messrs. Denis O’Meara and James Trimble, as Trustees, and The Bank of New York, as Collateral Trustee
+10.30		Form of Amended and Restated Mortgage, Assignment, Security Agreement and Financing Statement (Louisiana), dated as of July 16, 2003, from Calpine Corporation to The Bank of New York, as Collateral Trustee
+10.31		Form of Amended and Restated Deed of Trust with Power of Sale, Assignment of Production, Security Agreement, Financing Statement and Fixture Filings (California), dated as of July 16, 2003, from Calpine Corporation to Chicago Title Insurance Company, as Trustee, and The Bank of New York, as Collateral Trustee
+10.32		Form of Deed to Secure Debt, Assignment of Rents and Security Agreement (Georgia), dated as of July 16, 2003, from Calpine Corporation to The Bank of New York, as Collateral Trustee
+10.33		Form of Mortgage, Assignment of Rents and Security Agreement (Florida), dated as of July 16, 2003, from Calpine Corporation to The Bank of New York, as Collateral Trustee
+10.34		Form of Deed of Trust, Assignment of Rents and Security Agreement and Fixture Filing (Texas), dated as of July 16, 2003, from Calpine Corporation to Malcolm S. Morris, as Trustee, in favor of The Bank of New York, as Collateral Trustee


Exhibit
Number		Description

+10.35		Form of Deed of Trust, Assignment of Rents and Security Agreement (Washington), dated as of July 16, 2003, from Calpine Corporation to Chicago Title Insurance Company, in favor of The Bank of New York, as Collateral Trustee
+10.36		Form of Deed of Trust, Assignment of Rents, and Security Agreement (California), dated as of July 16, 2003, from Calpine Corporation to Chicago Title Insurance Company, in favor of The Bank of New York, as Collateral Trustee
+10.37		Form of Mortgage, Collateral Assignment of Leases and Rents, Security Agreement and Financing Statement (Louisiana), dated as of July 16, 2003, from Calpine Corporation to The Bank of New York, as Collateral Trustee
+10.38		Amended and Restated Hazardous Materials Undertaking and Indemnity (Multistate), dated as of July 16, 2003, by Calpine Corporation in favor of The Bank of New York, as Collateral Trustee
+10.39		Amended and Restated Hazardous Materials Undertaking and Indemnity (California), dated as of July 16, 2003, by Calpine Corporation in favor of The Bank of New York, as Collateral Trustee
+31.1		Certification of the Chairman, President and Chief Executive Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
+31.2		Certification of the Executive Vice President and Chief Financial Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
+32.1		Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

*		Incorporated by reference.

+		Filed herewith.

(a)		Incorporated by reference to Calpine Corporation’s 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 Quarterly Report on Form 10-Q dated September 30, 2002, filed with the SEC on November 14, 2002.

(i)		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.

(j)		Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated March 31, 2003, filed with the SEC on July 1, 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

The registrant filed or furnished the following reports on Form 8-K during the quarter ended June 30, 2003:


	Date Filed
Date of Report	or Furnished		Item Reported

4/10/03		4/17/03		4,7
5/6/03		5/7/03		12
5/13/03		5/13/03		5,7
5/13/03		5/14/03		12
5/19/03		5/20/03		5
5/23/03		5/27/03		5
6/2/03		6/3/03		5
6/5/03		6/5/03		5


	Date Filed
Date of Report	or Furnished		Item Reported

6/12/03		6/13/03		5
6/17/03		6/18/03		5
6/23/03		6/24/03		5
6/25/03		6/26/03		5
6/26/03		6/26/03		5

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: August 14, 2003
	By:	/s/ CHARLES B. CLARK, JR.

		Charles B. Clark, Jr.
		Senior Vice President and Corporate
		Controller (Principal Accounting Officer)

Date: August 14, 2003

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)
+4.1		Indenture dated as of July 16, 2003, between Calpine Corporation and Wilmington Trust Company, as Trustee, including form of Notes
+4.2		Indenture dated as of July 16, 2003, between Calpine Corporation and Wilmington Trust Company, as Trustee, including form of Notes
+4.3		Indenture dated as of July 16, 2003, between Calpine Corporation and Wilmington Trust Company, as Trustee, including form of Notes
+4.4		Indenture dated as of June 13, 2003, between Power Contract Financing, L.L.C. and Wilmington Trust Company, as Trustee, Accounts Agent, Paying Agent and Registrar, including form of Notes
*10.1		Second Amended and Restated Credit Agreement (“Second Amended and Restated Credit Agreement”) dated as of May 23, 2000, among Calpine Corporation, 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 Calpine Corporation, 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 Calpine Corporation, 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 Calpine Corporation, 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 Calpine Corporation, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein (h)
*10.6		Fifth Amendment to Second Amended and Restated Credit Agreement, dated as of March 12, 2003, among Calpine Corporation, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein (i)
*10.7		Sixth Amendment to Second Amended and Restated Credit Agreement, dated as of May 23, 2003, among Calpine Corporation, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein (j)
*10.8		Seventh Amendment to Second Amended and Restated Credit Agreement, dated as of June 16, 2003, among Calpine Corporation, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein (j)
*10.9		Credit Agreement, dated as of March 8, 2002, among Calpine Corporation, 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 Calpine Corporation, 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 (k)
*10.12		Second Amendment to Credit Agreement, dated as of May 23, 2003, among Calpine Corporation, The Bank of Nova Scotia, as Joint Administrative Agent and Funding Agent, Citicorp USA, Inc., as Joint Administrative Agent, and the Lenders named therein (j)


Exhibit
Number			Description

*10.13			Third Amendment to Credit Agreement, dated as of June 16, 2003, among Calpine Corporation, The Bank of Nova Scotia, as Joint Administrative Agent and Funding Agent, Citicorp USA, Inc., as Joint Administrative Agent, and the Lenders named therein (j)
10.14			[intentionally omitted]
+10.15			Amended and Restated Credit Agreement, dated as of July 16, 2003 (“Amended and Restated Credit Agreement”), among Calpine Corporation, the Lenders named therein, The Bank of Nova Scotia, as Administrative Agent, Funding Agent, Lead Arranger and Bookrunner, Bayerische Landesbank, Cayman Islands Branch, as Lead Arranger, Co-Bookrunner and Documentation Agent and ING Capital LLC and Toronto Dominion (Texas) Inc., as Lead Arrangers, Co-Bookrunners and Co-Syndication Agents
+10.16			First Amendment to Amended and Restated Credit Agreement, dated as of August 7, 2003, among Calpine Corporation, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent
+10.17			Credit Agreement, dated as of July 16, 2003, among Calpine Corporation, the Lenders named therein, Goldman Sachs Credit Partners L.P., as Sole Lead Arranger, Sole Bookrunner and Administrative Agent, The Bank of Nova Scotia, as Arranger and Syndication Agent, TD Securities (USA) Inc., ING (U.S.) Capital LLC and Landesbank Hessen-Thuringen, as Co-Arrangers and Credit Lyonnais New York Branch and Union Bank of California, N.A., as Managing Agents
+10.18			Letter of Credit Agreement, dated as of July 16, 2003, among Calpine Corporation, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent
+10.19			Guarantee and Collateral Agreement, dated as of July 16, 2003, made by Calpine Corporation, JOQ Canada, Inc., Quintana Minerals (USA) Inc., and Quintana Canada Holdings LLC, in favor of The Bank of New York, as Collateral Trustee
+10.20			First Amendment Pledge Agreement, dated as of July 16, 2003, made by JOQ Canada, Inc., Quintana Minerals (USA) Inc., and Quintana Canada Holdings LLC in favor of The Bank of New York, as Collateral Trustee
+10.21			First Amendment Assignment and Security Agreement, dated as of July 16, 2003, made by Calpine Corporation in favor of The Bank of New York, as Collateral Trustee
+10.22			Second Amendment Pledge Agreement (Stock Interests), dated as of July 16, 2003, made by Calpine Corporation in favor of The Bank of New York, as Collateral Trustee
+10.23			Second Amendment Pledge Agreement (Membership Interests), dated as of July 16, 2003, made by Calpine Corporation in favor of The Bank of New York, as Collateral Trustee
+10.24			First Amendment Note Pledge Agreement, dated as of July 16, 2003, made by Calpine Corporation in favor of The Bank of New York, as Collateral Trustee
+10.25			Collateral Trust Agreement, dated as of July 16, 2003, among Calpine Corporation, JOQ Canada, Inc., Quintana Minerals (USA) Inc., Quintana Canada Holdings LLC, Wilmington Trust Company, as Trustee, The Bank of Nova Scotia, as Agent, Goldman Sachs Credit Partners L.P., as Administrative Agent, and The Bank of New York, as Collateral Trustee
+10.26			Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Multistate), dated as of July 16, 2003, from Calpine Corporation to Messrs. Denis O’Meara and James Trimble, as Trustees, and The Bank of New York, as Collateral Trustee
+10.27			Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Multistate), dated as of July 16, 2003, from Calpine Corporation to Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of New York, as Collateral Trustee
+10.28			Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Colorado), dated as of July 16, 2003, from Calpine Corporation to Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of New York, as Collateral Trustee
+10.29			Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (New Mexico), dated as of July 16, 2003, from Calpine Corporation to Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of New York, as Collateral Trustee
+10.30			Form of Amended and Restated Mortgage, Assignment, Security Agreement and Financing Statement (Louisiana), dated as of July 16, 2003, from Calpine Corporation to The Bank of New York, as Collateral Trustee
+10.31			Form of Amended and Restated Deed of Trust with Power of Sale, Assignment of Production, Security Agreement, Financing Statement and Fixture Filings (California), dated as of July 16, 2003, from Calpine Corporation to Chicago Title Insurance Company, as Trustee, and The Bank of New York, as Collateral Trustee
+10.32			Form of Deed to Secure Debt, Assignment of Rents and Security Agreement (Georgia), dated as of July 16, 2003, from Calpine Corporation to The Bank of New York, as Collateral Trustee
+10.33			Form of Mortgage, Assignment of Rents and Security Agreement (Florida), dated as of July 16, 2003, from Calpine Corporation to The Bank of New York, as Collateral Trustee


Exhibit
Number		Description

+10.34		Form of Deed of Trust, Assignment of Rents and Security Agreement and Fixture Filing (Texas), dated as of July 16, 2003, from Calpine Corporation to Malcolm S. Morris, as Trustee, in favor of The Bank of New York, as Collateral Trustee
+10.35		Form of Deed of Trust, Assignment of Rents and Security Agreement (Washington), dated as of July 16, 2003, from Calpine Corporation to Chicago Title Insurance Company, in favor of The Bank of New York, as Collateral Trustee
+10.36		Form of Deed of Trust, Assignment of Rents, and Security Agreement (California), dated as of July 16, 2003, from Calpine Corporation to Chicago Title Insurance Company, in favor of The Bank of New York, as Collateral Trustee
+10.37		Form of Mortgage, Collateral Assignment of Leases and Rents, Security Agreement and Financing Statement (Louisiana), dated as of July 16, 2003, from Calpine Corporation to The Bank of New York, as Collateral Trustee
+10.38		Amended and Restated Hazardous Materials Undertaking and Indemnity (Multistate), dated as of July 16, 2003, by Calpine Corporation in favor of The Bank of New York, as Collateral Trustee
+10.39		Amended and Restated Hazardous Materials Undertaking and Indemnity (California), dated as of July 16, 2003, by Calpine Corporation in favor of The Bank of New York, as Collateral Trustee
+31.1		Certification of the Chairman, President and Chief Executive Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
+31.2		Certification of the Executive Vice President and Chief Financial Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
+32.1		Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

*		Incorporated by reference.

+		Filed herewith.

(a)		Incorporated by reference to Calpine Corporation’s 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 Quarterly Report on Form 10-Q dated September 30, 2002, filed with the SEC on November 14, 2002.

(i)		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.

(j)		Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated March 31, 2003, filed with the SEC on July 1, 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.

(1)		On May 12, 2003, the Company completed the 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, the partnership terminated its 580-MW, 20-year tolling arrangement with a subsidiary of Aquila in return for a cash payment of $105.5 million. Acadia recorded a gain of $105.5 million and then made a $105.5 million distribution to Calpine. Subsequently, CES, a wholly owned subsidiary of Calpine, entered into a new 20-year, 580-MW 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. As a result of this transaction, the Company recorded, as its share of the termination payment from the Aquila subsidiary, a $52.8 million gain which was recorded within income from unconsolidated investments in power projects.

(2)		On March 29, 2002, the Company sold its 11.4% interest in the Lockport Power Plant in exchange for a $27.3 million note receivable, which was subsequently paid in full, from Fortistar Tuscarora LLC, a wholly owned subsidiary of Fortistar LLC, the project’s managing general partner. This transaction resulted in a pre-tax gain of $9.7 million recorded in other income.

	•		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 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.

	•		Sold a preferred interest in a subsidiary that leases and operates the 115-megawatt King City Power Plant to GE Structured Finance for $82 million. The preferred interest holder will receive approximately 60% of future cash flow distributions based on current projection.

	•		Monetized one of its long-term power sales contracts with the California Department of Water Resources through an $802 million senior secured notes offering by Power Contract Financing, L.L.C. (“PCF”), a Calpine stand-alone subsidiary. As part of the PCF financing transaction, PCF issued two tranches of Senior Secured Notes totaling $802.2 million in aggregate. The two tranches of Senior Secured Notes have been rated Baa2 by Moody’s Investors Service, Inc. and BBB (with a negative outlook) by S&P.

	•		Received $105.5 million for a contract monetization and a restructuring of its 50-percent interest in a partnership that owns and operates the 1,160-megawatt Acadia Power Project in Louisiana.

	•		Completed an $82.8 million monetization of its 100-megawatt power sales agreement with the Bonneville Power Administration.

	•		Announced plans for its stand-alone subsidiary Gilroy Energy Center, LLC (GEC) to sell approximately $270 million of senior secured notes, net proceeds of which will be used to reimburse costs incurred in connection with Calpine’s 11 northern California peaking units. Calpine also announced negotiations for a $74 million third-party equity investment in GEC.

	•		Agreed to sell its unconsolidated, 50-percent interest in the 240-megawatt Gordonsville Power Plant. As a result of the transaction, Calpine will receive a $31.5 million cash payment, which includes a $5.5 million payment from the project for return of a debt service reserve.

	•		Average availability and average baseload capacity factor or operating rate. Availability represents the percent of total hours during the period that our plants were available to run after taking into account the downtime associated with both scheduled and unscheduled outages. The baseload capacity factor, sometimes called operating rate, is calculated by dividing (a) total baseload megawatt hours generated by our power plants (excluding pure peaker facilities (“peakers”)) by the product of multiplying (b) the weighted average baseload megawatts in operation during the period by (c) the total hours in the period. The baseload capacity factor is thus a measure of total actual baseload generation as a percent of total potential baseload generation. If we elect not to generate during periods when electricity pricing is too low or gas prices too high to operate profitably, the baseload capacity factor will reflect that decision as well as both scheduled and unscheduled outages due to maintenance and repair requirements. Peakers are designed to operate infrequently, generally only during periods of high demand, and so are excluded from the calculation of baseload capacity factor.

	•		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 intercompany “equity” gas from Calpine Natural Gas, which is eliminated in consolidation), and the spread on sales of purchased gas for hedging, balancing, and optimization activity by (b) the heat content in millions of Btu’s of the fuel we consumed in our power plants for the period.

	•		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.

(i)		Election of Jeffrey E. Garten as Class I Director for a three-year term expiring 2006: 342,194,260 FOR and 12,394,554 ABSTAIN;

		Election of George J. Stathakis as Class I Director for a three-year term expiring 2006: 342,503,334 FOR and 12,085,480 ABSTAIN;

		Election of John O. Wilson as Class I Director for a three-year term expiring 2006: 342,299,478 FOR and 12,289,337 ABSTAIN;

(ii)		Proposal that the Board of Directors be requested to redeem the stockholders right plan unless such plan is approved by a majority vote of the stockholders to be held as soon as may be practicable: 114,024,314 FOR, 52,519,839 AGAINST, 5,427,930 ABSTAIN, and 182,616,732 Broker non-votes;

(iii)		Proposal that the Board of Directors take the necessary steps to declassify the Board of Directors for the purpose of establishing elections for directors: 107,998,279 FOR, 58,400,060 AGAINST, 5,573,744 ABSTAIN, and 182,616,732 Broker non-votes.

(iv)		Ratification of the appointment of PricewaterhouseCoopers LLP as independent accountants for the fiscal year ending December 31, 2003: 345,740,875 FOR, 5,993,176 AGAINST, and 2,854,762 ABSTAIN.