Exhibit 99.3

Item 8.  Financial Statements and Supplementary Data

      The information required hereunder is set forth under “Independent Auditors’ Report,” “Report of Independent Chartered Accountants,” “Consolidated Balance Sheets,” “Consolidated Statements of Operations,” “Consolidated Statements of Stockholders’ Equity,” “Consolidated Statements of Cash Flows,” and “Notes to Consolidated Financial Statements” included in the Consolidated Financial Statements that are a part of this report. Other financial information and schedules are included in the Consolidated Financial Statements that are a part of this report.

CALPINE CORPORATION AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2002

Independent Auditors’ Report	F-2
Consolidated Balance Sheets December 31, 2002 and 2001 (Restated)	F-4
Consolidated Statements of Operations for the Years Ended December 31, 2002, 2001 (Restated), and 2000 (Restated)	F-6
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2002, 2001 (Restated), and 2000 (Restated)	F-8
Consolidated Statements of Cash Flows for the Years Ended December 31, 2002, 2001 (Restated), and 2000 (Restated)	F-9
Notes to Consolidated Financial Statements for the Years Ended December 31, 2002, 2001 (Restated), and 2000 (Restated)	F-10

F-1

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors

and Stockholders of Calpine Corporation:

      We have audited the consolidated balance sheets of Calpine Corporation and subsidiaries (the “Company”) as of December 31, 2002 and 2001, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. The consolidated financial statements give retroactive effect to the merger of Calpine Corporation and Encal Energy Ltd. (“Encal”) on April 19, 2001, which has been accounted for as a pooling of interests as discussed in Note 3 of the Notes to the Consolidated Financial Statements. We did not audit the related statements of operations, stockholders’ equity, and cash flows of Encal for the year ended December 31, 2000, which statements reflect total revenues constituting 11.1% of consolidated total revenues for the year ended December 31, 2000. Such financial statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Encal, is based solely on the report of such other auditors.

      We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.

      In our opinion, based on our audits and the report of other auditors, such consolidated financial statements present fairly, in all material respects, the consolidated financial position of Calpine Corporation and subsidiaries as of December 31, 2002 and 2001, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.

      As discussed in Note 2 of the Notes to the Consolidated Financial Statements, in 2002, the Company adopted new accounting standards to account for the impairment of long-lived assets, discontinued operations, gains and losses on debt extinguishments and certain derivative contracts. Additionally, in 2002, the Company changed the method of reporting gains and losses associated with energy trading contracts from the gross to the net method and retroactively reclassified the consolidated statements of operations for 2001 and 2000. In 2001, as discussed in Note 3 of the Notes to the Consolidated Financial Statements, the Company adopted Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, and certain interpretations issued by the Derivatives Implementation Group of the Financial Accounting Standards Board.

      As discussed in Note 2 of the Notes to the Consolidated Financial Statements, the accompanying 2001 and 2000 consolidated financial statements have been restated.

      As discussed in Note 12 of the Notes to the Consolidated Financial Statements, in June 2003, the Company approved the divestiture of its specialty data center engineering business. Accordingly, the accompanying 2002 and 2001 consolidated financial statements have been reclassified.

/s/ DELOITTE & TOUCHE LLP

San Jose, California

March 10, 2003

(March 26, 2003 as to paragraphs two, three and four of Note 29;

October 21, 2003 as to paragraph two of Note 12)

F-2

REPORT OF INDEPENDENT CHARTERED ACCOUNTANTS

The Board of Directors of Encal Energy Ltd.

      We have audited the consolidated balance sheets of Encal Energy Ltd. as of December 31, 2000, 1999, and 1998, and the related consolidated statements of earnings, changes in shareholders’ equity, and cash flows for each of the three years in the three year period ended December 31, 2000. These financial statements are the responsibility of the company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

      We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Encal Energy Ltd. at December 31, 2000, 1999, and 1998, and the consolidated results of its operations and its cash flows for each of the three years in the three year period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States.

ERNST AND YOUNG LLP

Calgary, Canada

February 16, 2001

F-3

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

December 31, 2002 and 2001

			2002		2001
					Restated(1)
			(In thousands, except share
			and per share amounts)
ASSETS
Current assets:
	Cash and cash equivalents		$	579,486	$	1,594,144
	Accounts receivable, net of allowance of $5,955 and $15,422			745,312		963,361
	Margin deposits and other prepaid expense			152,413		451,353
	Inventories			106,536		82,801
	Restricted cash			176,716		102,633
	Current derivative assets			330,244		820,183
	Current assets held for sale			2,005		12,851
	Other current assets			143,318		95,850
		Total current assets		2,236,030		4,123,176
Restricted cash, net of current portion				9,203		9,438
Notes receivable, net of current portion				195,398		158,124
Project development costs				116,795		405,835
Investments in power projects				421,402		367,290
Deferred financing costs				185,026		193,734
Prepaid lease, net of current portion				301,603		142,887
Property, plant and equipment, net				18,846,580		15,327,030
Goodwill, net				29,165		23,924
Other intangible assets, net				93,066		109,290
Long-term derivative assets				496,028		578,775
Long-term assets held for sale				11,630		363,443
Other assets				285,066		134,281
		Total assets	$	23,226,992	$	21,937,227

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

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

F-4

			2002			2001
						Restated(1)
			(In thousands, except share
			and per share amounts)
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
	Accounts payable		$	1,237,261		$	1,285,569
	Accrued payroll and related expense			47,978			56,100
	Accrued interest payable			189,336			185,727
	Income taxes payable			3,640			—
	Notes payable and borrowings under lines of credit, current portion			340,703			23,238
	Capital lease obligation, current portion			3,454			2,069
	Construction/project financing, current portion			1,307,291			—
	Zero-Coupon Convertible Debentures Due 2021			—			878,000
	Current derivative liabilities			189,356			634,534
	Current liabilities held for sale			1,962			14,857
	Other current liabilities			246,150			171,460
		Total current liabilities		3,567,131			3,251,554
Term loan				949,565			—
Notes payable and borrowings under lines of credit, net of current portion				8,249			74,750
Capital lease obligation, net of current portion				197,653			198,469
Construction/project financing, net of current portion				3,212,022			4,080,495
Convertible Senior Notes Due 2006				1,200,000			1,100,000
Senior notes				6,894,801			7,036,461
Deferred income taxes, net				1,123,729			951,857
Deferred lease incentive				53,732			57,236
Deferred revenue				154,969			92,139
Long-term derivative liabilities				528,400			862,842
Long-term liabilities held for sale				19			7,560
Other liabilities				175,636			87,269
		Total liabilities		18,065,906			17,800,632
Commitments and contingencies (see Note 26)
Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts				1,123,969			1,122,924
Minority interests				185,203			45,542
Stockholders’ equity:
	Preferred stock, $.001 par value per share; authorized 10,000,000 shares; issued and outstanding one share in 2002 and 2001			—			—
	Common stock, $.001 par value per share; authorized 1,000,000,000 shares; issued and outstanding 380,816,132 shares in 2002 and 307,058,751 shares in 2001			381			307
	Additional paid-in capital			2,802,503			2,040,833
	Retained earnings			1,286,487			1,167,869
	Accumulated other comprehensive loss			(237,457	)		(240,880	)
		Total stockholders’ equity		3,851,914			2,968,129
		Total liabilities and stockholders’ equity	$	23,226,992		$	21,937,227

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

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

F-5

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

				For the Years Ended December 31,
				2002			2001		2000
							Restated(1)		Restated(1)
				(In thousands, except
				per share amounts)
Revenue:
	Electric generation and marketing revenue
		Electricity and steam revenue		$	3,280,291		$	2,417,481	$	1,696,066
		Sales of purchased power for hedging and optimization			3,145,991			3,332,412		369,911
	Total electric generation and marketing revenue				6,426,282			5,749,893		2,065,977
	Oil and gas production and marketing revenue
		Oil and gas sales			121,227			286,519		221,883
		Sales of purchased gas for hedging and optimization			870,466			526,517		87,119
	Total oil and gas production and marketing revenue				991,693			813,036		309,002
	Trading revenue, net
		Realized revenue on power and gas trading transactions, net			26,090			29,145		—
		Unrealized mark-to-market gain (loss) on power and gas transactions, net			(4,605	)		122,593		—
	Total trading revenue, net				21,485			151,738		—
	Other revenue				10,787			32,697		199
			Total revenue		7,450,247			6,747,364		2,375,178
Cost of revenue:
	Electric generation and marketing expense
		Plant operating expense			510,676			325,847		198,964
		Royalty expense			17,615			27,493		32,326
		Purchased power expense for hedging and optimization			2,618,445			2,986,578		358,649
	Total electric generation and marketing expense				3,146,736			3,339,918		589,939
	Oil and gas production and marketing expense
		Oil and gas production expense			97,895			90,882		66,369
		Purchased gas expense for hedging and optimization			821,065			492,587		107,591
	Total oil and gas production and marketing expense				918,960			583,469		173,960
	Fuel expense				1,791,930			1,170,977		602,165
	Depreciation, depletion and amortization expense				459,465			311,302		195,863
	Operating lease expense				111,022			99,519		63,463
	Other expense				7,279			10,943		2,019
			Total cost of revenue		6,435,392			5,516,128		1,627,409

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

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

F-6

		For the Years Ended December 31,
		2002			2001			2000
					Restated(1)			Restated(1)
		(In thousands, except
		per share amounts)
	Gross profit		1,014,855			1,231,236			747,769
Income from unconsolidated investments in power projects			(16,552	)		(16,946	)		(28,796	)
Equipment cancellation and asset impairment charge			404,737			—			—
Project development expense			66,981			35,879			27,556
General and administrative expense			229,011			150,453			97,749
Merger expense			—			41,627			—
	Income from operations		330,678			1,020,223			651,260
Interest expense			413,702			198,473			81,890
Distributions on trust preferred securities			62,632			62,412			45,076
Interest income			(43,116	)		(72,459	)		(40,504	)
Other expense (income)			(149,504	)		(55,049	)		544
	Income before provision (benefit) for income taxes		46,964			886,846			564,254
Provision (benefit) for income taxes			(12,181	)		299,427			231,451
	Income before discontinued operations and cumulative effect of a change in accounting principle		59,145			587,419			332,803
Discontinued operations, net of tax provision of $40,121, $35,989 and $31,454			59,473			35,037			36,281
Cumulative effect of a change in accounting principle, net of tax provision of $699			—			1,036			—
	Net income	$	118,618		$	623,492		$	369,084
Basic earnings per common share:
	Weighted average shares of common stock outstanding		354,822			303,522			281,084
	Income before discontinued operations and cumulative effect of a change in accounting principle	$	0.16		$	1.94		$	1.18
	Discontinued operations, net of tax	$	0.17		$	0.11		$	0.13
	Cumulative effect of a change in accounting principle	$	—		$	—		$	—
	Net income	$	0.33		$	2.05		$	1.31
Diluted earnings per common share:
	Weighted average shares of common stock outstanding before dilutive effect of certain convertible securities		362,533			317,919			297,507
	Income before dilutive effect of certain convertible securities, discontinued operations and cumulative effect of a change in accounting principle	$	0.16		$	1.85		$	1.12
	Dilutive effect of certain convertible securities(2)	$	—		$	(0.15	)	$	(0.05	)
	Income before discontinued operations and cumulative effect of a change in accounting principle	$	0.16		$	1.70		$	1.07
	Discontinued operations, net of tax	$	0.17		$	0.10		$	0.11
	Cumulative effect of a change in accounting principle	$	—		$	—		$	—
	Net income	$	0.33		$	1.80		$	1.18

(1)	See Note 2 to Consolidated Financial Statements regarding the restatement of financial statements.
(2)	See Note 25 to Consolidated Financial Statements for further information.

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

F-7

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

For the Years Ended December 31, 2002, 2001, and 2000

								Accumulated
				Additional				Other			Total
		Common		Paid-in		Retained		Comprehensive			Stockholders’			Comprehensive
		Stock		Capital		Earnings		Loss			Equity			Income
		(In thousands, except share amounts)
Balance, January 1, 2000		$	268	$	943,865	$	175,293	$	(19,337	)	$	1,100,089
	Issuance of 28,190,682 shares of common stock, net of issuance costs		28		785,900		—		—			785,928
	Issuance of 3,501,532 shares of common stock for acquisitions		4		120,591		—		—			120,595
	Tax benefit from stock options exercised and other		—		46,631		—		—			46,631
Comprehensive income:
	Net income, restated(1)		—		—		369,084		—			369,084		$	369,084
	Other comprehensive loss								(6,026	)		(6,026	)		(6,026	)
	Total comprehensive income		—		—		—		—			—		$	363,058
Balance, December 31, 2000, restated(1)			300		1,896,987		544,377		(25,363	)		2,416,301
	Issuance of 6,833,497 shares of common stock, net of issuance costs		7		72,459		—		—			72,466
	Issuance of 151,176 shares of common stock for acquisitions		—		7,500		—		—			7,500
	Tax benefit from stock options exercised and other		—		63,887		—		—			63,887
Comprehensive income:
	Net income, restated(1)		—		—		623,492		—			623,492		$	623,492
	Other comprehensive loss								(215,517	)		(215,517	)		(215,517	)
	Total comprehensive income		—		—		—		—			—		$	407,975
Balance, December 31, 2001, restated(1)			307		2,040,833		1,167,869		(240,880	)		2,968,129
	Issuance of 73,757,381 shares of common stock, net of issuance costs		74		751,721				—			751,795
	Tax benefit from stock options exercised and other		—		9,949							9,949
Comprehensive income:
	Net income		—		—		118,618		—			118,618		$	118,618
	Other comprehensive income								3,423			3,423			3,423
	Total comprehensive income		—		—		—							$	122,041
Balance, December 31, 2002		$	381	$	2,802,503	$	1,286,487	$	(237,457	)	$	3,851,914

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

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

F-8

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2002, 2001, and 2000

					2002			2001			2000
								Restated(1)			Restated(1)
					(In thousands)
Cash flows from operating activities:
	Net income				$	118,618		$	623,492		$	369,084
		Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation, depletion and amortization				542,176			364,056			228,384
		Equipment cancellation and asset impairment charge				404,737			—			—
		Development cost write-off				56,427			—			—
		Deferred income taxes, net				23,206			82,410			(8,222	)
		(Gain) on sale of assets				(97,377	)		(38,258	)		(1,051	)
		(Gain) loss on retirement of debt				(118,020	)		(9,600	)		2,031
		Minority interests				2,716			1,345			1,819
		Income from unconsolidated investments in power projects				(16,490	)		(9,433	)		(23,969	)
		Distributions from unconsolidated investments in power projects				14,117			5,983			29,979
		Change in operating assets and liabilities, net of effects of acquisitions:
			Accounts receivable			229,187			(230,400	)		(486,968	)
			Change in net derivative liability			(268,551	)		57,693			—
			Other current assets			405,515			(527,296	)		9,917
			Other assets			(306,894	)		(120,310	)		(58,174	)
			Accounts payable and accrued expense			(48,804	)		449,369			674,935
			Other liabilities			200,203			71,927			137,986
			Other comprehensive income (loss) relating to derivatives			(72,300	)		(297,409	)		—
				Net cash provided by operating activities		1,068,466			423,569			875,751
Cash flows from investing activities:
	Purchases of property, plant and equipment					(4,036,254	)		(5,832,874	)		(3,068,528	)
	Disposals of property, plant and equipment					400,349			49,120			17,321
	Acquisitions, net of cash acquired					—			(1,608,840	)		(728,455	)
	Proceeds from sale leasebacks					—			517,081			242,205
	Advances to joint ventures					(68,088	)		(177,917	)		(132,102	)
	Maturities of collateral securities					3,586			2,549			6,445
	Project development costs					(105,182	)		(147,520	)		(50,912	)
	Cash flows from derivatives not designated as hedges					26,091			29,145			—
	(Increase) decrease in restricted cash					(73,848	)		(45,642	)		8,374
	(Increase) decrease in notes receivable					8,926			(40,273	)		(165,509	)
	Other					6,593			14,516			(6,026	)
				Net cash used in investing activities		(3,837,827	)		(7,240,655	)		(3,877,187	)
Cash flows from financing activities:
	Proceeds from issuance of Zero-Coupon Convertible Debentures Due 2021					—			1,000,000			—
	Repurchase of Zero-Coupon Convertible Debentures Due 2021					(869,736	)		(110,100	)		—
	Borrowings from notes payable and borrowings under lines of credit					1,348,798			148,863			1,100,766
	Repayments of notes payable and borrowings under lines of credit					(126,404	)		(962,873	)		(1,315,506	)
	Borrowings from project financing					725,111			3,869,391			1,548,328
	Repayments of project financing					(286,293	)		(1,712,292	)		(631,374	)
	Proceeds from issuance of Convertible Senior Notes Due 2006					100,000			1,100,000			—
	Repayments of senior notes					—			(106,300	)		—
	Proceeds from Company — obligated mandatorily redeemable convertible preferred securities of a subsidiary trust					—			—			877,500
	Proceeds from senior debt offerings					—			4,596,039			1,000,000
	Proceeds from issuance of common stock					751,795			72,465			784,033
	Proceeds from Income Trust Offering					169,677			—			—
	Financing costs					(42,783	)		(144,746	)		(37,750	)
	Other					(12,769	)		(270	)		(9,210	)
				Net cash provided by financing activities		1,757,396			7,750,177			3,316,787
Effect of exchange rate changes on cash and cash equivalents						(2,693	)		(3,669	)		—
Net increase (decrease) in cash and cash equivalents						(1,014,658	)		929,422			315,351
Cash and cash equivalents, beginning of period						1,594,144			664,722			349,371
Cash and cash equivalents, end of period					$	579,486		$	1,594,144		$	664,722
Cash paid during the period for:
	Interest, net of amounts capitalized				$	325,334		$	42,883		$	15,912
	Income taxes				$	15,451		$	114,667		$	144,406
Schedule of non cash investing and financing activities:
	— 2002 non-cash consideration of $88.4 million in tendered Company debt received upon the sale of its British Columbia oil and gas properties
	— 2001 equity investment in a power project for $17.5 million note receivable

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

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

F-9

CALPINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the Years Ended December 31, 2002, 2001, and 2000

1.  Organization and Operations of the Company

      Calpine Corporation (“Calpine”), a Delaware corporation, and subsidiaries (collectively, the “Company”) is engaged in the generation of electricity in the United States, Canada and the United Kingdom. The Company is involved in the development, 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. In Canada, the Company owns power facilities and oil and gas operations. In the United Kingdom, the Company owns a gas-fired power cogeneration facility. Each of the generation facilities produces and markets electricity for sale to utilities and other third party purchasers. Thermal energy produced by the gas-fired power cogeneration facilities is primarily sold to industrial users. Gas produced and not physically delivered to the Company’s generating plants is sold to third parties.

2.  Restatement of Prior Period Financial Statements

      Subsequent to the issuance of the Company’s 2001 consolidated financial statements, the Company determined that the sale/leaseback transactions for the 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. In September 2000, the Company completed a leveraged lease financing transaction to provide the term financing for both Phases I and II of the Pasadena, Texas Facility. Under the terms of the lease, the Company received $400.0 million in gross proceeds and recorded a deferred gain of approximately $65.0 million. In October 2001, the Company completed the leveraged lease financing of the Broad River facility. Under the terms of the lease, the Company received $300.0 million in gross proceeds and recorded a deferred gain of $1.7 million. Statement of Financial Accounting Standards (“SFAS”) No. 98 “Accounting for Leases,” governs the accounting for sale and leaseback transactions and prohibits sale-leaseback accounting treatment when the leaseback involves a material sublease. At both the Pasadena and Broad River facilities, the Company entered into long-term power sales agreements. Certain of these agreements have been determined to meet the definition of leases within the meaning of SFAS No. 13, and have also been determined to be material subleases. Therefore, sale/leaseback accounting treatment is precluded for those plants. Accordingly, these two sale/leaseback transactions have been restated as financing transactions and the proceeds have been classified as debt and the operating lease payments have been recharacterized as debt service payments in the accompanying consolidated financial statements. The Company is therefore now accounting for the assets as if they had not been sold. The assets have been added back to the Company’s property, plant and equipment, and depreciation has been recorded thereon.

      As a result, the Company has restated the accompanying 2001 and 2000 consolidated financial statements from amounts previously reported to properly account for these two transactions as financing transactions and to record certain other adjustments.

      In addition, the Company has reclassified certain amounts in the accompanying 2001 and 2000 consolidated financial statements to reflect the adoption of new accounting standards. The reclassifications include (a) treatment as discontinued operations pursuant to SFAS No. 144 “Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of” of the 2002 sales of certain oil and gas properties and the DePere Energy Center, (b) the reclassification of gains and losses, net associated with extinguishment of debt in 2001 and 2000 from extraordinary item to nonoperating other expense (income) pursuant to SFAS No. 145, “Recission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13 and Technical Corrections,” and (c) the reclassification of revenues and costs associated with certain energy trading contracts to trading revenues, net pursuant to Emerging Issues Task Force

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(“EITF”) Issue No. 02-3, “Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities.”

      A summary of the significant effects of the restatements along with certain reclassification adjustments is as follows (in thousands except per share data):

			Adjustments
	Income		to reflect			Adjustments						Income
	Statement		adoption of new			to correct						Statement
	as previously		accounting			the accounting			Other			as
	reported		standards(1)			for two leases(2)			adjustments(3)			restated
2001
Depreciation, depletion and amortization expense	$	338,244	$	(41,466	)	$	10,506		$	4,018		$	311,302
Operating lease expense	$	118,873	$	—		$	(18,352	)	$	(1,002	)	$	99,519
Interest expense	$	165,360	$	(7,553	)	$	38,510		$	2,156		$	198,473
Income before discontinued operations and cumulative effect of a change in accounting principle	$	641,062	$	(29,030	)	$	(19,164	)	$	(5,449	)	$	587,419
Net income	$	648,105	$	—		$	(19,164	)	$	(5,449	)	$	623,492
Diluted earnings per common share		1.87											1.80
2000
Depreciation, depletion and amortization expense	$	230,787	$	(37,817	)	$	2,935		$	(42	)	$	195,863
Operating lease expense	$	69,419	$	—		$	(4,955	)	$	(1,001	)	$	63,463
Interest expense	$	74,683	$	(4,699	)	$	11,315		$	591		$	81,890
Income before discontinued operations and cumulative effect of a change in accounting principle	$	373,837	$	(37,516	)	$	(5,810	)	$	2,292		$	332,803
Net income	$	372,602	$	—		$	(5,810	)	$	2,292		$	369,084
Diluted earnings per common share		1.19											1.18

			Adjustments to
			reflect adoption			Adjustments to
	Balance Sheet		of new			correct the
	as previously		accounting			accounting for			Other			Balance Sheet
	reported		standards(1)			two leases(2)			adjustments(3)			as restated
2001
Property, plant and equipment, net	$	15,384,990	$	(445,038	)	$	618,304		$	(236,677	)	$	15,321,579
Total assets	$	21,309,295	$	—		$	595,667		$	32,265		$	21,937,227
Construction/project financing, net of current portion	$	3,393,410	$	—		$	687,085		$	—		$	4,080,495
Deferred revenue	$	154,381	$	—		$	(61,554	)	$	(688	)	$	92,139
Total liabilities	$	17,128,313	$	—		$	620,641		$	51,678		$	17,800,632
Total stockholders’ equity	$	3,010,569	$	—		$	(24,974	)	$	(17,466	)	$	2,968,129

(1)	Includes the effect of adopting SFAS No. 144, SFAS No. 145 and EITF Issue No. 02-3 and the reclassification resulting from the June 2003 discontinued operations described in Note 12.
(2)	Includes the effect of restating the accounting for the Pasadena and Broad River sale/leaseback transactions from operating lease accounting to financing transactions
(3)	Includes the effect of certain other adjustments and the effect of reclassification entries made to conform certain prior period amounts to the 2002 presentation

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      Reclassification of Prior Period Financial Information related to newly issued Accounting Standards — In 2002, the Company sold certain gas assets, as well as the DePere Energy Center. The decision to sell these assets required the application of one of the newly issued accounting standards, SFAS No. 144, which changed the criteria for determining when the disposal or sale of certain assets meets the definition of “discontinued operations.” Some of our asset sales in 2002 met the requirements of the new definition and accordingly, the Company made reclassifications to current and prior period financial statements to reflect the sale or designation as “held for sale” of certain oil and gas and power plant assets and liabilities and to separately classify the operating results of the assets sold and gain on sale of those assets from the operating results of continuing operations. See Note 12 for further information.

      In April 2002, the FASB issued SFAS No. 145. SFAS No. 145 rescinds SFAS No. 4, “Reporting Gains and Losses from Extinguishment of Debt.” The Company elected early adoption, effective July 1, 2002, of the provisions related to the rescission of SFAS No. 4. In December 2001, the Company had recorded an extraordinary gain of $7.4 million, net of tax of $4.5 million, related to the repurchase of $122.0 million Zero Coupons. The extraordinary gain was offset by an extraordinary loss of $1.4 million, net of tax of $0.9 million, related to the write-off of unamortized deferred financing costs in connection with the repayment of $105 million of the 9 1/4% Senior Notes Due 2004 and the bridge facilities. In August 2000, in connection with repayment of outstanding borrowings, the termination of certain credit agreements and the related write-off of deferred financing costs, the Company recorded an extraordinary loss of $1.2 million, net of tax of $0.8 million.

      In October 2002, the EITF discussed EITF Issue No. 02-3. The EITF reached a consensus to rescind EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” the impact of which is to preclude mark-to-market accounting for all energy trading contracts not within the scope of SFAS No. 133. The EITF also reached a consensus that gains and losses on derivative instruments within the scope of SFAS No. 133 should be shown net in the income statement if the derivative instruments are held for trading purposes, as defined in SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities.” EITF Issue No. 02-3 has had no impact on the Company’s net income but has affected the presentation of the Consolidated Financial Statements. Effective July 1, 2002, the Company changed its method of reporting trading revenues to conform to this standard and accordingly, the Company reclassified certain revenue amounts and cost of revenue in its Consolidated Statements of Operations as follows (in thousands):

			For the Years Ended
			December 31,
			2002			2001
Amounts previously classified as:
	Sales of purchased power		$	845,349		$	732,193
	Sales of purchased gas			126,031			23,441
	Purchased power expense			833,174			722,267
	Purchased gas expense			121,944			23,827
	Cost of oil and natural gas burned by power plants (fuel expense)			(9,828	)		(19,605	)
Net amount reclassified to:
		Realized revenue on power and gas trading transactions, net	$	26,090		$	29,145
Amounts previously classified as:
	Electric power derivative mark-to-market gain (loss)			8,017			98,291
	Natural gas derivative mark-to-market gain (loss)			(12,622	)		24,302
Net amount reclassified to:
		Unrealized mark-to-market gain (loss) on power and gas trading transactions, net	$	(4,605	)	$	122,593

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      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.

      Restatement of Certain Other Prior Period Financial Information — The Company restated certain other prior period amounts. These adjustments did not have a significant effect on the Company’s 2001 and 2000 financial statements.

      Reclassifications — Certain prior years’ amounts in the Consolidated Financial Statements have been reclassified to conform to the 2002 presentation.

3.  Summary of Significant Accounting Policies

      Principles of Consolidation — The accompanying consolidated financial statements include accounts of the Company and its wholly owned and majority-owned subsidiaries. Certain less-than-majority-owned subsidiaries are accounted for using the equity method. For equity method investments, the Company’s share of income is calculated according to the Company’s equity ownership or according to the terms of the appropriate partnership agreement (see Note 9). All intercompany accounts and transactions are eliminated in consolidation.

      On April 19, 2001, Calpine acquired 100% of the outstanding shares and interests of Encal Energy Ltd. (“Encal”). Encal is a Calgary, Alberta-based natural gas and petroleum exploration and development company. As a result of the merger, the Company issued approximately 16.6 million common shares for all of the outstanding Encal capital stock and options. The merger was accounted for as a pooling-of-interests, and the consolidated financial statements have been prepared to give retroactive effect to the merger.

      Encal operated under the same fiscal year end as Calpine, and accordingly, Encal’s statements of operations, shareholders’ equity and cash flows for the fiscal year ended December 31, 2000, have been combined with the Company’s consolidated financial statements. The results of operations previously reported by the separate companies and the combined amounts presented in the consolidated financial statements are summarized below.

			Year Ended December 31,
			2000
			(In thousands)
Revenues:
	Calpine		$	2,110,870
	Encal			264,308
		Combined revenues	$	2,375,178
Net Income:
	Calpine		$	319,934
	Encal			49,150
		Combined net income	$	369,084

      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.

      Foreign Currency Translation — Assets and liabilities of non-U.S. subsidiaries that operate in a local currency environment are translated to U.S. dollars at exchange rates in effect at the balance sheet date with the resulting translation adjustments recorded in other comprehensive income. Income and expense accounts are translated at average exchange rates during the year.

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      Fair Value of Financial Instruments — The carrying value of accounts receivable, marketable securities, accounts and other payables approximate their respective fair values due to their short maturities. See Note 18 for disclosures regarding the fair value of the senior notes.

      Cash and Cash Equivalents — The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. The carrying amount of these instruments approximates fair value because of their short maturity.

      The Company has certain project debt agreements which establish working capital accounts which limit the use of certain cash balances to the operations of the respective plants. At December 31, 2002 and 2001, $189.0 million and $336.6 million, respectively of the cash and cash equivalents balance was subject to such project debt agreements.

      Accounts Receivable and Accounts Payable — Accounts receivable and payable represent amounts due from customers and owed to vendors. These balances also include settled but unpaid amounts relating to hedging, balancing, optimization and trading activities of Calpine Energy Services, L.P. (“CES”). Some of these receivables and payables with individual counterparties are subject to master netting agreements whereby the Company legally has a right of offset and the Company settles the balances net. However, for balance sheet presentation purposes and to be consistent with the way the Company is required to present amounts related to hedging, balancing and optimization activities in its statements of operations under Staff Accounting Bulletin (“SAB”) No. 101 “Revenue Recognition in Financial Statements” and EITF Issue No. 99-19 “Reporting Revenue Gross as a Principal Versus Net as an Agent”, the Company presents its receivables and payables on a gross basis.

      Inventories — The Company’s inventories primarily include spare parts and stored gas. Operating supplies are valued at the lower of cost or market. Cost for large replacement parts estimated to be used within one year is determined using the specific identification method. For the remaining supplies and spare parts, cost is generally determined using the weighted average cost method. Stored gas is valued at the lower of weighted average cost or market.

      Margin Deposits — As of December 31, 2002 and 2001, in order to satisfy the credit requirements of trading counterparties, CES had deposited net amounts of $25.2 million and $345.5 million, respectively, in cash as margin deposits.

      Collateral Debt Securities — The Company classifies all short-term and long-term debt securities as held-to-maturity because the Company has the intent and ability to hold the securities to maturity. The securities act as collateral to support the King City operating lease and mature serially in amounts equal to a portion of the semi-annual lease payments. Held-to-maturity securities are stated at amortized cost, adjusted for amortization of premiums and accretion discounts to maturity. The Company owns no investments that are considered to be available-for-sale or trading securities.

      Property, Plant and Equipment, Net — See Note 5 for a discussion of the Company’s accounting policies for its property, plant and equipment.

      Project Development Costs — The Company capitalizes project development costs once it is determined that it is probable that such costs will be realized through the ultimate construction of a power plant. These costs include professional services, salaries, permits and other costs directly related to the development of a new project. Upon commencement of construction, these costs are transferred to construction in progress, a component of property, plant and equipment. Upon the start-up of plant operations, these construction costs are reclassified as buildings, machinery and equipment, also a component of property, plant and equipment, and are amortized as a component of the total cost of the plant over its estimated useful life. Capitalized project costs are charged to expense if the Company determines that the project is no longer probable or to the extent it is impaired. Outside services and other third party costs are capitalized for acquisition projects.

      Investments in Power Projects — The Company uses the equity method to recognize its pro rata share of the net income or loss of an unconsolidated investment until such time, if applicable, that the Company’s

F-14

investment is reduced to zero, at which time equity income is generally recognized only upon receipt of cash distributions from the investee.

      Restricted Cash — The Company is required to maintain cash balances that are restricted by provisions of its debt agreements, lease agreements and regulatory agencies. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent service, and major maintenance. Funds that will be used to satisfy obligations due during the next twelve months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is invested in accounts earning market rates; therefore the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents in the consolidated statement of cash flows.

      Notes Receivable — See Note 10 for a discussion of the Company’s accounting policies for its notes receivable.

      Deferred Financing Costs — The deferred financing costs related to the Company’s Senior Notes and the Convertible Senior Notes Due 2006 are amortized over the life of the related debt, ranging from 5 to 10 years, using the straight-line method which approximates the effective interest rate method (See Note 17). The deferred financing costs associated with the two Calpine Construction Finance Company facilities are amortized over the 4-year facility lives using the straight-line method, which approximates the effective interest rate method (See Note 16). The deferred financing costs related to the Zero-Coupon Debentures Due 2021 were amortized over 1 year due to the put option that was exercised by the holders in 2002. Costs incurred in connection with obtaining other financing are deferred and amortized over the life of the related debt.

      Long-Lived Assets — In accordance with Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets and for Long-Lived Assets to be Disposed of,” the Company evaluates the impairment of long-lived assets, based on the projection of undiscounted pre-interest expense and pre-tax expense cash flows whenever events or changes in circumstances indicate that the carrying amounts of such assets may not be recoverable. In the event such cash flows are not expected to be sufficient to recover the recorded value of the assets, the assets are written down to their estimated fair values (See Note 5).

      Concentrations of Credit Risk — Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of cash, accounts receivable, notes receivable, and commodity contracts. The Company’s cash accounts are generally held in FDIC insured banks. The Company’s accounts and notes receivable are concentrated within entities engaged in the energy industry, mainly within the United States (see Note 10 and 23). The Company generally does not require collateral for accounts receivable from end-user customers, but evaluates the net accounts receivable, accounts payable, and fair value of commodity contracts with trading companies and may require security deposits or letters of credit to be posted if exposure reaches a certain level.

      Deferred Revenue — The Company’s deferred revenue consists primarily of deferred gains for the sale/leaseback transactions as well as deferred revenue for long-term power supply contracts. See Note 8 and 23.

      Trust Preferred Securities — The Company’s trust preferred securities are accounted for as a minority interest in the balance sheet and reflected as “Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts.” The distributions are reflected in the statements of operations as “distributions on trust preferred securities.” Financing costs related to these issuances are netted with the principal amounts and are accreted as minority interest expense over the securities’ 30-year maturity using the straight-line method which approximates the effective interest rate method (See Note 19).

      Revenue Recognition — The Company is primarily an electric generation company, operating a portfolio of mostly wholly owned plants but also some plants in which its ownership interest is 50% or less and which are accounted for under the equity method. In conjunction with its electric generation business, the Company also produces, as a by-product, thermal energy for sale to customers, principally steam hosts at the Company’s cogeneration sites. In addition, the Company acquires and produces natural gas for its own consumption and

F-15

sells the balance and oil produced to third parties. Where applicable, revenues are recognized under EITF No. 91-6, “Revenue Recognition of Long Term Power Sales Contracts,” ratably over the terms of the related contracts. To protect and enhance the profit potential of its electric generation plants, the Company, through its subsidiary, CES, enters into electric and gas hedging, balancing, and optimization transactions, subject to market conditions, and CES has also, from time to time, entered into contracts considered energy trading contracts under EITF Issue No. 02-3. CES executes these transactions primarily through the use of physical forward commodity purchases and sales and financial commodity swaps and options. With respect to its physical forward contracts, CES generally acts as a principal, takes title to the commodities, and assumes the risks and rewards of ownership. Therefore, when CES does not hold these contracts for trading purposes and, in accordance with SAB No. 101, and EITF Issue No. 99-19, the Company records settlement of its non-trading physical forward contracts on a gross basis. Effective July 1, 2002, the Company changed its method of reporting gains and losses from derivatives held for trading purposes to a net basis. Prior to July 1, 2002, physical trading contracts were recorded on a gross basis but have been reclassified to a net basis to conform to the current presentation. The Company settles its financial swap and option transactions net and does not take title to the underlying commodity. Accordingly, the Company records gains and losses from settlement of financial swaps and options net within net income. Managed risks typically include commodity price risk associated with fuel purchases and power sales.

      The Company, through its wholly owned subsidiary, Power Systems Mfg., LLC (“PSM”), designs and manufactures certain spare parts for gas turbines. The Company also generates revenue by occasionally loaning funds to power projects, by providing operation and maintenance (“O&M”) services to third parties and to certain unconsolidated power projects, and by performing engineering services for data centers and other facilities requiring highly reliable power. The Company also has begun to sell engineering and construction services to third parties for power projects. Further details of the Company’s revenue recognition policy for each type of revenue transaction are provided below:

      Electric Generation and Marketing Revenue — This includes electricity and steam sales and sales of purchased power for hedging, balancing and optimization. Subject to market and other conditions, the Company manages the revenue stream for its portfolio of electric generating facilities. The Company markets on a system basis both power generated by its plants in excess of amounts under direct contract between the plant and a third party, and power purchased from third parties, through hedging, balancing and optimization transactions. CES performs a market-based allocation of total electric generation and marketing revenue to electricity and steam sales (based on electricity delivered by the Company’s electric generating facilities) and the balance is allocated to sales of purchased power.

      Oil and Gas Production and Marketing Revenue — This includes sales to third parties of oil, gas and related products that are produced by the Company’s Calpine Natural Gas and Calpine Canada Natural Gas subsidiaries and, subject to market and other conditions, sales of purchased gas arising from hedging, balancing and optimization transactions. Oil and gas sales for produced products are recognized pursuant to the sales method, net of royalties. If the Company has recorded gas sales on a particular well or field in excess of its share of remaining estimated reserves, then the excessive gas sale imbalance is recognized as a liability. If the Company is under-produced on a particular well or field, and it is determined that an over-produced partner’s share of remaining reserves is insufficient to settle the gas imbalance, the Company will recognize a receivable, to the extent collectible, from the over-produced partner.

      Trading Revenue, Net — This includes realized settlements of and unrealized mark-to-market gains and losses on both power and gas derivative instruments held for trading purposes. Gains and losses due to ineffectiveness on hedging instruments are also included in unrealized mark-to-market gains and losses.

      Other Revenue — This includes O&M contract revenue, PSM revenue from sales to third parties, engineering revenue and miscellaneous revenue.

      Purchased Power and Purchased Gas Expense — The cost of power purchased from third parties for hedging, balancing and optimization activities is recorded as purchased power expense, a component of electric generation and marketing expense. The Company records the cost of gas purchased from third parties for the purposes of consumption in its power plants as fuel expense, while gas purchased from third parties for

F-16

hedging, balancing, and optimization activities is recorded as purchased gas expense, a component of oil and gas production and marketing expense.

      Insurance Program — The CPN Insurance Corporation, a wholly owned captive insurance subsidiary, charges the Company competitive premium rates to insure workers’ compensation, automobile liability, general liability as well as all risk property insurance including business interruption. Accruals for claims under the captive insurance program pertaining to property, including business interruption claims, are recorded on a claims-incurred basis. Accruals for casualty claims under the captive insurance program are recorded on a monthly basis, and are based upon the estimate of the total cost of claims incurred during the policy period. The captive insures limits up to $25 million per occurrence for property claims, including business interruption, and up to $500,000 per occurrence for casualty claims.

      Derivative Instruments — SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” as amended and interpreted by other related accounting literature, establishes accounting and reporting standards for derivative instruments (including certain derivative instruments embedded in other contracts). SFAS No. 133 requires companies to record derivatives on their balance sheets as either assets or liabilities measured at their fair value unless exempted from derivative treatment as a normal purchase and sale. All changes in the fair value of derivatives are recognized currently in earnings unless specific hedge criteria are met, which requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting.

      SFAS No. 133 sets forth the accounting requirements for cash flow and fair value hedges. SFAS No. 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, must be recognized currently in earnings. SFAS No. 133 provides that the changes in fair value of derivatives designated as fair value hedges and the corresponding changes in the fair value of the hedged risk attributable to a recognized asset, liability, or unrecognized firm commitment be recorded in earnings. If the fair value hedge is effective, the amounts recorded will offset in earnings.

      Where the Company’s derivative instruments are subject to a master netting agreement and the criteria of FASB Interpretation (“FIN”) 39 “Offsetting of Amounts Related to Certain Contracts (An Interpretation of APB Opinion No. 10 and SFAS No. 105) are met, the Company presents its derivative assets and liabilities on a net basis in its balance sheet. The Company has chosen this method of presentation because it is consistent with the way related mark-to-market gains and losses on derivatives are recorded in its Consolidated Statements of Operations and within Other Comprehensive Income (“OCI”).

New Accounting Pronouncements

      In July 2001, the Company adopted SFAS No. 141, “Business Combinations,” which supersedes Accounting Principles Board (“APB”) Opinion No. 16, “Business Combinations” and SFAS No. 38, “Accounting for Preacquisition Contingencies of Purchased Enterprises.” SFAS No. 141 eliminated the pooling-of-interests method of accounting for business combinations and modified the recognition of intangible assets and disclosure requirements. The adoption of SFAS No. 141 did not have a material effect on the Company’s consolidated financial statements.

      On January 1, 2002, the Company adopted SFAS No. 142, “Goodwill and Other Intangible Assets,” which supersedes APB Opinion No. 17, “Intangible Assets.” See Note 6 for further information.

      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

F-17

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, we 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 the Statement had been in effect at the date the obligation was incurred, which is generally the start of commercial operations for the facility.

      Based on current information and assumptions the Company expects to record an additional long-term liability of $33.3 million, an additional asset within Property, Plant and Equipment, net of accumulated depreciation, of $33.7 million, and a gain to income due to the cumulative effect of a change in accounting principle of ($0.4) million, net of taxes. These entries include the effects of the reversal of site dismantlement and restoration costs previously expensed in accordance with SFAS No. 19. Due to the complexity of this accounting standard and the number of assumptions used in the calculations, the Company may make adjustments to these estimates prior to the filing of Form 10-Q for the quarter ending March 31, 2003.

      On January 1, 2002, the Company adopted SFAS No. 144, which supersedes SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of,” and the accounting and reporting provisions of APB Opinion No. 30, “Reporting the Results of Operations — Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions,” for the disposal of a segment of a business (as previously defined in that APB Opinion). SFAS No. 144 establishes a single accounting model, based on the framework established in SFAS No. 121, for long-lived assets to be disposed of by sale. SFAS No. 144 also resolves several significant implementation issues related to SFAS No. 121, such as eliminating the requirement to allocate goodwill to long-lived assets to be tested for impairment and establishing criteria to define whether a long-lived asset is held for sale. Adoption of SFAS No. 144 has not had a material net effect on the Company’s consolidated financial statements, although certain reclassifications have been made to current and prior period financial statements to reflect the sale or designation as “held for sale” of certain oil and gas and power plant assets and classification of the operating results. In general, gains from completed sales and any anticipated losses on “held for sale” assets are included in discontinued operations net of tax. See Note 12 for further information.

      In April 2002, the FASB issued SFAS No. 145, SFAS No. 145 rescinds SFAS No. 4, “Reporting Gains and Losses from Extinguishment of Debt” and an amendment of that statement, SFAS No. 64, “Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements” and provides that gains or losses from extinguishment of debt that fall outside of the scope of APB Opinion No. 30 should not be classified as extraordinary. SFAS No. 145 also amends SFAS No. 13, “Accounting for Leases,” to eliminate an inconsistency between the required accounting for sale/leaseback transactions and the required accounting for certain lease modifications that have economic effects that are similar to sale/leaseback transactions. SFAS No. 145 also amends other existing authoritative pronouncements to make various technical corrections, clarify meanings, or describe their applicability under changed conditions. The Company elected early adoption, effective July 1, 2002, of the provisions related to the rescission of SFAS No. 4, the effect of which has been reflected in these financial statements as reclassifications of gains and losses from the extinguishment of debt from extraordinary gain/(loss) to other (income)/expense totaling $118.0 million in 2002, $9.6 million in 2001 and $(2.0) million in 2000. The provisions related to SFAS No. 13 are effective for transactions occurring after May 15, 2002. All other provisions are effective for financial statements issued on or after May 15, 2002, with early adoption encouraged. The Company believes that the SFAS No. 145 provisions relating to leases will not have a material effect on its financial statements.

      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

F-18

accounting guidance, principally EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (Including Certain Costs Incurred in a Restructuring).” The Company will adopt the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF No. 94-3, a liability for an exit cost was recognized at the date of commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amounts recognized. The Company does not believe that SFAS No. 146 will have a material effect on its Consolidated Financial Statements other than timing of exit costs.

      In October 2002 the EITF discussed EITF Issue No. 02-3. See Note 2 for further information on EITF Issue No. 02-3 and its impact on the Consolidated Financial Statements.

      In November 2002, the FASB issued FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”. FIN 45 expands on the accounting guidance of SFAS No. 5, “Accounting for Contingencies,” SFAS No. 57, “Related Party Disclosures,” and SFAS No. 107, “Disclosures about Fair Value of Financial Instruments.” FIN 45 also incorporates, without change, the provisions of FASB Interpretation No. 34, “Disclosures of Indirect Guarantees of the Indebtedness of Others,” which it supersedes. FIN 45 elaborates on the existing disclosure requirements for most guarantees. It clarifies that a guarantor’s required disclosures include the nature of the guarantee, the maximum potential undiscounted payments that could be required, the current carrying amount of the liability, if any, for the guarantor’s obligations (including the liability recognized under SFAS No. 5), and the nature of any recourse provisions or available collateral that would enable the guarantor to recover amounts paid under the guarantee. FIN 45 also clarifies that at the time a company issues a guarantee, it must recognize an initial liability for the fair value of the obligation it assumes under that guarantee, including its ongoing obligation to stand ready to perform over the term of the guarantee in the event that specified triggering events or conditions occur. FIN 45 does not prescribe a specific account for the guarantor’s offsetting entry when it recognizes the liability at the inception of the guarantee, noting that the offsetting entry would depend on the circumstances in which the guarantee was issued. There also is no prescribed approach included for subsequently measuring the guarantor’s recognized liability over the term of the related guarantee. It is noted that the liability would typically be reduced by a credit to earnings as the guarantor is released from risk under the guarantee. The initial recognition and initial measurement provisions apply on a prospective basis to guarantees issued or modified after December 31, 2002. The Company is currently evaluating the impact of FIN 45’s initial recognition and measurement provisions on its Consolidated Financial Statements. The disclosure requirements for FIN 45 are effective for financial statements of interim or annual periods ending after December 15, 2002, and have been incorporated into the Company’s December 31, 2002, disclosures of guarantees. See (Note 26).

      In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure.” This Statement amends SFAS No. 123, “Accounting for Stock-Based Compensation,” to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, 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 anticipates that the adoption of SFAS No. 123 prospectively effective January 1, 2003 will have a material effect on its financial statements. Had stock-based compensation cost for 2002, 2001 and 2000 been accounted for under SFAS No. 123, the Company’s net income and

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earnings per share would have been reduced to the following pro forma amounts (in thousands, except per share amounts):

			2002		2001		2000
Net income
		As reported	$	118,618	$	623,492	$	369,084
		Pro Forma		83,025		588,442		342,433
Earnings per share data:
	Basic earnings per share
		As reported	$	0.33	$	2.05	$	1.31
		Pro Forma		0.23		1.94		1.22
	Diluted earnings per share
		As reported	$	0.33	$	1.80	$	1.18
		Pro Forma		0.23		1.71		1.10
Stock-based compensation cost included in net income, as reported			$	—	$	—	$	—
Stock-based compensation cost included in net income, pro forma				35,593		35,050		26,651

      The range of fair values of the Company’s stock options granted in 2002, 2001, and 2000 were as follows, based on varying historical stock option exercise patterns by different levels of Calpine employees: $3.73-$6.62 in 2002, $18.29-$30.73 in 2001, and $8.01-$12.13 in 2000 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%-83% for 2002, 55%-59% for 2001, and 49%-50% for 2000, risk-free interest rates of 2.39%-3.83% for 2002, 3.99%-5.07% for 2001, and 4.99%-5.12% for 2000, and expected option terms of 4-9 years for 2002, 2001, and 2000.

      The volatility figures and expected option terms shown above have been recalculated for all prior periods based on generally longer historical time frames to be consistent with the Company’s upcoming adoption and application of SFAS No. 123. The recalculated assumptions have caused stock-based compensation cost under SFAS No. 123 to be higher than previously reported.

      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. 2. As a collective group, the entity’s owners do not have a controlling financial interest in the entity. This 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

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first fiscal year or interim period beginning after June 15, 2003, to VIEs that were previously created or acquired before February 1, 2003. The Company has not completed its assessment of the impact of FIN 46.

      In connection with the January 2003 EITF meeting, the FASB was asked to clarify the application of SFAS No. 133 Implementation Issue No. C11 “Interpretation of Clearly and Closely Related In Contracts That Qualify for the Normal Purchases and Normal Sales Exception” (“C11”). The specific issue relates to pricing based on broad market indices such as the Consumer Price Index (“CPI”) and under what circumstances those broad market indices would preclude the normal purchase and sales exception under SFAS No. 133. The Company is currently evaluating how further discussions regarding C11 would impact contracts that have been documented as exempt from derivative treatment as normal purchases and sales. While the Company is still evaluating the impact that this potential new guidance would have on its results of operations and financial position, it believes it could result in additional volatility in reported earnings, other comprehensive income and accumulated other comprehensive income.

4.  Investment in Debt Securities

      The Company classifies all short-term and long-term debt securities as held-to-maturity because of the intent and ability to hold the securities to maturity. The securities are pledged as collateral to support the King City operating lease and mature serially in amounts equal to a portion of the semi-annual lease payments. The following short-term debt securities are included in Other Current Assets at December 31, 2002 and 2001:

		2002								2001
				Gross		Gross						Gross		Gross
		Amortized		Unrealized		Unrealized		Fair		Amortized		Unrealized		Unrealized		Fair
		Cost		Gains		Losses		Value		Cost		Gains		Losses		Value
		(In thousands)
Corporate Debt Securities		$	2,012	$	38	$	—	$	2,050	$	1,882	$	6	$	—	$	1,888
Government Agency Debt Securities			1,959		9		—		1,968		1,825		11		—		1,836
U.S. Treasury Securities (non-interest bearing)			3,960		81		—		4,041		3,077		56		—		3,133
	Debt Securities	$	7,931	$	128	$	—	$	8,059	$	6,784	$	73	$	—	$	6,857

      The following long-term debt securities are included in Other Assets at December 31, 2002 and 2001:

		2002								2001
				Gross		Gross						Gross		Gross
		Amortized		Unrealized		Unrealized		Fair		Amortized		Unrealized		Unrealized		Fair
		Cost		Gains		Losses		Value		Cost		Gains		Losses		Value
		(In thousands)
Corporate Debt Securities		$	13,968	$	939	$	—	$	14,907	$	16,025	$	838	$	—	$	16,863
Government Agency Debt Securities							—				1,964		90		—		2,054
U.S. Treasury Notes			1,972		237		—		2,209		1,972		167		—		2,139
U.S. Treasury Securities (non-interest bearing)			62,224		17,068		—		79,292		61,792		9,023		—		70,815
	Debt Securities	$	78,164	$	18,244	$	—	$	96,408	$	81,753	$	10,118	$	—	$	91,871

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      The contractual maturities of debt securities at December 31, 2002, are shown below. Actual maturities may differ from contractual maturities because borrowers may have the right to call or prepay obligations with or without call or prepayment penalties.

		Amortized
		Cost		Fair Value
		(In thousands)
Due within one year		$	7,931	$	8,059
Due after one year through five years			30,436		34,206
Due after five years through ten years			26,947		34,127
Due after ten years			20,781		28,075
	Total debt securities	$	86,095	$	104,467

5.  Property, Plant and Equipment, Net, and Capitalized Interest

      As of December 31, 2002 and 2001, the components of property, plant and equipment, are stated at cost less accumulated depreciation and depletion as follows (in thousands):

	2002			2001
Buildings, machinery, and equipment	$	10,290,931		$	5,321,339
Oil and gas properties, including pipelines		2,031,026			1,888,777
Geothermal properties		402,643			378,838
Other		182,901			119,285
		12,907,501			7,708,239
Less: accumulated depreciation and depletion		(1,220,094	)		(745,265	)
		11,687,407			6,962,974
Land		82,158			80,506
Construction in progress		7,077,015			8,283,550
Property, plant and equipment, net	$	18,846,580		$	15,327,030

      Total depreciation and depletion expense for the years ended December 31, 2002, 2001 and 2000 was $459.4 million, $298.4 million and $177.2 million, respectively.

      Buildings, Machinery, and Equipment — This component includes electric power plants and related equipment. Depreciation is recorded utilizing the straight-line method over the estimated original composite useful life, generally 35 years for power plants, exclusive of the estimated salvage value, typically 10%. Peaking facilities are generally depreciated over 40 years, less the estimated salvage value of 10%. The Company capitalizes the costs for major gas turbine generator refurbishment and amortizes them over their estimated useful lives of generally 3 to 6 years. Additionally, the Company expenses annual planned maintenance.

      Oil and gas properties — The Company follows the successful efforts method of accounting for oil and natural gas activities. Under the successful efforts method, lease acquisition costs and all development costs are capitalized. Proved oil and gas properties are reviewed for potential impairment when circumstances suggest the need for such a review and, if required, the proved properties are written down to their estimated fair value. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploratory costs are expensed as incurred. Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated or until the projects are substantially complete and ready for their intended use if the projects are evaluated as successful. The provision for depreciation, depletion, and amortization is based on the capitalized costs as determined above, plus future abandonment costs net of salvage value, using the units of production method with lease

F-22

acquisition costs amortized over total proved reserves and other costs amortized over proved developed reserves.

      Geothermal Properties — The Company capitalizes costs incurred in connection with the development of geothermal properties, including costs of drilling wells and overhead directly related to development activities, together with the costs of production equipment, the related facilities and the operating power plants at such time as management determines that it is probable the property will be developed on an economically viable basis and that costs will be recovered from operations. Proceeds from the sale of geothermal properties are applied against capitalized costs, with no gain or loss recognized.

      Geothermal costs, including an estimate of future costs to be incurred, costs to optimize the productivity of the assets, and the estimated costs to dismantle, are amortized by the units of production method based on the estimated total productive output over the estimated useful lives of the related steam fields. Depreciation of the buildings and roads is computed using the straight-line method over their estimated useful lives. It is reasonably possible that the estimate of useful lives, total unit-of-production or total capital costs to be amortized using the units-of-production method could differ materially in the near term from the amounts assumed in arriving at current depreciation expense. These estimates are affected by such factors as the ability of the Company to continue selling electricity to customers at estimated prices, changes in prices of alternative sources of energy such as hydro-generation and gas, and changes in the regulatory environment. Geothermal steam turbine generator refurbishments are expensed as incurred.

      Construction in Progress — Construction in progress 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.

      As of December 31, 2002, the Company has classified $142.4 million of equipment costs as other assets, as the equipment is not required for the Company’s current power plant development program. During the year, the Company has recorded a $404.7 million charge to equipment cancellation and impairment charges to effect a reduction in the carrying value of such equipment. The Company currently anticipates that some of this equipment will be used for future power plants and some may be sold to third parties. The Company restructured contracts for certain of its remaining gas turbines and steam turbines in the fourth quarter of 2002 (See Note 26). The Company may also, subject to market conditions, take steps to further adjust or restructure turbine orders, including canceling additional turbine orders, consistent with the Company’s power plant construction and development programs.

      Capitalized Interest — The Company capitalizes interest on capital invested in projects during the advanced stages of development and the construction period in accordance with SFAS No. 34, “Capitalization of Interest Cost,” as amended by SFAS No. 58, “Capitalization of Interest Cost in Financial Statements That Include Investments Accounted for by the Equity Method (an Amendment of FASB Statement No. 34).” The Company’s qualifying assets include construction in progress, certain oil and gas properties under development, construction costs related to unconsolidated investments in power projects under construction, and advanced stage development costs. For the years ended December 31, 2002, 2001 and 2000, the total amount of interest capitalized was $575.5 million, $498.7 million and $207.0 million, including $114.2 million, $136.0 million and $36.0 million, respectively, of interest incurred on funds borrowed for specific construction projects and $461.3 million, $362.7 million and $171.0 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 increase in the amount of interest capitalized during the year ended December 31, 2002, reflects the increase in the Company’s power plant construction program. However, the Company expects that the amount of interest capitalized will decrease in future periods as the power plants in construction are completed and as a result of the current suspension of certain of the Company’s development projects.

      In accordance with SFAS No. 34, the Company determines which debt instruments best represent a reasonable measure of the cost of financing construction assets in terms of interest cost incurred that otherwise

F-23

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 $600.0 million and the $400.0 million revolving credit facilities.

6.  Goodwill and Other Intangible Assets

      On January 1, 2002, the Company adopted SFAS No. 142, “Goodwill and Other Intangible Assets,” which requires that all intangible assets with finite useful lives be amortized and that goodwill and intangible assets with indefinite lives not be amortized, but rather tested upon adoption and at least annually for impairment. The Company was required to complete the initial step of a transitional impairment test within six months of adoption of SFAS No. 142 and to complete the final step of the transitional impairment test by the end of the fiscal year. Any future impairment losses will be reflected in operating income or loss in the consolidated statements of operations. The Company completed both the transitional goodwill impairment test and the first annual goodwill impairment test as required and determined that the fair value of the reporting units with goodwill exceeded their net carrying values. Therefore, the Company did not record any impairment expense.

      In accordance with the standard, the Company discontinued the amortization of its recorded goodwill as of January 1, 2002, identified reporting units based on its current segment reporting structure and allocated all recorded goodwill, as well as other assets and liabilities, to the reporting units. A reconciliation of previously reported net income and earnings per share to the amounts adjusted for the exclusion of goodwill amortization is provided below (in thousands, except per share amounts):

		2002		2001		2000
Reported income before discontinued operations and cumulative effect of accounting changes		$	59,145	$	587,419	$	332,803
	Add: Goodwill amortization		—		629		29
Pro forma income before discontinued operations and cumulative effect of accounting changes			59,145		588,048		332,832
Discontinued operations and cumulative effect of accounting changes, net of tax			59,473		36,073		36,281
	Pro forma net income	$	118,618	$	624,121	$	369,113
Basic earnings per share
	As reported	$	0.33	$	2.05	$	1.31
	Pro forma		0.33		2.06		1.31
Diluted earnings per share
	As reported	$	0.33	$	1.80	$	1.18
	Pro forma		0.33		1.80		1.18

      Recorded goodwill, by segment, as of December 31, 2002 and December 31, 2001, was (in thousands):

		December 31,		December 31,
		2002		2001
Electric Generation and Marketing		$	—	$	—
Oil and Gas Production and Marketing			—		—
Corporate, Other and Eliminations		$	29,165		23,924
	Total	$	29,165	$	23,924

      The increase in goodwill during 2002 is due to a $5.2 million contingent payment that the Company paid based on certain performance incentives met by PSM under the terms of the PSM purchase agreement. Should PSM continue to meet the performance objectives, annual contingent payments of $5.2 million will be made in 2003-2005, each of which will increase the goodwill balance. Subsequent goodwill impairment tests will be performed, at a minimum, in December of each year, in conjunction with the Company’s annual reporting process.

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      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		As of December 31, 2002					As of December 31, 2001
		Average
		Useful Life/		Carrying		Accumulated			Carrying		Accumulated
		Contract Life		Amount		Amortization			Amount		Amortization
Patents			5	$	485	$	(231	)	$	485	$	(134	)
Power sales agreements			14		156,814		(106,227	)		156,814		(86,352	)
Fuel supply and fuel management contracts			26		22,198		(4,105	)		22,198		(3,216	)
Geothermal lease rights			20		19,518		(350	)		19,493		(250	)
Steam purchase agreement			14		5,201		(486	)		—		—
Other			5		320		(71	)		277		(25	)
	Total			$	204,536	$	(111,470	)	$	199,267	$	(89,977	)

      Amortization expense of other intangible assets was $21.5 million, $23.9 million and $22.8 million, in 2002, 2001 and 2000, respectively. Assuming no future impairments of these assets or additions as the result of acquisitions, annual amortization expense will be $5.3 million in 2003, $4.9 million in 2004, $4.8 million in 2005, $4.8 million in 2006, and $4.8 million in 2007.

7.  Acquisitions

      The Company seeks to acquire power generating facilities and certain oil and gas properties that provide significant potential for revenue, cash flow and earnings growth, and that provide the opportunity to enhance the operating efficiency of its plants. Acquisition activity is dependent on the availability of financing on attractive terms and the expectation of returns that meets the Company’s long-term requirements. The following material mergers and acquisitions were consummated during the years ended December 31, 2001 and 2000. There were no mergers or acquisitions consummated during the year ended December 31, 2002. All business combinations were accounted for as purchases, with the exception of the Encal pooling-of-interests transaction. For all business combinations accounted for as purchases, the results of operations of the acquired companies were incorporated into the Company’s Consolidated Financial Statements commencing on the date of acquisition.

Encal Transaction

      On April 19, 2001, the Company completed its merger with Encal, a Calgary, Alberta-based natural gas and petroleum exploration and development company. Encal shareholders received, in exchange for each share of Encal common stock, 0.1493 shares of Calpine common equivalent shares (called “exchangeable shares”) of the Company’s subsidiary, Calpine Canada Holdings Ltd. A total of 16,603,633 exchangeable shares were issued to Encal shareholders in exchange for all of the outstanding shares of Encal common stock. Each exchangeable share is exchangeable for one share of Calpine common stock. The aggregate value of the transaction was approximately US$1.1 billion, including the assumed indebtedness of Encal. The transaction was accounted for as a pooling-of-interests and, accordingly, all historical amounts reflected in the Consolidated Financial Statements have been restated to reflect the transaction in accordance with APB Opinion No. 16, “Business Combinations” (“APB 16”). Encal operated under the same fiscal year end as Calpine, and accordingly, Encal’s balance sheet as of December 31, 2000, and the statements of operations, shareholders’ equity and cash flows for the fiscal year ended December 31, 2000, have been combined with the Company’s Consolidated Financial Statements. The Company incurred $41.6 million in nonrecurring merger costs for this transaction. Upon completion of the acquisition, the Company gained approximately 664 billion cubic feet equivalent of proved natural gas reserves, net of royalties. This transaction also provided access to firm gas transportation capacity from western Canada to California and the eastern U.S., and an accomplished

F-25

management team capable of leading the Company’s business expansion in Canada. In addition, Encal had proved undeveloped acreage totaling approximately 1.2 million acres.

Hidalgo Transaction

      On March 30, 2000, the Company purchased a 78.5% interest in the 502-megawatt Hidalgo Energy Center (“Hidalgo”) which was under construction in Edinburg, Texas, from Duke Energy North America for $235.0 million. The purchase included a cash payment of $134.0 million and the assumption of a $101.0 million capital lease obligation. The Hidalgo Energy Center sells power into the Electric Reliability Council of Texas’ (“ERCOT”) wholesale market. Construction of the facility began in February 1999 and commercial operation was achieved in June 2000.

KIAC and Stony Brook Transaction

      On May 31, 2000, Calpine acquired the remaining 50% interests in the 105-megawatt Kennedy International Airport Power Plant (“KIAC”) in Queens, New York and the 40-megawatt Stony Brook Power Plant located at the State University of New York at Stony Brook on Long Island from Statoil Energy, Inc. The Company paid approximately $71.0 million in cash and assumed a capital lease obligation relating to the Stony Brook Power Plant and an operating lease obligation relating to the KIAC Power Plant. The Company initially acquired a 50% interest in both facilities in December 1997.

Freestone Transaction

      On June 15, 2000, the Company announced that it had acquired the Freestone Energy Center (“Freestone”) from Energy Corporation. Freestone is a 1,052-megawatt natural gas-fired energy center under development in Freestone County, Texas. The Company paid approximately $61.0 million in cash and assumed certain liabilities. This represented payment for the land and development rights for the Freestone Energy Center, previous progress payments made for four General Electric gas turbines, two steam turbines and related equipment, and development expenditures.

Auburndale Transaction

      On June 30, 2000, the Company acquired from Edison Mission Energy the remaining 50% ownership interest in a 153-megawatt natural gas-fired, combined-cycle cogeneration facility located in Auburndale, Fla. The Company paid approximately $22.0 million in cash and assumed certain liabilities, including project level debt. The Company acquired an initial 50% ownership interest in the Auburndale Power Plant in October 1997.

Natural Gas Reserves Transactions

      On July 5, 2000, the Company completed the acquisitions of natural gas reserves for $206.5 million, including the acquisition of Calgary-based Quintana Minerals Canada Corp. (“QMCC”), three fields in the Gulf of Mexico and natural gas assets in the Piceance Basin, Colorado and onshore Gulf Coast. The Company subsequently changed QMCC’s name to Calpine Canada Natural Gas, Ltd. (“CCNG”).

Oneta Transaction

      On July 20, 2000, the Company completed the acquisition of the 1,138-megawatt natural gas-fired Oneta Energy Center, (“Oneta”) in Coseta, Oklahoma, from Panda Energy International, Inc. for total proceeds of $22.9 million, consisting of $20.1 million of cash and $2.8 million of a forgiven note receivable.

SkyGen Energy Transaction

      On October 12, 2000, the Company completed the acquisition of Northbrook, Illinois-based SkyGen Energy LLC (“SkyGen”) from Michael Polsky and Wisvest Corporation (“Wisvest”), an affiliate of Wisconsin Energy Corp., for a total purchase price of $359.1 million. The purchase price included cash payments of $294.2 million and 2,117,742 shares of Calpine common stock (which were valued in the aggregate at $64.9 million at signing of the letter of intent). Additionally, the purchase agreement provided for

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contingent consideration not to exceed $200.0 million upon perfection of certain earnout projects, which were perfected during 2001 and resulted in payments of $195.3 million.

TriGas Transaction

      On November 15, 2000, the Company acquired TriGas Exploration Inc. (“TriGas”), a Calgary-based oil and gas company, for a total purchase price of $101.1 million. The purchase price included cash payments of $79.6 million, as well as assumed net indebtedness of $21.5 million. The acquisition provided Calpine with natural gas reserves to fuel its Calgary Energy Centre, and a 26.6% working interest in the East Crossfield Gas Plant, a majority interest in 63 miles of pipeline that conducts the gas to two nearby gas-fired power generation facilities, and a significant undeveloped land base with development potential.

PSM Transaction

      On December 13, 2000, the Company completed the acquisition of Boca Raton, Florida-based PSM for a total purchase price of $16.3 million. The purchase price included cash payments of $5.6 million and 281,189 shares of Calpine common stock (which were valued in the aggregate at $10.7 million at the closing of the agreement). The Company recorded goodwill initially valued at $19.0 million, prior to subsequent contingent payments and amortization taken during 2001. Prior to the adoption of SFAS No. 142, the goodwill was being amortized over a 20-year life. Additionally, the agreement provides for five equal installments of cash payments, totaling $26.7 million, beginning in January 2002, contingent upon future PSM performance. PSM specializes in the design and manufacturing of turbine hot section blades, vanes, combustors and low emissions combustion components.

EMI Transaction

      On December 15, 2000, the Company completed the acquisition of strategic power assets from Dartmouth, Massachusetts-based Energy Management, Inc. (“EMI”) for a total purchase price of $145.0 million. The purchase price included cash payments of $100.0 million and 1,102,601 shares of Calpine common stock (which were valued in the aggregate at $45.0 million at the closing of the agreement). Under the terms of the agreement, the Company acquired the remaining interest in three recently constructed combined-cycle power generating facilities located in Dighton, Massachusetts, Tiverton, Rhode Island, and Rumford, Maine, as well as Calpine-EMI Marketing LLC, a joint marketing venture between Calpine and EMI.

Saltend Transaction

      On August 24, 2001, the Company acquired a 100% interest in and assumed operations of the Saltend Energy Centre (“Saltend”), a 1,200-megawatt natural gas-fired power plant located at Saltend near Hull, Yorkshire, England. The Company purchased the cogeneration facility from an affiliate of Entergy Corporation for £560.4 million (US$811.3 million at exchange rates at the closing of the acquisition). Saltend began commercial operation in November 2000 and is one of the largest natural gas-fired electric power generating facilities in England.

Hog Bayou and Pine Bluff Transactions

      On September 12, 2001, the Company purchased the remaining 33.3% interests in the 247-megawatt Hog Bayou Energy Center (“Hog Bayou”) and the 213-megawatt Pine Bluff Energy Center (“Pine Bluff”) from Houston, Texas-based InterGen (North America), Inc. for approximately $9.6 million and $1.4 million of a forgiven note receivable.

Westcoast Transaction

      On September 20, 2001, the Company’s wholly owned subsidiary, Canada Power Holdings Ltd., acquired and assumed operations of two Canadian power generating facilities from British Columbia-based Westcoast Energy Inc. (“Westcoast”) for C$325.2 million (US$207.0 million at exchange rates at the closing of the

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acquisition). The Company acquired a 100% interest in the Island Cogeneration facility (“Island”), a 250-megawatt natural gas-fired electric generating facility then in the commissioning phase of construction and located near Campbell River, British Columbia on Vancouver Island. The Company also acquired a 50% interest in the 50-megawatt Whitby Cogeneration facility (“Whitby”) located in Whitby, Ontario.

California Energy General Corporation and CE Newburry, Inc. Transaction

      On October 16, 2001, the Company acquired 100% of the voting stock of California Energy General Corporation (“California Energy”) and CE Newburry, Inc. (“CE Newburry”) from MidAmerican Energy Holdings Company for $22.0 million. The transaction included geothermal resource assets, contracts, leases and development opportunities associated with the Glass Mountain Known Geothermal Resource Area (“Glass Mountain KGRA”) located in Siskiyou County, California, approximately 30 miles south of the Oregon border. These purchases were directly related to the Company’s plans to develop the 49.5-megawatt Fourmile Hill Geothermal Project located in the Glass Mountain KGRA.

Michael Petroleum Transaction

      On October 22, 2001, the Company completed the acquisition of 100% of the voting stock of Michael Petroleum Corporation (“Michael”), a natural gas exploration and production company, for cash of $314.0 million, plus the assumption of $54.5 million of debt. The acquired assets consisted of approximately 531 wells, producing approximately 33.5 net mmcfe/day of which 90 percent is gas, and developed and non-developed acreage totaling approximately 82,590 net acres at year end.

Delta, Metcalf and Russell City Transactions

      On November 6, 2001, the Company acquired Bechtel Enterprises Holdings, Inc.’s 50% interest in the 874-megawatt Delta Energy Center (“Delta”), the 600-megawatt Metcalf Energy Center (“Metcalf”) and the 600-megawatt Russell City Energy Center (“Russell City”) for approximately $154.0 million and the assumption of approximately $141.0 million of debt. As a result of this acquisition, the Company now owns a 100% interest in all three projects.

      The initial purchase price allocation for all material business combinations initiated after June 30, 2001, the effective date of SFAS No. 141, is shown below. As of December 31, 2001, the Company had not finalized the purchase price allocation for Saltend, Michael, or Westcoast. The allocations for the three acquisitions were subsequently completed during 2002, and the final allocations and the allocations as reported at December 31, 2001, are shown below (in thousands):

Final Purchase Price Allocation

					Michael
		Saltend			Petroleum			Westcoast
Current assets		$	16,725		$	5,970		$	14,390
Property, plant and equipment			908,204			532,145			200,514
Other assets			9,523			—			—
Investments in power plants			—			—			26,000
Current liabilities			(21,900	)		(16,852	)		(7,932	)
Derivative liability			—			(1,862	)		—
Notes payable			—			(54,500	)		—
Other long-term liability			(8,045	)		—			—
Deferred tax liabilities, net			(93,230	)		(150,944	)		(25,947	)
	Net purchase price	$	811,277		$	313,957		$	207,025

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Initial Purchase Price Allocation

					Michael
		Saltend			Petroleum			Westcoast
Current assets		$	27,363		$	5,970		$	4,468
Property, plant and equipment			906,801			535,007			212,902
Other assets			1,478			—			—
Investments in power plants			—			—			25,907
Current liabilities			(21,900	)		(16,852	)		(6,802	)
Derivative liability			—			(1,862	)		—
Notes payable			—			(54,500	)		—
Deferred tax liabilities, net			(95,671	)		(151,946	)		(24,408	)
	Net purchase price	$	818,071		$	315,817		$	212,067

      The $6.8 million decrease in the net purchase price of Saltend occurred primarily due to a $10.1 million working capital adjustment that was paid to the Company during 2002. This reduction was partially offset by a $4.0 million adjustment to reflect a previously unrecorded receivable held by Saltend as a result of liquidated damages Saltend owed for delays in achieving commercial operations during 2000.

      The $5.0 million decrease in the net purchase price of Westcoast occurred primarily due to a performance adjustment payment to the Company to compensate for certain plant specifications that were not met of $3.4 million and a $4.2 million compensation payment for the loss of certain tax pools that were previously represented to be held by Westcoast and were used in part to help determine the original purchase price. Both amounts were paid to the Company during 2002. These reductions were partially offset by a working capital adjustment of $2.4 million that the Company paid during 2002.

Pro Forma Effects of Acquisitions

      Acquired subsidiaries are consolidated upon acquisition. The table below reflects the Company’s unaudited pro forma combined results of operations for all business combinations during 2001, as if the acquisitions had taken place at the beginning of fiscal year 2001. The Company’s combined results include the effects of Saltend, Hog Bayou, Pine Bluff, Island, Whitby, California Energy, CE Newburry, Michael, Highland, Delta, Metcalf, and Russell City (in thousands, except per share amounts):

	2001
Total revenue	$	6,966,753
Income before discontinued operations and cumulative effect of accounting changes	$	588,856
Net income	$	624,929
Net income per basic share	$	2.06
Net income per diluted share	$	1.80

      In management’s opinion, these unaudited pro forma amounts are not necessarily indicative of what the actual combined results of operations might have been if the 2001 acquisitions had been effective at the beginning of fiscal year 2001. In addition, they are not intended to be a projection of future results and do not reflect all the synergies that might be achieved from combined operations.

8.  Sale/Leaseback Transactions

      In 2001 the Company completed the following sale/leaseback transactions, which resulted in operating leases. All counterparties in the sale/leaseback transactions are unrelated to the Company. In connection with these transactions, the Company recorded deferred gains (losses) which are being amortized as a reduction of (addition to) operating lease expense over the respective remaining lives of the leases.

F-29

      On September 30, 2001, the Company completed a leveraged lease financing transaction of its Aidlin project. Under the terms of the agreement, the facility was incorporated into the Company’s geothermal lease facility, which the Company originally entered into on May 7, 1999. The Company received $29.0 million in gross proceeds and recorded a deferred gain of approximately $6.8 million.

      On October 18, 2001, the Company completed leveraged lease financing transactions for the South Point and RockGen facilities raising $500.0 million in gross proceeds, resulting in a deferred gain of approximately $21.1 million. In connection with these transactions, Calpine Corporation provided a guarantee for the obligations of its subsidiaries under the leases. The lessors raised a significant portion of the capital necessary to fund this transaction by issuing pass through trust certificates with an aggregate principal amount of $654.5 million. A portion of the pass through trust certificates was used to fund the Broad River Energy Center financing. See Note 16 for more information regarding the Broad River financing, which prior to the restatement described in Note 2, was accounted for as a sale/leaseback operating lease. In effect, the pass through certificates evidence the debt component of these sale/ leaseback transactions. The pass through certificates were issued in two tranches: the first, consisting of $454.5 million in aggregate principal amount of 8.4% Series A Certificates due May 30, 2012, and the second, consisting of $200.0 million in aggregate principal amount of 9.825% Series B Certificates due May 30, 2019.

      The transactions involving South Point and RockGen utilize special-purpose entities formed by the lessor with the sole purpose of owning a power generation facility. The Company is not the owner of the SPE nor does the Company have any direct or indirect ownership interest in each respective SPE; therefore the SPEs are appropriately not consolidated as subsidiaries of the Company.

9.  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			December 31,
		December 31,
		2002			2002		2001
Acadia Power Plant			50.0	%	$	282,634	$	228,728
Grays Ferry Power Plant			40.0	%		42,322		43,601
Aries Power Plant			50.0	%		30,936		26,133
Gordonsville Power Plant			50.0	%		20,892		21,687
Lockport Power Plant(1)			11.4	%		—		15,919
Whitby Cogeneration			50.0	%		33,502		25,848
Other			—			11,116		5,374
	Total investments in power projects				$	421,402	$	367,290

(1)  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.

F-30

      The combined unaudited results of operations and financial position of the Company’s equity method affiliates are summarized below (in thousands):

		December 31,
		2002		2001		2000
Condensed statements of operations:
	Revenue	$	372,212	$	401,452	$	617,914
	Gross profit		151,784		148,476		217,777
	Income from continuing operations		132,911		102,904		161,852
	Net income		70,596		87,003		80,812
Condensed balance sheets:
	Current assets	$	133,801	$	125,376
	Non-current assets		1,740,056		1,359,548
	Total assets	$	1,873,857	$	1,484,924
	Current liabilities	$	132,516	$	144,583
	Non-current liabilities		946,383		687,645
	Total liabilities	$	1,078,899	$	832,228

      The debt on the books of the unconsolidated power projects is not reflected on the Company’s balance sheet. At December 31, 2002, investee debt is approximately $639.3 million. Based on the Company’s pro rata ownership share of each of the investments, the Company’s share would be approximately $238.6 million. However, all such debt is non-recourse to the Company.

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

		Income (loss) from Unconsolidated
		Investments in Power Projects								Distributions
		For the Years Ended December 31,
		2002			2001			2000		2002		2001		2000
Grays Ferry Power Plant		$	(1,499	)	$	594		$	4,737	$	—	$	—	$	4,500
Lockport Power Plant			1,570			5,562			4,391		—		4,351		3,752
Gordonsville Power Plant			5,763			4,453			4,514		2,125		825		2,950
Acadia Energy Center			14,590			—			—		11,969		—		—
Aries Power Plant			(43	)		—			—		—		—		—
Whitby Cogeneration			411			684			—		—		637		—
Other			(4,302	)		(1,139	)		10,327		23		170		18,777
	Total	$	16,490		$	10,154		$	23,969	$	14,117	$	5,983	$	29,979
Interest income on loans to power projects(1)		$	62		$	6,792		$	4,827
	Total	$	16,552		$	16,946		$	28,796

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

(1)  At December 31, 2002 and 2001, loans to power projects represented an outstanding loan to the Company’s 32.3% owned investment, Androscoggin Energy Center LLC, in the amount of $3.1 million. Androscoggin Energy Center LLC is included in the “Other” category throughout this note.

      In the fourth quarter of 2002 income from unconsolidated investments was reclassified out of total revenue and are presented as a component of other income from operations. Prior periods have also been reclassified accordingly.

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10.  Notes Receivable

      The long-term notes receivable are recorded by discounting expected future cash flows using current interest rates at which similar loans would be made to borrowers with similar credit ratings and remaining maturities. The Company intends to hold these notes to maturity.

      As of December 31, 2002, and December 31, 2001, the components of notes receivable were (in thousands):

		December 31,			December 31,
		2002			2001
PG&E (Gilroy) note		$	163,584		$	117,698
Panda note			30,818			30,818
Other			9,555			21,833
	Total notes receivable		203,957			170,349
Less: Notes receivable, current portion			(8,559	)		(12,225	)
Notes receivable, net of current portion		$	195,398		$	158,124

      Calpine Gilroy Cogen, LP (“Gilroy”) had a long-term power purchase agreement (“PPA”) with Pacific Gas and Electric Company (“PG&E”) for the sale of energy through 2018. The terms of the PPA provided for 120 megawatts of firm capacity and up to 10 megawatts of as-delivered capacity. On December 2, 1999, the California Public Utilities Commission approved the restructuring of the PPA between Gilroy and PG&E. Under the terms of the restructuring, PG&E and Gilroy are each released from performance under the PPA effective November 1, 2002. Under the restructured contract, in addition to the normal capacity revenue for the period, Gilroy has earned from September 1999 to October 2002 restructured capacity revenue it would have earned over the November 2002 through March 2018 time period, for which PG&E has issued notes to the Company. These notes will be paid by PG&E during the period from February 2003 to September 2014. The first scheduled note repayment of $1.7 million was received in February 2003. See Note 23 for additional discussion of transactions with PG&E.

      In June 2000 the Company entered into a series of turbine sale contracts with and acquired the development rights to construct, own and operate the Oneta Energy Center from a subsidiary of Panda Energy International, Inc (“Panda”). As part of the transaction, Panda was extended a loan from the Company bearing an interest rate of LIBOR plus 5%. The loan is collateralized by Panda’s carried interest in the income generated from the Oneta Energy Center, which has achieved partial commercial operations. The loan, while due in December 2003, is classified as a long-term receivable as of December 31, 2002, due to the probability that repayment may be delayed by a slow down in full completion of the Oneta facility.

11.  Canadian Income Trust

      On August 29, 2002, the Company announced it had completed a Cdn$230 million (US$147.5 million) initial public offering of its Canadian income trust fund — Calpine Power Income Fund (the “Fund”). The 23 million Trust Units issued to the public were priced at Cdn$10 per unit, to initially yield 9.35% per annum. The Fund indirectly owns interests in two of Calpine’s Canadian power generating assets, the Island Cogeneration Facility, and the Calgary Energy Centre, which is under construction, and has a loan to a Calpine subsidiary which owns Calpine’s other Canadian power generating asset, the Whitby cogeneration plant. Combined, these assets represent approximately 550 net megawatts of power generating capacity.

      On September 20, 2002, the syndicate of underwriters fully exercised the over-allotment option that it was granted as part of the initial public offering of Trust Units and acquired 3,450,000 additional Trust Units of the Fund at Cdn$10 per Trust Unit, generating Cdn$34.5 million (US$21.9 million).

      The Company intends to retain a substantial subordinated equity interest and an operating and management role in the Calpine Power Income Fund and the Fund assets and, accordingly, has control, therefore, the financial results of the Fund are consolidated in the Company’s financial statements. At

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December 31, 2002, the Company held 49% of the Fund’s authorized Trust Units. The proceeds from the public offering of Trust Units were recorded as minority interests in the Company’s balance sheet. See Subsequent Events (Note 29) for a description of the Company’s secondary offering of Warranted Units in February 2003.

12.  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 Financial Statements as of December 31, 2002:

Corporate and Other

      In June 2003, the Company approved 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 divestiture on July 31, 2003.

Oil and Gas Production and Marketing

      On August 29, 2002, the Company completed the sale of certain non-strategic oil and gas properties (“Medicine River properties”) located in central Alberta to NAL Oil and Gas Trust and another institutional investor for Cdn$125.0 million (US$80.1 million). As a result of the sale, the Company recorded a pre-tax gain of $21.9 million.

      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. The Company used approximately US$50.4 million of cash proceeds to repay amounts outstanding under its US$1.0 billion term loan. See Note 18 for more information about the specific debt securities delivered to the Company as a result of this transaction.

      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.

Electric Generation and Marketing

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

Summary

      The Company made reclassifications to current and prior period financial statements to reflect the sale or designation as ‘held for sale’ of these oil and gas and power plant assets and liabilities and to separately classify the operating results of the assets sold and gain on sale of those assets from the operating results of continuing operations.

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      The tables below present significant components of the Company’s income from discontinued operations for 2002, 2001 and 2000, respectively (in thousands):

	2002
	Electric		Oil and Gas
	Generation		Production		Corporate and
	and Marketing		and Marketing		Other			Total
Total revenue	$	16,915	$	76,486	$	7,653		$	101,054
Gain on disposal before taxes	$	35,840	$	59,288	$	—		$	95,128
Operating income from discontinued operations before taxes		5,253		16,181		(16,968	)		4,466
Income from discontinued operations before taxes	$	41,093	$	75,469	$	(16,968	)	$	99,594
Gain on disposal, net of tax	$	21,377	$	35,153	$	—		$	56,530
Operating income from discontinued operations, net of tax		3,465		9,531		(10,053	)		2,943
Income from discontinued operations, net of tax	$	24,842	$	44,684	$	(10,053	)	$	59,473

	2001
	Electric		Oil and Gas
	Generation		Production		Corporate and
	and Marketing		and Marketing		Other			Total
Total revenue	$	17,113	$	140,040	$	6,864		$	164,017
Gain on disposal before taxes	$	—	$	—	$	—		$	—
Operating income from discontinued operations before taxes		2,520		70,375		(1,869	)		71,026
Income from discontinued operations before taxes	$	2,520	$	70,375	$	(1,869	)	$	71,026
Gain on disposal, net of tax	$	—	$	—	$	—		$	—
Operating income from discontinued operations, net of tax		1,544		34,601		(1,108	)		35,037
Income from discontinued operations, net of tax	$	1,544	$	34,601	$	(1,108	)	$	35,037

	2000
	Electric		Oil and Gas
	Generation		Production		Corporate and
	and Marketing		and Marketing		Other		Total
Total revenue	$	7,178	$	133,599	$	—	$	140,777
Gain on disposal before taxes	$	—	$	—	$	—	$	—
Operating income from discontinued operations before taxes		818		66,917		—		67,735
Income from discontinued operations before taxes	$	818	$	66,917	$	—	$	67,735
Gain on disposal, net of tax	$	—	$	—	$	—	$	—
Operating income from discontinued operations, net of tax		484		35,797		—		36,281
Income from discontinued operations, net of tax	$	484	$	35,797	$	—	$	36,281

F-34

      The table below presents the assets and liabilities held for sale on the Company’s balance sheet as of December 31, 2002 and December 31, 2001, respectively:

		December 31, 2002								December 31, 2001
		Electric		Oil and Gas						Electric		Oil and Gas
		Generation		Production		Corporate and				Generation		Production		Corporate and
		and Marketing		and Marketing		Other		Total		and Marketing		and Marketing		Other		Total
Current assets of discontinued operations		$	—	$	—	$	2,005	$	2,005	$	—	$	9,484	$	3,367	$	12,851
Long-term assets of discontinued operations			—		—		11,630		11,630		74,415		257,665		31,363		363,443
	Total assets of discontinued operations	$	—	$	—	$	13,635	$	13,635	$	74,415	$	267,149	$	34,730	$	376,294
Current liabilities of discontinued operations		$	—	$	—	$	1,962	$	1,962	$	—	$	12,059	$	2,798	$	14,857
Long-term liabilities of discontinued operations			—		—		19		19		7,488		—		72		7,560
	Total liabilities of discontinued operations	$	—	$	—	$	1,981	$	1,981	$	7,488	$	12,059	$	2,870	$	22,417

      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 is required to repay under the terms of its $1.0 billion term loan. In 2002, 2001 and 2000, the Company allocated interest expense of $6.2 million, $4.5 million, and $3.9 million, respectively, to its discontinued operations.

13.  Notes Payable and Borrowings Under Lines of Credit and Term Loan

      The components of notes payable and borrowings under lines of credit and related outstanding letters of credit are (in thousands):

						Letters of Credit
		Borrowings Outstanding				Outstanding
		December 31,				December 31,
		2002		2001		2002		2001
Corporate term loan		$	949,565	$	—	$	—	$	—
Corporate revolving lines of credit			340,000		—		573,899		373,224
Michael Petroleum note payable			—		64,750		—		250
Other			8,952		33,238		—		10,810
	Total notes payable and borrowings under lines of credit and term loan	$	1,298,517	$	97,988	$	573,899	$	384,284
Less: notes payable and borrowings under lines of credit, current portion, and term loan			340,703		23,238
Notes payable and borrowings under lines of credit, net of current portion, and term loan		$	957,814	$	74,750

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      In March 2002, the Company closed a new secured credit agreement which at that point was comprised of (a) a $1.0 billion revolving credit facility expiring on May 24, 2003 and (b) a two-year term loan facility for up to $600.0 million. In May 2002, the term loan facility was subsequently increased to $1.0 billion through a term of May 10, 2004, while the amount of the revolving credit facility was decreased to $600.0 million. Any letters of credit issued under the $600.0 million revolving credit facility on or prior to May 24, 2003 can be extended for up to one year at our option so long as they expire no later than five business days prior to the maturity date of the term-loan facility.

      As part of the March 2002 closings, the Company also amended its existing $400.0 million unsecured revolving credit agreement to provide, among other things, security for borrowings under that agreement. The $400.0 million revolving credit facility matures on May 23, 2003.

      Security for the $400.0 million and $600.0 million revolving credit facilities as well as the $1.0 billion term loan facility originally included (a) a pledge of the capital stock of the Company’s subsidiaries holding, directly or indirectly (i) the interests in the Company’s U.S. natural gas properties, (ii) the Saltend power plant located in the United Kingdom and (iii) the Company’s equity investment in nine U.S. power plants, and (b) a pledge by certain of the Company’s subsidiaries of a total of 65% of the capital stock of Calpine Canada Energy Ltd., the direct or indirect parent company of all of our Canadian subsidiaries, including those holding all of our Canadian natural gas properties.

      As part of the initial funding of the term loan in May 2002, the Company expanded the security for the revolving credit and term loan facilities by pledging to the lenders substantially all of the Company’s remaining first tier domestic subsidiaries, excluding CES. At the time, the security also included direct liens on the Company’s domestic natural gas properties.

      At December 31, 2002, the Company had $949.6 million in funded borrowings outstanding under the term loan facility, and $340.0 million in funded borrowings and $573.9 million outstanding in letters of credit under its two revolving credit facilities. At December 31, 2001, the Company had no outstanding borrowings and $373.2 million outstanding in letters of credit under its $400.0 million revolving credit facility.

      Borrowings bear variable interest and interest is paid on the last day of each interest period for such loans, at least quarterly. The term loan and credit facilities specify that the Company maintain certain covenants, with which the Company was in compliance as of December 31, 2002 and 2001. Commitment fees related to the revolving lines of credit are charges based on unused credit amounts. The interest rate on the term loan was 5.2% at December 31, 2002; and the interest rate on this facility ranged from 5.2% to 7.5% during 2002. The interest rate on the $600.0 million revolving credit facility was 4.7% at December 31, 2002; and the interest rate on this facility ranged from 4.6% to 6.8% during 2002. The interest rate on the $400.0 million revolving credit facility was 3.9% at December 31, 2002; and the interest rate on this facility ranged from 3.8% to 5.8% during 2002, and from 5.5% to 8.0% during 2001.

      As part of the Company’s acquisition of Michael Petroleum Corporation (“MPC”) through its wholly owned subsidiary Calpine Natural Gas Company, the Company assumed a $75.0 million three-year revolving credit facility with Bank One, N.A. and other banks. Amounts outstanding under the facility bore variable interest. The interest rate ranged from 4.3% to 5.0% during 2002. The line of credit was secured by the Company’s oil and gas properties. The Company was out of compliance as of December 31, 2001, with a covenant under the loan agreement. Subsequent to December 31, 2001, the Company initiated the process to obtain a waiver for the covenant but chose to instead repay the outstanding balance under the loan agreement. On March 13, 2002, the Company repaid the Michael Petroleum note payable, which had a balance of $64.8 million at repayment.

14.  Capital Lease Obligations

      During 2000 and 2001 the Company assumed and consolidated capital leases in conjunction with certain acquisitions. As of December 31, 2002 and 2001, the asset balances for the leased assets totaled $201.1 million and $200.5 million, respectively, with accumulated amortization of $20.4 million and $11.1 million, respectively. The primary types of property leased by the Company are power plants and related equipment.

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The leases generally provide for the lessee to pay taxes, maintenance, insurance, and certain other operating costs of the leased property. The lease terms range from 13 to 28 years.

      The following is a schedule by years of future minimum lease payments under capital leases together with the present value of the net minimum lease payments as of December 31, 2002, (in thousands):

Year Ending December 31:
	2003		$	19,010
	2004			19,231
	2005			19,328
	2006			19,947
	2007			20,018
	Thereafter			304,039
		Total minimum lease payments		401,573
Less: Amount representing interest(1)				200,466
	Present value of net minimum lease payments		$	201,107
Less: Capital lease obligation, current portion				3,454
	Capital lease obligation, net of current portion		$	197,653

(1)  Amount necessary to reduce net minimum lease payments to present value calculated at the incremental borrowing rate at the time of acquisition.

15.  Zero-Coupon Convertible Debentures

      On April 30, 2001, the Company completed the sale of $1.0 billion of Zero-Coupon Convertible Debentures Due 2021 (“Zero Coupons”) in a private placement under Rule 144A of the Securities Act of 1933.

      In December 2001 the Company repurchased $122.0 million in aggregate principal amount of its Zero Coupons in open-market purchases at a discount, and recorded a pre-tax gain of $11.9 million after the write-off of related financing costs. In January and February 2002 the Company repurchased an additional $192.5 million of its Zero Coupons at a discount and recorded a pre-tax gain of $3.5 million, after the write-off of related financing costs. On April 30, 2002, the Company repurchased the remaining $685.5 million in aggregate principal amount of its Zero Coupons at par pursuant to a scheduled put provided for by the terms of the Zero Coupons.

      The effective interest rate, after amortization of deferred financing costs, was 2.5% in 2002, and 2.3% in 2001.

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16.  Construction/ Project Financing

      The components of construction/project financing as of December 31, 2002 and 2001, are (in thousands):

						Letters of Credit
						Outstanding at
		Outstanding at December 31,				December 31,
Projects		2002		2001		2002		2001
Calpine Construction Finance Company		$	970,110	$	967,576	$	29,890	$	18,600
Calpine Construction Finance Company II			2,469,642		2,425,834		3,224		57,303
Pasadena Cogeneration, L.P.(1)			388,867		387,085		—		—
Broad River Energy LLC(1)			300,974		300,000		—		—
Siemens Westinghouse Power Corporation			169,180		—		—		—
Blue Spruce Energy Center LLC			83,540		—		—		—
Peaker Financing			50,000		—		—		—
Calpine Newark, Inc.			50,000		—		—		—
Calpine Parlin Inc.			37,000		—				—
	Total		4,519,313		4,080,495	$	33,114	$	75,903
Less: current portion			1,307,291		—
Long-term project financing		$	3,212,022	$	4,080,495

(1)  See Note 2 for information regarding this transaction.

      In November 1999 the Company entered into a credit agreement for $1.0 billion through its wholly owned subsidiary Calpine Construction Finance Company L.P. with a consortium of banks. The lead arranger was The Bank of Nova Scotia and the lead arranger syndication agent was Credit Suisse First Boston. The non-recourse credit facility is utilized to finance the construction of certain of the Company’s gas-fired power plants currently under development. The Company currently intends to refinance this construction facility prior to its four-year maturity in November 2003. As of December 31, 2002, the Company had $970.1 million in borrowings outstanding under the facility. Borrowings under this facility bear variable interest. The credit facility specifies that the Company maintain certain covenants, with which the Company was in compliance as of December 31, 2002. The interest rate at December 31, 2002 and 2001, was 2.9% and 3.4%, respectively. The interest rate ranged from 2.9% to 5.5% during 2002.

      In October 2000 the Company entered into a credit agreement for $2.5 billion through its wholly owned subsidiary Calpine Construction Finance Company II, LLC with a consortium of banks. The lead arrangers were The Bank of Nova Scotia and Credit Suisse First Boston. The non-recourse credit facility is utilized to finance the construction of certain of the Company’s gas-fired power plants currently under development. The Company currently intends to refinance or extend this construction facility prior to its four-year maturity in November 2004. As of December 31, 2002, the Company had $2.5 billion in borrowings outstanding under the facility. Borrowings under this facility bear variable interest. The credit facility specifies that the Company maintain certain covenants, with which the Company was in compliance as of December 31, 2002. The interest rate at December 31, 2002 and 2001, was 2.9% and 3.7%, respectively. The interest rate ranged from 2.9% to 5.5% during 2002.

      In September 2000, the Company completed the financing for both Phase I and Phase II of the Pasadena, Texas cogeneration project. Under the terms of the project financing, the Company received $400.0 million in gross proceeds. At December 31, 2002, the Company had $388.9 million in borrowings outstanding which mature in 2048. The interest rate at December 31, 2002 was 8.6%.

      In October 2001, the Company completed the financing for the Broad River Energy Center in South Carolina. Under the terms of the project financing, the Company received $300.0 million in gross proceeds. At

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December 31, 2002, the Company had $301.0 million in borrowings outstanding which mature in 2041. The interest rate at December 31, 2002 was 8.1%.

      On January 31, 2002, the Company’s subsidiary, Calpine Construction Management Company, Inc., entered into an agreement with Siemens Westinghouse Power Corporation to reschedule the production and delivery of gas and steam turbine generators and related equipment. Under the agreement, the Company obtained vendor financing of up to $232.0 million bearing variable interest for gas and steam turbine generators and related equipment. The financing is due prior to the earliest of the equipment site delivery date specified in the agreement, the Company’s requested date of turbine site delivery or June 25, 2003. At December 31, 2002, there was $169.2 million in borrowings outstanding under this agreement. The interest rate at December 31, 2002, was 6.6%. The interest rate ranged from 6.6% to 7.6% during 2002.

      On May 14, 2002, the Company’s subsidiary, Calpine California Energy Finance, LLC, entered into an $100.0 million amended and restated credit agreement with ING Capital LLC for the funding of 9 California peaker facilities, of which $100.0 million was drawn on May 24, 2002 and $50.0 million was repaid on August 7, 2002. At December 31, 2002, there was $50.0 million outstanding under this agreement. The interest rate at December 31, 2002, was 4.0%. The interest rate ranged from 4.0% to 5.8% during 2002. The Company has classified this financing as current as it is expected to be retired in 2003.

      On August 22, 2002, the Company completed a $106.0 million non-recourse project financing for the construction of its 300-megawatt Blue Spruce Energy Center. At December 31, 2002, the Company had $83.5 million in funded borrowings under this non-recourse construction and term-loan facility. The interest rate at December 31, 2002, was 6.3%. The interest rate ranged from 6.3% to 10.2% during 2002. This project financing will mature in 2008.

      In December 2002 the Company completed a $50.0 million project financing secured by the Newark Power Plant. At December 31, 2002, the Company had $50.0 million in funded borrowings under this project financing. The interest rate at December 31, 2002, was 10.6%. This project financing will mature in 2014.

      In December 2002 the Company completed a $37.0 million project financing secured by the Parlin Power Plant. At December 31, 2002, the Company had $37.0 million in funded borrowings under this project financing. The interest rate at December 31, 2002, was 9.8%. This project financing will mature in 2010.

17.  Convertible Senior Notes Due 2006

      In December 2001 and January 2002 the Company completed the issuance of $1.2 billion in aggregate principal amount of 4% Convertible Senior Notes Due 2006 (“Convertible Senior Notes”). These securities are convertible, at the option of the holder, into shares of Calpine common stock at a price of $18.07. Holders have the right to require the Company to repurchase all or a portion of the Convertible Senior Notes on December 26, 2004, at 100% of their principal amount plus any accrued and unpaid interest. The Company has the right to repurchase the convertible senior notes with cash, shares of Calpine common stock, or a combination of cash and stock.

      The effective interest rate on these notes, after amortization of deferred financing costs, was approximately 4.9% in 2002 and 4.4% in 2001.

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18.  Senior Notes

      Senior Notes payable consist of the following as of December 31, 2002 and 2001, (in thousands):

											(3)
											Fair Value as of
							December 31,				December 31,
		Interest		First Call
		Rates		Date			2002		2001		2002		2001
Senior Notes Due 2004			9 1/4%		1999		$	—	$	—	$	—	$	—
Senior Notes Due 2005			8 1/4%			(2)		249,420		249,197		117,227		223,032
Senior Notes Due 2006			10 1/2%		2001			171,750		171,750		82,440		163,163
Senior Notes Due 2006			7 5/8%			(1)		249,821		249,821		107,423		221,092
Senior Notes Due 2007			8 3/4%		2002			275,107		275,112		118,296		244,849
Senior Notes Due 2007			8 3/4%			(2)		125,782		124,568		55,973		110,866
Senior Notes Due 2008			7 7/8%			(1)		379,689		399,094		155,672		355,194
Senior Notes Due 2008			8 1/2%			(2)		2,027,859		2,027,455		892,258		1,774,023
Senior Notes Due 2008			8 3/8%			(2)		183,509		155,868		67,898		143,399
Senior Notes Due 2009			7 3/4%			(1)		329,593		349,810		135,133		304,335
Senior Notes Due 2010			8 5/8%			(2)		707,036		749,174		304,025		655,527
Senior Notes Due 2011			8 1/2%			(2)		1,875,571		1,996,081		806,496		1,756,551
Senior Notes Due 2011			8 7/8%			(2)		319,664		288,531		115,079		259,677
	Total						$	6,894,801	$	7,036,461	$	2,957,920	$	6,211,708

(1)	Not redeemable prior to maturity.
(2)	Redeemable at any time prior to maturity.
(3)	Represents the market values of the Senior Notes at the respective dates.

      The Company has completed a series of public debt offerings since 1994. Interest is payable semiannually at specified rates. Deferred financing costs are amortized on a straight-line basis, which approximates the effective interest method, over the respective lives of the notes. There are no sinking fund or mandatory redemptions of principal before the maturity dates of each offering. Certain of the Senior Note indentures limit the Company’s ability to incur additional debt, pay dividends, sell assets and enter into certain transactions. As of December 31, 2002, the Company was in compliance with all debt covenants relating to the Senior Notes. The effective interest rates for each of the Company’s Senior Notes outstanding at December 31, 2002, are consistent with the respective notes outstanding during 2001, unless otherwise noted.

      During the third quarter of 2001, the Company borrowed a total of $1.2 billion under three bridge credit facilities (which ranked equally with Senior Notes) to finance several acquisitions. These facilities were refinanced with the October 2001 issuance of long-term Senior Notes. The Company recorded a pre-tax loss of $1.0 million, related to the write off of unamortized deferred financing costs.

      In October 2002, $88.4 million was paid by Pengrowth Corporation’s purchase in the open market and delivery to the Company of $203.2 million in aggregate principal amount of certain of the Company’s Senior Notes. The Company recorded a pre-tax gain, net of write-off of unamortized deferred financing costs, of US$114.8 million related to these purchases. See Note 12 for more details regarding this transaction.

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      The following debt securities were delivered to the Company by Pengrowth Corporation (in millions):

Debt Security		Principal Amount
7 7/8% Senior Notes Due 2008		$	19.6
7 3/4% Senior Notes Due 2009			20.2
8 5/8% Senior Notes Due 2010			42.3
8 1/2% Senior Notes Due 2011			121.1
	Total	$	203.2

Senior Notes Due 2004

      Interest on these notes is payable semi-annually on February 1 and August 1 each year. The notes, which would have matured on February 1, 2004, were redeemable, at the option of the Company, at any time on or after February 1, 1999, at various redemption prices. The effective interest rate, after amortization of deferred financing costs, was 9.6% per annum. On June 7, 2001, the Company redeemed all $105.0 million principal amount of the Senior Notes Due 2004 for 100% of the principal amount plus accrued interest to the redemption date. The Company recorded a pre-tax loss of $1.3 million, in connection with this redemption.

Senior Notes Due 2005

      Interest on these notes is payable semi-annually on February 15 and August 15. The notes mature on August 15, 2005, or may be redeemed at any time prior to maturity at a redemption price equal to 100% of their principal amount plus accrued and unpaid interest plus a make-whole premium. The effective interest rate, after amortization of deferred financing costs, is 8.7% per annum.

Senior Notes Due 2006

      Interest on the 10 1/2% notes is payable semi-annually on May 15 and November 15 each year and the notes mature on May 15, 2006, or are redeemable, at the option of the Company, at any time on or after May 15, 2001, at various redemption prices. In addition, the Company may redeem up to $63.0 million of the Senior Notes Due 2006 from the proceeds of any public equity offering. The effective interest rate, after amortization of deferred financing costs, is 10.8% per annum.

      Interest on the 7 5/8% notes is payable semi-annually on April 15 and October 15 each year and the notes mature on April 15, 2006, and are not redeemable prior to maturity. The effective interest rate, after amortization of deferred financing costs, is 7.9% per annum.

Senior Notes Due 2007

      Interest on the $275.1 million principal senior notes is payable semi-annually on January 15 and July 15 each year. These notes mature on July 15, 2007, or are redeemable, at the option of the Company, at any time on or after July 15, 2002, at various redemption prices. In addition, the Company may redeem up to $96.3 million of the Senior Notes Due 2007 from the proceeds of any public equity offering. The effective interest rate, after amortization of deferred financing costs, is 9.1% per annum.

      Interest on the C$200.0 million (US$125.8 million as of December 31, 2002) Senior Notes Due 2007 is payable semi-annually on April 15 and October 15 each year. The Notes mature on October 15, 2007; however, they may be redeemed prior to maturity, at any time in whole or from time to time in part, at a redemption price equal to the greater of (a) the “Discounted Value” of the senior notes, which equals the sum of the present values of all remaining scheduled payments of principal and interest, or (b) 100% of the principal amount plus accrued and unpaid interest to the redemption date. The Notes are fully and unconditionally guaranteed by the Company. The effective interest rate, after amortization of deferred financing costs and the effect of cross currency swaps, was 9.1% per annum.

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Senior Notes Due 2008

      Interest on the 7 7/8% notes is payable semi-annually on April 1 and October 1 each year. These notes mature on April 1, 2008, and are not redeemable prior to maturity. The effective interest rate, after amortization of deferred financing costs, is 8.0% per annum. The Notes are fully and unconditionally guaranteed by the Company.

      Interest on the 8 1/2% Senior Notes is payable semi-annually on May 1 and November 1 each year. The notes mature on May 1, 2008, or may be redeemed prior to maturity at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest plus a make-whole premium. The effective interest rate, after amortization of deferred financing costs, is 8.7% per annum at December 31, 2001, and 8.8% per annum at December 31, 2002.

      Interest on the 8 3/8% Senior Notes is payable semi- annually on April 15 and October 15 each year and the notes mature on October 15, 2008, or may be redeemed prior to maturity at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest plus a make-whole premium. The effective interest rate, after amortization of deferred financing costs and the effect of cross currency swaps, was 8.8% per annum at December 31, 2001, and 9.5% per annum at December 31, 2002.

Senior Notes Due 2009

      Interest on these notes is payable semi-annually on April 15 and October 15 each year. The notes mature on April 15, 2009, and are not redeemable prior to maturity. The effective interest rate, after amortization of deferred financing costs, is 7.9% per annum.

Senior Notes Due 2010

      Interest on these notes is payable semi-annually on August 15 and February 15 each year, and the notes mature on August 15, 2010, and may be redeemed at any time prior to maturity at a redemption price equal to 100% of their principal amount plus accrued and unpaid interest plus a make-whole premium. The effective interest rate, after amortization of deferred financing costs, is 8.8% per annum.

Senior Notes Due 2011

      Interest on the 8 1/2% Senior Notes is payable semi-annually on February 15 and August 15 each year, and the notes mature on February 15, 2011, and may be redeemed prior to maturity at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest plus a make-whole premium. The effective interest rate, after amortization of deferred financing costs, is 8.6% per annum at December 31, 2001, and 8.7% per annum at December 31, 2002.

      Interest on the 8 7/8% Senior Notes is payable semi-annually on April 15 and October 15 each year, and the notes mature on October 15, 2011, and may be redeemed prior to maturity at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest plus a make-whole premium. The effective interest rate, after amortization of deferred financing costs and the effect of cross currency swaps, was 9.3% per annum at December 31, 2001, and 8.9% per annum at December 31, 2002.

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Annual Debt Maturities and Minimum Sublease Rentals

      The annual principal maturities of notes payable and borrowings under lines of credit, project financing, Convertible Senior Notes Due 2006, senior notes and capital lease obligations as of December 31, 2002, are as follows (in thousands):

2003		$	1,651,448
2004			3,449,529
2005			277,075
2006			1,649,402
2007			441,192
Thereafter			6,645,092
	Total	$	14,113,738

      The Company intends to refinance or extend the maturity of the debt maturing in 2003. Other options include obtaining additional financing, further delaying its construction program to conserve cash, and selling assets. While the Company’s ability to refinance this indebtedness will depend, in part, on events beyond its control, the Company believes it will be successful in meeting its obligations on this debt.

      The Company has power sales agreements for the Broad River and Pasadena facilities that are accounted for as leases. The minimum sublease rentals to be received by the Company in connection with these agreements are $23.7 million, $24.1 million, $24.4 million, $24.7 million, and $25.1 million for the years 2003 through 2007, respectively. Minimum sublease rentals for 2008 and thereafter are $313.2 million.

19.  Trust Preferred Securities

      In 1999 and 2000 the Company, through its wholly owned subsidiaries, Calpine Capital Trust, Calpine Capital Trust II, and Calpine Capital Trust III, statutory business trusts created under Delaware law, (collectively, “the Trusts”) completed offerings of Remarketable Term Income Deferrable Equity Securities (“HIGH TIDES”) at a value of $50.00 per share.

											Conversion Ratio —
							Balance		Balance		Number of				Initial
					Interest		December 31,		December 31,		Common Shares		First Redemption		Redemption
	Issue Date		Shares		Rate		2002		2001		per 1 High Tide		Date		Price
High Tides I		October 1999		5,520,000		5.75%	$	268,608	$	268,346		3.4620		November 5, 2002		101.440%
High Tides II	January and February 2000			7,200,000		5.50%		351,499		351,177		1.9524		February 5, 2003		101.375%
High Tides III		August 2000		10,350,000		5.00%		503,862		503,401		1.1510		August 5, 2003		101.250%
				23,070,000			$	1,123,969	$	1,122,924

      The net proceeds from each of the offerings were used by the Trusts to invest in convertible subordinated debentures of the Company, which represent substantially all of the respective trusts’ assets. The Company has effectively guaranteed all of the respective trusts’ obligations under the trust preferred securities. The trust preferred securities have liquidation values of $50.00 per share, or $1.2 billion in total for all of the issuances. The Company has the right to defer the interest payments on the debentures for up to twenty consecutive quarters, which would also cause a deferral of distributions on the trust preferred securities. Currently, the Company has no intention of deferring interest payments on the debentures.

      The trust preferred securities are convertible into shares of the Company’s common stock at the holder’s option on or prior to the tender notification date. Additionally, the HIGH TIDES may be redeemed at any time on or after the initial redemption date. The redemption price declines to 100% during the one year following the initial redemption date.

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20.  Provision for Income Taxes

      The jurisdictional components of income (loss) before provision for income taxes at December 31, 2002, 2001, and 2000, are as follows (in thousands):

		2002			2001			2000
U.S.		$	102,852		$	920,756		$	529,486
International			(55,888	)		(33,910	)		34,768
	Income before provision for income taxes	$	46,964		$	886,846		$	564,254

      The provision (benefit) for income taxes for the years ended December 31, 2002, 2001, and 2000, consists of the following (in thousands):

				2002			2001			2000
Current:
	Federal			$	(39,402	)	$	183,533		$	214,169
	State				3,837			43,676			40,596
	Foreign				5,898			5,810			—
		Total Current			(29,667	)		233,019			254,765
Deferred:
	Federal				101,949			98,661			(34,011	)
	State				14,380			(16,863	)		(7,852	)
	Foreign				(98,843	)		(15,390	)		18,549
		Total Deferred			17,486			66,408			(23,314	)
			Total provision (benefit)	$	(12,181	)	$	299,427		$	231,451

      The Company’s effective rate for income taxes for the years ended December 31, 2002, 2001, and 2000, differs from the United States statutory rate, as reflected in the following reconciliation:

		2002			2001			2000
United States statutory tax rate			35.0	%		35.0	%		35.0	%
State income tax, net of federal benefit			25.2			2.0			3.8
Depletion and other permanent items			(0.2	)		0.0			0.0
Foreign tax at rates other than U.S. statutory			(85.9	)		(3.3	)		2.2
	Effective income tax rate		(25.9	)%		33.7	%		41.0	%

      The components of the deferred income taxes, net as of December 31, 2002 and 2001, are as follows (in thousands):

			2002			2001
Net operating loss and credit carryforwards			$	109,500		$	35,341
Taxes related to risk management activities and SFAS 133				103,604			66,549
Other differences				197,609			38,146
Valuation allowance				(26,665	)		—
	Deferred tax assets			384,048			140,036
Property differences				(1,321,445	)		(1,025,048	)
Other differences				(186,332	)		(66,845	)
	Deferred tax liabilities			(1,507,777	)		(1,091,893	)
		Net deferred income taxes	$	(1,123,729	)	$	(951,857	)

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      The net operating loss consists of federal and state carryforwards of $22.1 million which expire between 2004 and 2014. The federal and state net operating loss carryforwards available are subject to limitations on annual usage. We also have loss carryforwards in certain foreign subsidiaries, resulting in tax benefits of approximately $87.4 million, the majority of which expire by 2008. The Company has provided a valuation allowance to reduce deferred tax assets to the extent necessary to result in an amount that is more likely than not of being realized. Realization of the deferred tax assets and net operating loss carryforwards is dependent, in part, on generating sufficient taxable income prior to expiration of the loss carryforwards. The amount of the deferred tax asset considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carryforward period are reduced.

      The Company’s foreign subsidiaries had no cumulative undistributed earnings at December 31, 2002.

21.  Employee Benefit Plans

Retirement Savings Plan

      The Company has a defined contribution savings plan under Section 401(a) and 501(a) of the Internal Revenue Code. The plan provides for tax deferred salary deductions and after-tax employee contributions. Employees are immediately eligible upon hire. Contributions include employee salary deferral contributions and employer profit-sharing contributions of 3% of employees’ salaries up to $5,100 per year, made entirely in cash. Effective January 1, 2002, the Company increased its profit sharing contribution to 4% of employees’ salaries up to $8,000 per year. Employer profit-sharing contributions in 2002, 2001, and 2000 totaled $11.6 million, $6.9 million, and $2.9 million, respectively.

2000 Employee Stock Purchase Plan

      The Company adopted the 2000 Employee Stock Purchase Plan (“ESPP”) in May 2000. Eligible employees may in the aggregate purchase up to 12,000,000 shares of common stock at semi-annual intervals through periodic payroll deductions. Purchases are limited to a maximum value of $25,000 per calendar year based on the IRS code Section 423 limitation. Shares are purchased on May 31 and November 30 of each year until termination of the plan on May 31, 2010. Under the ESPP, 2,611,597 and 1,124,851 shares were issued at a weighted average fair value of $5.72 and $21.05 per share in 2002 and 2001, respectively. The purchase price is 85% of the lower of (i) the fair market value of the common stock on the participant’s entry date into the offering period, or (ii) the fair market value on the semi-annual purchase date.

1996 Stock Incentive Plan

      The Company adopted the 1996 Stock Incentive Plan (“SIP”) in September 1996. The SIP succeeded the Company’s previously adopted stock option program. The Company accounts for the SIP under APB Opinion No. 25, “Accounting for Stock Issued to Employees” under which no compensation cost has been recognized. See Note 3 for the effects the SIP would have on the Company’s financial statements if stock-based compensation was accounted for under SFAS No. 123.

      For the year ended December 31, 2002, the Company had granted options to purchase 8,997,720 shares of common stock. Over the life of the SIP, options exercised have equaled 4,362,064, leaving 24,712,390 granted and not yet exercised. Under the SIP, the option exercise price generally equals the stock’s fair market value on date of grant. The SIP options generally vest ratably over four years and expire after 10 years.

      In connection with the merger with Encal, the Company adopted Encal’s existing stock option plan. All outstanding options under the Encal stock option plan were converted at the time of the merger into options to purchase Calpine stock. No new options may be granted under the Encal stock option plan.

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      Changes in options outstanding, granted, exercisable and canceled during the years 2002, 2001, and 2000, under the option plans of Calpine and Encal were as follows:

									Weighted
			Available for			Outstanding			Average
			Option or			Number of			Exercise
			Award			Options			Price
Outstanding January 1, 2000				5,183,284			30,965,589			3.11
	Additional shares reserved			2,522,157			—			—
		Granted		(4,429,289	)		4,429,289			23.08
		Exercised		—			(4,533,946	)		1.85
		Cancelled		188,871			(188,871	)		17.52
Outstanding December 31, 2000				3,465,023			30,672,061			6.09
	Additional shares reserved			2,837,150			—			—
		Granted		(3,034,014	)		3,034,014			42.89
		Exercised		—			(5,745,505	)		8.64
		Cancelled		270,006			(270,006	)		34.20
		Cancelled options available for award(1)		(682,216	)		—			—
Outstanding December 31, 2001				2,855,949			27,690,564		$	9.32
	Additional shares reserved			15,070,588
		Granted		(8,997,720	)		8,997,720			7.20
		Exercised		—			(5,113,485	)		0.77
		Cancelled		1,470,802			(1,470,802	)		26.53
		Cancelled options available for award(1)		(237,580	)		—			—
Outstanding December 31, 2002				10,162,039			30,103,997			9.30
Options exercisable:
	December 31, 2000						18,980,332			2.68
	December 31, 2001						18,642,381			3.81

(1)  Represents cessation of options awarded under the Encal stock option plan

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      The following tables summarizes information concerning outstanding and exercisable options at December 31, 2002:

			Weighted
			Average		Weighted				Weighted
	Number of		Remaining		Average		Number of		Average
	Options		Contractual		Exercise		Options		Exercise
Range of Exercise Prices	Outstanding		Life in Years		Price		Exercisable		Price
$ 0.570 - $ 0.615		3,088,464		1.97	$	0.597		3,088,464	$	0.597
$ 0.645 - $ 2.150		4,508,453		4.29		1.609		4,503,253		1.609
$ 2.195 - $ 2.250		1,698,900		4.29		2.249		1,698,900		2.249
$ 2.345 - $ 3.860		3,942,560		6.01		3.751		3,000,010		3.717
$ 4.010 - $ 5.240		3,642,367		9.39		5.172		209,511		4.441
$ 5.330 - $ 7.640		4,459,961		8.11		7.568		1,933,341		7.490
$ 7.750 - $13.850		3,789,893		6.83		10.599		2,246,128		10.001
$13.917 - $48.150		4,774,793		6.92		31.256		2,654,747		27.287
$48.188 - $56.920		196,606		8.23		51.428		82,243		51.412
$56.990 - $56.990		2,000		8.33		56.990		750		56.990
$ 0.570 - $56.990		30,103,997		6.22	$	9.299		19,417,347	$	7.140

22. Stockholders’ Equity

Common Stock

      Increase in Authorized Shares — On July 26, 2001, the Company filed amended certificates with the Delaware Secretary of State to increase the number of authorized shares of common stock to 1,000,000,000 from 500,000,000.

      Equity Offering — On August 9, 2000, Calpine completed a public offering of 23,000,000 shares of common stock at $34.75 per share. The gross proceeds from the offering were $799.3 million.

      On April 30, 2002, Calpine completed a registered offering of 66,000,000 shares of common stock at $11.50 per share. The proceeds from this offering, after underwriting fees, were $734.3 million.

Preferred Stock and Preferred Share Purchase Rights

      On June 5, 1997, Calpine adopted a stockholders’ rights plan to strengthen Calpine’s ability to protect Calpine’s stockholders. The plan was amended on September 19, 2001. The rights plan is designed to protect against abusive or coercive takeover tactics that are not in the best interests of Calpine or its stockholders. To implement the rights plan, Calpine declared a dividend of one preferred share purchase right for each outstanding share of Calpine’s common stock held on record as of June 18, 1997, and directed the issuance of one preferred share purchase right with respect to each share of Calpine’s common stock that shall become outstanding thereafter until the rights become exercisable or they expire as described below. On December 31, 2002, there were 380,816,132 rights outstanding. Each right initially represents a contingent right to purchase, under certain circumstances, one one-thousandth of a share, called a “unit,” of Calpine’s Series A Participating Preferred Stock, par value $.001 per share, at a price of $140.00 per unit, subject to adjustment. The rights become exercisable and trade independently from Calpine’s common stock upon the public announcement of the acquisition by a person or group of 15% or more of Calpine’s common stock, or ten days after commencement of a tender or exchange offer that would result in the acquisition of 15% or more of Calpine’s common stock. Each unit purchased upon exercise of the rights will be entitled to a dividend equal to any dividend declared per share of common stock and will have one vote, voting together with the common stock. In the event of Calpine’s liquidation, each share of the participating preferred stock will be entitled to any payment made per share of common stock.

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      If Calpine is acquired in a merger or other business combination transaction after a person or group has acquired 15% or more of Calpine’s common stock, each right will entitle its holder to purchase at the right’s exercise price a number of the acquiring company’s shares of common stock having a market value of twice the right’s exercise price. In addition, if a person or group acquires 15% or more of Calpine’s common stock, each right will entitle its holder (other than the acquiring person or group) to purchase, at the right’s exercise price, a number of fractional shares of Calpine’s participating preferred stock or shares of Calpine’s common stock having a market value of twice the right’s exercise price.

      The rights remain exercisable for up to 90 days following a triggering event (such as a person acquiring 15% or more of the Company’s common Stock). The rights expire on June 18, 2007, unless redeemed earlier by Calpine. Calpine can redeem the rights at a price of $.01 per right at any time before the rights become exercisable, and thereafter only in limited circumstances.

Comprehensive Income (Loss)

      Comprehensive income is the total of net income and all other non-owner changes in equity. Comprehensive income includes the Company’s net income, unrealized gains and losses from derivative instruments that qualify as cash flow hedges and the effects of foreign currency translation adjustments. The Company reports Accumulated Other Comprehensive Income (AOCI) in its consolidated balance sheet. The tables below detail the changes during 2002, 2001 and 2000 in the Company’s AOCI balance and the components of the Company’s comprehensive income (in thousands):

						Foreign			Total Accumulated
			Cash Flow			Currency			Other Comprehensive			Comprehensive
			Hedges(1)			Translation			Income (Loss)			Income (Loss)
Accumulated other comprehensive loss at January 1, 2000			$	—		$	(19,337	)	$	(19,337	)
Net income												$	369,084
	Foreign currency translation loss						(6,026	)		(6,026	)		(6,026	)
Total comprehensive income												$	363,058
Accumulated other comprehensive loss at December 31, 2000			$	—		$	(25,363	)	$	(25,363	)
Net income												$	623,492
	Cash flow hedges:
		Comprehensive pre-tax loss on cash flow hedges before reclassification adjustment	$	(171,400	)
		Reclassification adjustment for gain included in net income		(126,009	)
		Income tax benefit		116,590
				(180,819	)					(180,819	)		(180,819	)
	Foreign currency translation loss						(34,698	)		(34,698	)		(34,698	)
Total comprehensive income												$	407,975
Accumulated other comprehensive loss at December 31, 2001			$	(180,819	)	$	(60,061	)	$	(240,880	)

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						Foreign			Total Accumulated
			Cash Flow			Currency			Other Comprehensive			Comprehensive
			Hedges(1)			Translation			Income (Loss)			Income (Loss)
Net income												$	118,618
	Cash flow hedges:
		Comprehensive pre-tax gain on cash flow hedges before reclassification adjustment		96,905
		Reclassification adjustment for gain included in net income		(169,205	)
		Income tax benefit		28,705
				(43,595	)					(43,595	)		(43,595	)
	Foreign currency translation gain						47,018			47,018			47,018
Total comprehensive income												$	122,041
Accumulated other comprehensive loss at December 31, 2002			$	(224,414	)	$	(13,043	)	$	(237,457	)

(1)  Includes accumulated other comprehensive income (loss) from cash flow hedges held by unconsolidated investees. At December 31, 2002 and 2001, these amounts were $12,018 and $(1,984) respectively.

23. Customers

      In 2002, the California Department of Water Resources (“DWR”) was a significant customer and accounted for more than 10% of the Company’s annual consolidated revenues. In 2001, Enron was a significant customer. PG&E was a significant customer in 2001 as well as in 2000. Significant customers relate exclusively to the Electric Generation and Marketing segment, with the exception of $33.3 million from Enron, which was derived from Oil and Gas Production and Marketing in 2001.

      Revenues earned from the significant customers for the years ended December 31, 2002, 2001, and 2000, were as follows (in thousands):

	2002		2001		2000
Revenues:
DWR	$	754,191	$	*	$	*
PG&E(1)		*		723,062		624,458
Enron		*		1,671,737		*

      Receivables due from the significant customers at December 31, 2002 and 2001, were as follows (in thousands):

		2002		2001
Receivables:
PG&E Accounts Receivable(2)			*		46,545
PG&E Notes Receivable(3)			*		117,698
	PG&E Total	$	*	$	164,243
Enron Accounts Receivable		$	*	$	75,002
DWR		$	78,842	$	*

* Customer not significant in respective year.

(1)  See Note 28 for further discussion of the California energy situation.

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(2)	In addition to the accounts receivable shown in the table, the Company had a receivable of $224.2 million from the sale of the pre-bankruptcy petition PG&E receivables on December 31, 2001. This receivable was collected from an escrow account in January 2002.
(3)	Payments of the PG&E notes receivable are scheduled from February 2003 to September 2014. The first scheduled note repayment of $1.7 million was received in February 2003. See Note 10 for further discussion.

California Department of Water Resources

      In 2001, California adopted legislation permitting it to issue long-term revenue bonds to fund wholesale purchases of power by the DWR. The bonds will be repaid with the proceeds of payments by retail power customers over time. CES and DWR entered into four long-term supply contracts during 2001. The Company has recorded deferred revenue in connection with one of the long-term power supply contracts (Contract 3). All of the Company’s accounts receivables from DWR are current.

      In early 2002, the California Public Utilities Commission (“CPUC”) and the California Electricity Oversight Board (“EOB) filed complaints under Section 206 of the Federal Power Act with the Federal Energy Regulatory Commission (“FERC”) alleging that the prices and terms of the long-term contracts with DWR were unjust and unreasonable and contrary to the public interest (the “206 Complaint”). The contracts entered into by CES and DWR were subject to the 206 Complaint.

      On April 22, 2002, the Company announced that it had renegotiated CES’ long-term power contracts with DWR and settled the 206 Complaint. The Office of the Governor, the CPUC, the EOB and the Attorney General for the State of California all endorsed the renegotiated contracts and dropped all pending claims against the Company and its affiliates, including any efforts by the CPUC and the EOB to seek refunds from the Company and its affiliates through the FERC California Refund Proceedings. In connection with the renegotiation, the Company agreed to pay $6 million over three years to the Attorney General to resolve any and all possible claims. A summary of the material terms of the four DWR contracts, as renegotiated, follows:

      (1) Contract 1 provides for baseload power deliveries of 350 megawatts for 2002, 600 megawatts for 2003, and 1,000 megawatts for 2004 through 2009 at a fixed energy price of $58.60 per megawatt-hour. In addition, Calpine provides up to 2.7 million and 4.8 million megawatt hours of additional, flexible energy in 2002 and 2003, respectively; with energy pricing indexed to gas and a two-year fixed capacity payment.

      (2) Contract 2 provides for baseload power deliveries of 200 megawatts for the first half of 2002 and 1,000 megawatts from July 1, 2002 through 2009 at a fixed energy price of $59.60 per megawatt-hour. Calpine provides up to 1.7 million and 3.0 million megawatt hours of additional, flexible energy in 2002 and 2003, respectively; with energy pricing indexed to gas and a two-year fixed capacity payment. DWR has the right to complete four Calpine projects planned for California if Calpine does not meet certain milestones with respect to each project. However, if DWR exercises this right, DWR must reimburse Calpine for all construction costs and certain other costs incurred to date in connection with the project(s) being completed by DWR and this right has no effect on the prices, terms and conditions associated with the energy products being sold to DWR under Contract 2.

      (3) Contract 3 provides DWR with a 10-year option for 2,000 hours (annually) for 495 megawatts of peak power in exchange for fixed annual capacity payments of $90 million for years one through five and $80 million per year thereafter. If DWR exercises its option, the energy price paid is indexed to gas.

      (4) Contract 4 provides DWR up to 225 megawatts of new peaking capacity for a 3-year term, beginning with commercial operation of the Los Esteros Energy Center, for fixed annual average capacity payments and an energy price indexed to gas.

      California Electric Power Fund. In November 2002, the DWR completed the issuance of $11.3 billion in revenue bonds. Part of the proceeds from this bond issuance was used to fund the Electric Power Fund (the “Fund”), which will be used to meet DWR’s payment obligations under its long-term energy contracts. Revenue requirements for the repayment of the bonds will be determined at least annually and submitted to

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the CPUC. Under the terms of a Rate Agreement between the DWR and the CPUC, the CPUC is required to set rates for the customers of the State’s investor owned utilities (“IOUs”), such that the Fund will always have monies to retire the bonds when due. DWR is shifting certain power procurement responsibilities to the IOUs, other than those procurement obligations already committed under the terms of its long-term contracts, such as the four long-term contracts with CES discussed above. Ultimately, the financial responsibility for the long-term contracts may be transferred to the IOUs; such as, Pacific Gas and Electric Company; however, this will not occur until a number of issues are addressed, including IOU creditworthiness.

Enron

      During 2001 the Company, primarily through its CES subsidiary, transacted a significant volume of business with units of Enron, mainly Enron Power Marketing, Inc. (“EPMI”) and Enron North America Corp. (“ENA”). ENA is the parent corporation of EPMI. Enron is the direct parent corporation of ENA. Most of these transactions were contracts for sales and purchases of power and gas for hedging purposes, the terms of which extended out as far as 2009. On December 2, 2001, Enron Corp. and certain of its subsidiaries, including EPMI and ENA, filed voluntary petitions for Chapter 11 reorganization with the U.S. Bankruptcy Court for the Southern District of New York.

      The Company has conducted no business with EPMI or ENA since December 31, 2001. The Company has terminated all of its open forward positions with ENA and EPMI, and will settle with ENA and EPMI based on the value of the terminated contracts at the termination or replacement date, as applicable.

      On November 14, 2001, CES, ENA and EPMI entered into a Master Netting, Setoff and Security Agreement (the “Netting Agreement”). The Netting Agreement permits CES, on the one hand, and ENA and EPMI, on the other hand, to set off amounts owed to each other under an ISDA Master Agreement between CES and ENA, an Enfolio Master Firm Purchase/ Sale Agreement between CES and ENA and a Master Energy Purchase/ Sale Agreement between CES and EPMI (in each case, after giving effect to the netting provisions contained in each of these agreements).

      The Company reserved $17.9 million related to unrealized mark to market gains generated by Enron’s insolvency, which caused earnings recognition for contracts that had previously been exempted from SFAS No. 133 accounting and which caused cash flow hedges to cease to be effective and mark to market in earnings until termination.

      The Company believes, based on contractually permissible calculation methodologies, that its gross exposure to Enron and its affiliates will be significantly less than amounts previously disclosed during the year using calculations made under generally accepted accounting principles. The Company expects that this amount will be offset by CES’ losses, damages, attorneys’ fees and other expenses arising from the default by Enron.

      The Company is engaged in confidential settlement negotiations with Enron, ENA and EPMI. It is premature to characterize these negotiations at this time. In the event settlement negotiations prove unsuccessful, the Company intends to pursue its rights under its agreements with Enron and its affiliates. Regardless of the outcome, the Company believes, based upon legal analysis, that it does not have any net collection exposure to Enron and its affiliates as of the date hereof.

PG&E

      The Company’s northern California Qualifying Facility (“QF”) subsidiaries sell power to PG&E under the terms of long-term contracts at eleven facilities. On April 6, 2001, PG&E filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. PG&E is the regulated subsidiary of PG&E Corporation, and the information on PG&E disclosed herein excludes PG&E Corporation’s non-regulated subsidiary activity. The Company has transactions with certain of the non-regulated subsidiaries, which have not been affected by PG&E’s bankruptcy. On July 12, 2001, the U.S. Bankruptcy Court for the Northern District of California approved the agreement the Company had entered into with PG&E to modify and assume all of Calpine’s QF contracts with PG&E. Under the terms of the agreement, the Company will

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continue to receive its contractual capacity payments plus a five-year fixed energy price component that averages 5.37 cents per kilowatt-hour in lieu of the short run avoided cost. In addition, all past due receivables under the QF contracts were elevated to administrative priority status to be paid to the Company, with interest, upon the effective date of a confirmed plan of reorganization. On September 20, 2001, PG&E filed its proposed plan of reorganization with the bankruptcy court.

      As of April 6, 2001, the date of PG&E’s bankruptcy filing, the Company had recorded $265.6 million in accounts receivable with PG&E under the QF contracts, plus $68.7 million in notes receivable not yet due and payable. PG&E has paid currently for power delivered after April 6, 2001.

      In December 2001 the bankruptcy court approved an agreement between Calpine and PG&E providing that PG&E repay the $265.6 million in past due pre-petition receivables plus accrued interest ($10.3 million through December 31, 2001) thereon beginning on December 31, 2001, and with monthly payments thereafter over the next 11 months. Shortly following receipt of this bankruptcy court approval and the first payments from PG&E on December 31, 2001, the Company sold the remaining PG&E receivables to a third party at a $9.0 million discount. The cash for the sale of the receivables was collected in January 2002.

      CPUC Proceeding Regarding QF Contract Pricing for Past Periods. The Company’s QF contracts with PG&E provide that the CPUC has the authority to determine the appropriate utility “avoided cost” to be used to set energy payments for certain QF contracts by determining the short run avoided cost (“SRAC”) energy price formula. In mid 2000 the Company’s QF facilities elected the option set forth in Section 390 of the California Public Utility Code, which provides QFs the right to elect to receive energy payments based on the California Power Exchange (“PX”) market clearing price instead of the price determined by SRAC. Having elected such option, the Company was paid based upon the PX zonal day ahead clearing price (“PX Price”) from summer 2000 until January 19, 2001, when the PX ceased operating a day ahead market. The CPUC has conducted proceedings (R.99-11-022) to determine whether the PX Price was the appropriate price for the energy component upon which to base payments to QFs which had elected the PX-based pricing option. The CPUC at one point issued a proposed decision to the effect that the PX Price was the appropriate price for energy payments under the California Public Utility Code but tabled it, and a final decision has not been issued to date. Therefore, it is possible that the CPUC could order a payment adjustment based on a different energy price determination. The Company believes that the PX Price was the appropriate price for energy payments but there can be no assurance that this will be the outcome of the CPUC proceedings.

      The Company had a combined accounts receivable balance of $21.1 million as of December 31, 2002, from the California Independent System Operator Corporation (“CAISO”) and Automated Power Exchange, Inc. (“APX”). Of this balance, $9.4 million relates to past due balances prior to the PG&E bankruptcy filing. The Company expects that a portion of these past due receivables will be offset against refund obligations under FERC’s California Refund Proceedings (See Note 28) and the Company has provided a partial reserve for these past due receivables. CAISO’s ability to pay the Company is directly impacted by PG&E’s ability to pay CAISO. APX’s ability to pay the Company is directly impacted by PG&E’s ability to pay the PX, which in turn would pay APX for energy delivered by the Company through APX. As noted above, the PX ceased operating in January 2001. See Note 28 for an update on the FERC investigation into the western markets.

Nevada Power and Sierra Pacific Power Company

      During the first quarter of 2002, two subsidiaries of Sierra Pacific Resources Company, Nevada Power Company (“NPC”) and Sierra Pacific Power Company (“SPPC”), received credit downgrades to sub-investment grades from the major credit rating agencies. Additionally, NPC acknowledged liquidity problems created when the Public Utilities Commission of Nevada disallowed a rate adjustment requested by NPC to cover the increased cost of buying power during the 2001 energy crisis. NPC requested that its power suppliers extend payment terms to help it overcome its short-term liquidity problems. In June and July 2002 NPC underpaid the Company by approximately $4.2 million. In addition, NPC and SPPC filed a complaint with the Federal Energy Regulatory Commission (“FERC”) under Section 206 of the Federal Power Act — see Note 26 for further discussion. In September, 2002, NPC notified the Company of its intention to repay all

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outstanding payables owed to the Company for power deliveries made during the period of May 1, 2002 through September 15, 2002, following execution by the Company of an agreement to forebear from taking action against NPC provided NPC makes certain periodic payments. On October 25, 2002, the Company received approximately $22.2 million from NPC as repayment of past due amounts for power deliveries through September 15, 2002.

      As of December 31, 2002, the Company had net collection exposures of approximately $4.8 million and $3.7 million with NPC and SPPC, respectively, net of established reserve. Both NPC and SPPC are paying the Company currently. The Company’s exposures include open forward power contracts that are reported at fair value on the Company’s balance sheet as well as receivable and payable balances relating to prior power deliveries. Management is continuing to monitor the exposure and its effect on the Company’s financial condition. The table below details the components of the Company’s exposure position at December 31, 2002 (in millions of dollars). The positive net positions represent realization exposure while the negative net positions represent the Company’s existing or potential obligations.

		Receivables/Payables							Fair Values
							Net							Net Open
		Gross		Gross			Receivable		Gross Fair		Gross Fair			Positions
		Receivable		Payable			(Payable)		Value (+)		Value (-)			Value		Total
NPC		$	5.5	$	(4.4	)	$	1.1	$	6.4	$	(2.7	)	$	3.7	$	4.8
SPPC			3.7		—			3.7		—		—			—		3.7
	Total	$	9.2	$	(4.4	)	$	4.8	$	6.4	$	(2.7	)	$	3.7	$	8.5

      Under the terms of its contracts with NPC and SPPC, the Company believes that it has the right to offset asset and liability positions.

NRG Power Marketing, Inc.

      The Company has open contract positions with NRG Power Marketing, Inc., a subsidiary of NRG Energy, Inc., which in turn is the unregulated power-generation subsidiary of XCEL Energy Inc. Almost all of the open contracts are accounted for as cash flow hedges under SFAS No. 133. NRG Energy, Inc. has reported that it is experiencing financial problems, defaulted on certain loan payments and has had its long-term debt rating downgraded to D by Standard & Poor’s. According to a report published on November 8, 2002, NRG Energy, Inc. has discussed a Chapter 11 bankruptcy filing with its lenders. While NRG Power Marketing, Inc. has remained current in its payments to the Company, the Company has established partial reserves totaling $3.9 million offsetting revenue and Other Accumulated Comprehensive Loss. The Company will continue to closely monitor its position with NRG Power Marketing, Inc. and will adjust the value of the reserve as conditions dictate. The Company’s exposure, net of the established reserve, to NRG Power Marketing, Inc. at December 31, 2002, is summarized below (in millions):

	Receivables/Payables							Open Positions
						Net		Gross Fair		Gross Fair			Net Open
	Gross		Gross			Receivable		Value		Value			Positions
	Receivable		Payable			(Payable)		(+)		(-)			Value		Total
NRG Power Marketing, Inc	$	2.6	$	(0.4	)	$	2.2	$	5.2	$	(2.0	)	$	3.2	$	5.4

Aquila Merchant Services, Inc.

      On November 13, 2002 Aquila Inc. (“Aquila”), the parent of Aquila Merchant Services, Inc., (“AMS”), reported third quarter 2002 losses of approximately $332 million, suspended its dividend and disclosed that it had obtained debt covenant waivers expiring in April 2003 from certain of its lenders. The Company believes that a downgrade in Aquila’s credit rating could trigger additional collateral requirements under Aquila’s and AMS’s contractual commitments. The Company currently buys and sells electricity and natural gas from Aquila and AMS under a variety of contractual arrangements. The Company accounts for certain of its contractual arrangements with AMS as derivatives under SFAS No. 133 and, accordingly, record the fair value of the open positions under these contracts in the financial statements. The Company also has

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tolling arrangements with AMS on the Acadia facility and with Aquila on the Aries facility under which they deliver gas to, and purchase electricity from, the Company with 20 and 15.5 year terms, respectively. These tolling agreements are not subject to derivative accounting. While Aquila and AMS has remained current in its payments to the Company, the Company has established partial reserves totaling $2.6 million offsetting revenue and Other Accumulated Comprehensive Loss. The Company will continue to closely monitor its position with Aquila and AMS and will adjust the value of the reserve as conditions dictate. The Company’s exposure, net of the established reserve, to Aquila and AMS at December 31, 2002, is summarized below (in millions):

	Receivables/Payables								Open Positions
						Net			Gross Fair		Gross Fair			Net Open
	Gross		Gross			Receivable			Value		Value			Positions
	Receivable		Payable			(Payable)			(+)		(-)			Value		Total
AMS and Aquila	$	15.0	$	(26.9	)	$	(11.9	)	$	90.0	$	(38.0	)	$	52.0	$	40.1

      Among the long term power contracts the Company entered into in California in 2001, one had a 10.5 year term, and one had a five year term. Each contract was negotiated in early 2001, commenced on July 1, 2001, and provided for pricing at $115/megawatt-hour during the first six months which included the peak summer season of 2001 when natural gas costs were very high and blackouts were feared. The contracts then provided for a flat fixed price of $61.00 and $75.25, respectively, per megawatt-hour for the balance of the contract terms, when gas prices were expected to return to more normal levels. The Company concluded that each contract contained two separate elements (1. the six-month period in 2001; and 2. the period commencing January 1, 2002), and consequently the Company accounted for each element separately. Had the Company concluded that each contract contained only one element, the Company would have calculated an average price for the contract as a whole and recognized revenue on a straight-line basis. The impact of the latter approach would have been approximately $55 million less revenue ($36 million less net income) in 2001, and $55 million more revenue ($36 million more net income) in the aggregate over the balance of the contracts. Market circumstances were unique at the time these two contracts were executed, and accordingly, the Company does not anticipate that it will enter into contracts with similar characteristics in the future in which elements would be separated in the same manner.

Credit Evaluations

      The Company’s treasury department includes a credit group focused on monitoring and managing counterparty risk. The credit group monitors the net exposure with each counterparty on a daily basis. The analysis is performed on a mark-to-market basis using the forward curves analyzed by the Company’s Risk Controls group. The net exposure is compared against a counterparty credit risk threshold which is determined based on each counterparty’s credit rating and evaluation of the financial statements. The credit department monitors these thresholds to determine the need for additional collateral or restriction of activity with the counterparty.

24. Derivative Instruments

Commodity Derivative Instruments

      As an independent power producer primarily focused on generation of electricity using gas-fired turbines, the Company’s natural physical commodity position is “short” fuel (i.e., natural gas consumer) and “long” power (i.e., electricity seller). To manage forward exposure to price fluctuation in these and (to a lesser extent) other commodities, the Company enters into derivative commodity instruments. The Company enters into commodity instruments to convert floating or indexed electricity and gas (and to a lesser extent oil and refined product) prices to fixed prices in order to lessen its vulnerability to reductions in electric prices for the electricity it generates, to reductions in gas prices for the gas it produces, and to increases in gas prices for the fuel it consumes in its power plants. The Company seeks to “self-hedge” its gas consumption exposure to an extent with its own gas production position. Any hedging, balancing, or optimization activities that the Company engages in are directly related to the Company’s asset-based business model of owning and operating gas-fired electric power plants and are designed to protect the Company’s “spark spread” (the

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difference between the Company’s fuel cost and the revenue it receives for its electric generation). The Company hedges exposures that arise from the ownership and operation of power plants and related sales of electricity and purchases of natural gas, and the Company utilizes derivatives to optimize the returns the Company is able to achieve from these assets for the Company’s shareholders. From time to time the Company has entered into contracts considered energy trading contracts under EITF Issue No. 02-3. However, the Company’s traders have low capital at risk and value at risk limits for energy trading, and its risk management policy limits, at any given time, its net sales of power to its generation capacity and limits its net purchases of gas to its fuel consumption requirements on a total portfolio basis. This model is markedly different from that of companies that engage in significant commodity trading operations that are unrelated to underlying physical assets. Derivative commodity instruments are accounted for under the requirements of SFAS No. 133.

      The Company also routinely enters into physical commodity contracts for sales of its generated electricity and sales of its natural gas production to ensure favorable utilization of generation and production assets. Such contracts often meet the criteria of SFAS No. 133 as derivatives but are generally eligible for the normal purchases and sales exception. Some of those contracts that are not deemed normal purchases and sales can be designated as hedges of the underlying consumption of gas or production of electricity.

      In 2001 the FASB cleared SFAS No. 133 Implementation Issue No. C16 “Applying the Normal Purchases and Normal Sales Exception to Contracts That Combine a Forward Contract and a Purchased Option Contract” (“C16”). The guidance in C16 applies to fuel supply contracts that require delivery of a contractual minimum quantity of fuel at a fixed price and have an option that permits the holder to take specified additional amounts of fuel at the same fixed price at various times. Under C16, the volumetric optionality provided by such contracts is considered a purchased option that disqualifies the entire derivative fuel supply contract from being eligible to qualify for the normal purchases and normal sales exception in SFAS No. 133. On April 1, 2002, the Company adopted C16. At June 30, 2002, the Company had no fuel supply contracts to which C16 applies. However, one of the Company’s equity method investees has fuel supply contracts subject to C16. The equity investee also adopted C16 in April 2002. The contracts qualified as highly effective hedges of the equity method investee’s forecasted purchase of gas. Accordingly, the Company has recorded $7.8 million net of tax as a cumulative effect of change in accounting principle to other comprehensive income for its share of the equity method investee’s other comprehensive income from this accounting change.

Interest Rate and Currency Derivative Instruments

      The Company also enters into various interest rate swap agreements to hedge against changes in floating interest rates on certain of its project financing facilities. The interest rate swap agreements effectively convert floating rates into fixed rates so that the Company can predict with greater assurance what its future interest costs will be and protect itself against increases in floating rates.

      In conjunction with its capital markets activities, the Company enters into various forward interest rate agreements to hedge against interest rate fluctuations that may occur after the Company has decided to issue long-term fixed rate debt but before the debt is actually issued. The forward interest rate agreements effectively prevent the interest rates on anticipated future long-term debt from increasing beyond a certain level, allowing the Company to predict with greater assurance what its future interest costs on fixed rate long-term debt will be.

      The Company enters into various foreign currency swap agreements to hedge against changes in exchange rates on certain of its senior notes denominated in currencies other than the U.S. dollar. The foreign currency swaps effectively convert floating exchange rates into fixed exchange rates so that the Company can predict with greater assurance what its U.S. dollar cost will be for purchasing foreign currencies to satisfy the interest and principal payments on these senior notes.

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Summary of Derivative Values

      The table below reflects the amounts (in thousands) that are recorded as assets and liabilities at December 31, 2002, for the Company’s derivative instruments:

								Commodity
			Interest Rate			Currency		Derivative		Total
			Derivative			Derivative		Instruments		Derivative
			Instruments			Instruments		Net		Instruments
Current derivative assets			$	—		$	—	$	330,244	$	330,244
Long-term derivative assets				—			9,580		486,448		496,028
	Total assets		$	—		$	9,580	$	816,692	$	826,272
Current derivative liabilities			$	14,402		$	1,189	$	173,765	$	189,356
Long-term derivative liabilities				28,481			7,619		492,300		528,400
	Total liabilities		$	42,883		$	8,808	$	666,065	$	717,756
		Net derivative assets (liabilities)	$	(42,883	)	$	772	$	150,627	$	108,516

      At any point in time, it is highly unlikely that total net derivative assets and liabilities will equal accumulated OCI, net of tax from derivatives, for three primary reasons:

• Tax effect of OCI — When the values and subsequent changes in values of derivatives that qualify as effective hedges are recorded into OCI, they are initially offset by a derivative asset or liability. Once in OCI, however, these values are tax effected against a deferred tax liability or asset account, thereby creating an imbalance between net OCI and net derivative assets and liabilities.

• Derivatives not designated as cash flow hedges and hedge ineffectiveness — Only derivatives that qualify as effective cash flow hedges will have an offsetting amount recorded in OCI. Derivatives not designated as cash flow hedges and the ineffective portion of derivatives designated as cash flow hedges will be recorded into earnings instead of OCI, creating a difference between net derivative assets and liabilities and pre-tax OCI from derivatives.

• Termination of effective cash flow hedges prior to maturity — Following the termination of a cash flow hedge, changes in the derivative asset or liability are no longer recorded to OCI. At this point, an accumulated OCI balance remains that is not recognized in earnings until the forecasted initially hedged transactions occur. As a result, there will be a temporary difference between OCI and derivative assets and liabilities on the books until the remaining OCI balance is recognized in earnings.

      Below is a reconciliation of the Company’s net derivative assets to its accumulated other comprehensive loss, net of tax from derivative instruments at December 31, 2002 (in thousands):

Net derivative assets	$	108,516
Derivatives not designated as cash flow hedges and recognized hedge ineffectiveness		(180,814	)
Cash flow hedges terminated prior to maturity		(310,580	)
Deferred tax asset attributable to accumulated other comprehensive loss on cash flow hedges		145,294
Accumulated OCI from unconsolidated investees		12,018
Other reconciling items		1,152
Accumulated other comprehensive loss from derivative instruments, net of tax(1)	$	(224,414	)

(1)  Amount represents one portion of the Company’s total accumulated OCI balance. See Note 22 for further information.

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      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 December 31, 2002.

			December 31, 2002
			Gross		Net
Current derivative assets			$	1,287,034	$	330,244
Long-term derivative assets				1,022,279		486,448
	Total derivative assets		$	2,309,313	$	816,692
Current derivative liabilities			$	1,130,182	$	173,765
Long-term derivative liabilities				1,028,504		492,300
	Total derivative liabilities		$	2,158,686	$	666,065
		Net commodity derivative assets	$	150,627	$	150,627

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

      The tables below reflect the impact of the Company’s derivative instruments on its pre-tax earnings, both from cash flow hedge ineffectiveness and from the changes in market value of derivatives not designated as hedges of cash flows, for the years ended December 31, 2002 and 2001, respectively (in thousands):

		2002									2001
		Hedge			Undesignated						Hedge			Undesignated
		Ineffectiveness			Derivatives			Total			Ineffectiveness			Derivatives			Total
Natural gas derivatives(1)		$	2,147		$	(14,792	)	$	(12,645	)	$	(5,788	)	$	30,113		$	24,325
Power derivatives(1)			(4,934	)		12,974			8,040			1,866			96,402			98,268
Interest rate derivatives(2)			(810	)		—			(810	)		(1,330	)		(5,785	)		(7,115	)
	Total	$	(3,597	)	$	(1,818	)	$	(5,415	)	$	(5,252	)	$	120,730		$	115,478

(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 years ended December 31, 2002 and 2001, respectively (in thousands):

		2002			2001
Natural gas and crude oil derivatives		$	(119,419	)	$	(30,745	)
Power derivatives			304,073			163,228
Interest rate derivatives			(10,993	)		(6,474	)
Foreign currency derivatives			(4,456	)		—
	Total derivatives	$	169,205		$	126,009

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      As of December 31, 2002, the maximum length of time over which the Company was hedging its exposure to the variability in future cash flows for forecasted transactions was 8, 6, and 12 years, for commodity, foreign currency and interest rate derivative instruments, respectively. The Company estimates that pre-tax losses of $(113.6) million would be reclassified from accumulated OCI into earnings during the twelve months ended December 31, 2003, as the hedged transactions affect earnings assuming constant gas and power prices, interest rates, and exchange rates over time; however, the actual amounts that will be reclassified will likely vary based on the probability that gas and power prices as well as interest rates and exchange rates will, in fact, change. Therefore, management is unable to predict what the actual reclassification from OCI to earnings (positive or negative) will be for the next twelve months.

      The table below presents (in thousands) the pre-tax gains (losses) currently held in OCI that will be recognized annually into earnings, assuming constant gas and power prices, interest rates, and exchange rates over time.

														2007 &
		2003			2004			2005			2006			After			Total
Crude oil OCI		$	(510	)	$	—		$	—		$	—		$	—		$	(510	)
Gas OCI			(87,352	)		(37,929	)		(58,420	)		(20,441	)		3,374			(200,768	)
Power OCI			(2,003	)		(21,410	)		(21,055	)		(13,825	)		322			(57,971	)
Interest rate OCI			(22,474	)		(19,499	)		(15,179	)		(12,434	)		(33,672	)		(103,258	)
Foreign currency OCI			(1,228	)		(1,426	)		(1,355	)		(1,312	)		(1,881	)		(7,202	)
	Total pre-tax OCI	$	(113,567	)	$	(80,264	)	$	(96,009	)	$	(48,012	)	$	(31,857	)	$	(369,709	)

25. Earnings per Share

      Basic earnings per common share were computed by dividing net income by the weighted average number of common shares outstanding for the period. The dilutive effect of the potential exercise of outstanding options to purchase shares of common stock is calculated using the treasury stock method. The dilutive effect of the assumed conversion of certain convertible securities into the Company’s common stock is based on the dilutive common share equivalents and the after tax distribution expense avoided upon conversion. The reconciliation of basic earnings per common share to diluted earnings per share is shown in the following table (in thousands except per share data). All share data has been adjusted to reflect the two-for-one stock splits effective June 8, 2000, and November 14, 2000.

		For the Years Ended December 31,
		2002						2001						2000
		Net						Net						Net
		Income		Shares		EPS		Income		Shares		EPS		Income		Shares		EPS
Basic earnings per common share:
	Income before discontinued operations and cumulative effect of a change in accounting principle	$	59,145		354,822	$	0.16	$	587,419		303,522	$	1.93	$	332,803		281,084	$	1.18
	Discontinued operations, net of tax		59,473				0.17		35,037				0.12		36,281				0.13
	Cumulative effect of a change in accounting principle		—				—		1,036				—		—				—
	Net income	$	118,618		354,822	$	0.33	$	623,492		303,522	$	2.05	$	369,084		281,084	$	1.31
	Common shares issuable upon exercise of stock options using treasury stock method				7,711						14,397						16,423

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		For the Years Ended December 31,
		2002						2001							2000
		Net						Net							Net
		Income		Shares		EPS		Income		Shares		EPS			Income		Shares		EPS
Diluted earnings per common share:
	Income before dilutive effect of certain convertible securities, discontinued operations and cumulative effect of a change in accounting principle	$	59,145		362,533	$	0.16	$	587,419		317,919	$	1.85		$	332,803		297,507	$	1.12
	Dilutive effect of certain convertible securities		—		—		—		46,632		54,337		(0.15	)		20,841		31,746		(0.05	)
	Income before discontinued operations and cumulative effect of a change in accounting principle		59,145		362,533		0.16		634,051		372,256		1.70			353,644		329,253		1.07
	Discontinued operations, net of tax		59,473				0.17		35,037				0.10			36,281				0.11
	Cumulative effect of a change in accounting principle		—				—		1,036				—			—				—
	Net income, as adjusted	$	118,618		362,533	$	0.33	$	670,124		372,256	$	1.80		$	389,925		329,253	$	1.18

      Potentially convertible securities and unexercised employee stock options to purchase 136,744,307, 13,293,586, and 18,877,778 shares of the Company’s common stock were not included in the computation of diluted shares outstanding during the years ended December 31, 2002, 2001, and 2000, respectively, because such inclusion would be anti-dilutive.

26. Commitments and Contingencies

      Turbines. On February 11, 2003, the Company announced a significant restructuring of its turbine agreements (see Note 5), which enables the Company to cancel up to 131 steam and gas turbines. The Company recorded a pre-tax charge of $207.4 million in connection with these restructurings. The Company remains committed to take delivery of 12 gas and 9 steam turbines. The table below sets forth future payments for previously delivered turbines, payments and delivery year for the remaining 21 turbines to be delivered as well as payment required for the potential cancellation costs of the 131 gas and steam turbines. The table does not include payments that would result if the Company were to release for manufacturing any of the 131 turbines.

Year	Total			Units To Be Delivered
2003	$	427,848	(1)		14
2004		153,339			7
2005		19,596			—
Total	$	600,783			21

(1)  Includes certain payments under vendor financing. See Note 16 for further discussion.

      Power Plant Operating Leases — The Company has entered into long-term operating leases for power generating facilities, expiring through 2049. Many of the lease agreements provide for renewal options, and some of the agreements contain customary restrictions on dividends, additional debt and further encumbrances similar to those typically found in project finance instruments. In accordance with SFAS No. 13 and

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SFAS No. 98, “Accounting for Leases” the Company’s operating leases are not reflected on our balance sheet. Future minimum lease payments under these leases are as follows (in thousands):

		Initial
		Year		2003		2004		2005		2006		2007		Thereafter		Total
Watsonville			1995	$	2,905	$	2,905	$	2,905	$	2,905	$	2,905	$	6,969	$	21,494
King City			1996		22,563		13,746		10,344		9,700		9,100		96,150		161,603
Greenleaf			1998		8,994		8,858		8,723		8,650		8,650		45,628		89,503
Geysers			1999		66,967		55,415		55,890		47,991		47,150		183,419		456,832
KIAC			2000		25,467		24,251		24,077		23,875		23,845		289,092		410,607
Rumford/ Tiverton			2000		32,940		35,365		44,942		45,000		45,000		653,292		856,539
South Point			2001		46,059		31,627		9,620		9,620		9,620		317,650		424,196
RockGen			2001		25,861		26,565		27,031		26,088		27,478		227,344		360,367
	Total			$	231,756	$	198,732	$	183,532	$	173,829	$	173,748	$	1,819,544	$	2,781,141

      In 2002, 2001, and 2000 rent expense for power plant operating leases amounted to $111.0 million, $99.5 million, and $63.5 million, respectively. Calpine guarantees $1.8 billion of the total future minimum lease payments of its consolidated subsidiaries.

      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. These debt securities are classified as held-to-maturity and are recorded at an amortized cost of $86.1 million at December 31, 2002.

      Production Royalties and Leases — The Company is committed under numerous geothermal leases and right-of-way, easement and surface agreements. The geothermal leases generally provide for royalties based on production revenue with reductions for property taxes paid. The right-of-way, easement and surface agreements are based on flat rates or adjusted based on CPI changes and are not material. Under the terms of most geothermal leases, prior to May 1999, when the Company consolidated the steam field and power plant operations in Lake and Sonoma Counties in northern California (“The Geysers”), royalties were based on steam and effluent revenue. Following the consolidation of operations, the royalties began to accrue as a percentage of electrical revenues. Certain properties also have net profits and overriding royalty interests that are in addition to the land base lease royalties. Some lease agreements contain clauses providing for minimum lease payments to lessors if production temporarily ceases or if production falls below a specified level.

      Production royalties for the years ended December 31, 2002, 2001, and 2000, are $17.6 million, $27.5 million, and $32.3 million, respectively.

      Office and Equipment Leases — The Company leases its corporate and regional offices as well as some of its office equipment under noncancellable operating leases expiring through 2013. Future minimum lease payments under these leases are as follows (in thousands):

2003		$	24,028
2004			28,182
2005			26,377
2006			22,240
2007			19,743
Thereafter			108,621
	Total	$	229,191

      Lease payments are subject to adjustments for the Company’s pro rata portion of annual increases or decreases in building operating costs. In 2002, 2001, and 2000 rent expense for noncancellable operating leases amounted to $25.8 million, $16.2 million, and $6.3 million, respectively.

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      Natural Gas Purchases — The Company enters into gas purchase contracts of various terms with third parties to supply gas to its gas-fired cogeneration projects.

      Gas Pipeline Transportation in Canada — To support production and marketing operations, Calpine has firm commitments in the ordinary course of business for gathering, processing and transmission services that require the Company to deliver certain minimum quantities of natural gas to third parties or pay the corresponding tariffs.

      Guarantees — As part of normal business, Calpine enters into various agreements providing, or otherwise arranges, financial or performance assurance to third parties on behalf of its subsidiaries. Such arrangements include guarantees, standby letters of credit and surety bonds. These arrangements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended commercial purposes.

      Calpine routinely issues guarantees to third parties in connection with contractual arrangements entered into by Calpine’s direct and indirect wholly-owned subsidiaries in the ordinary course of such subsidiaries’ respective business, including power and natural gas purchase and sale arrangements and contracts associated with the development, construction, operation and maintenance of Calpine’s fleet of power generating facilities. Under these guarantees, if the subsidiary in question were to fail to perform its obligations under the guaranteed contract, giving rise to a default and/or an amount owing by the subsidiary to the third party under the contract, Calpine could be called upon to pay such amount to the third party or, in some instances, to perform the subsidiary’s obligations under the contract. It is Calpine’s policy to attempt to negotiate specific limits or caps on Calpine’s overall liability under these types of guarantees; however, in some instances, Calpine’s liability is not limited by way of such a contractual liability cap.

      At December 31, 2002, guarantees of subsidiary debt, standby letters of credit, surety bonds and guarantees of subsidiary operating lease payments and their respective expiration dates were as follows (in thousands):

Commitments Expiring	2003		2004		2005		2006		2007		Thereafter		Total
Guarantee of subsidiary debt	$	161,268	$	18,597	$	13,086	$	15,528	$	152,618	$	3,035,559	$	3,396,656
Standby letters of credit(1)		622,178		—		63,428		—		—		—		685,606
Surety bonds(2)		2,090		33,366		—		—		—		36,811		72,267
Guarantee of subsidiary operating lease payments		111,070		96,688		83,169		81,772		82,487		1,393,364		1,848,550
Total	$	896,606	$	148,651	$	159,683	$	97,300	$	235,105	$	4,465,734	$	6,003,079

(1)	The Standby letters of credit disclosed above include those disclosed in Notes 13 and 16.
(2)	The bonds that do not have expiration or cancellation dates are included in the Thereafter column.

      The balance of the guarantees of subsidiary debt, standby letters of credit and surety bonds were as follows (in thousands):

	Balance at December 31,
	2002		2001
Guarantee of subsidiary debt	$	3,396,656	$	3,283,507
Standby letters of credit		685,606		642,496
Surety bonds		72,267		261,937
	$	4,154,529	$	4,187,940

      The Company has guaranteed the principal payment of $2,656.8 million and $2,596.4 million, as of December 31, 2002 and 2001, respectively, of Senior Notes for two wholly-owned finance subsidiaries of Calpine, Calpine Canada Energy Finance ULC and Calpine Canada Energy Finance II ULC. In addition, as of December 31, 2002 the Company has guaranteed the payment of $50.0 million of project financing for its wholly-owned subsidiary, Calpine California Energy Finance, LLC. As of December 31, 2002, the Company

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has guaranteed $301.0 million and $388.9 million, respectively, of project financing for the Broad River Energy Center and Pasadena Power Plant and $300.0 million and $387.1 million, respectively, as of December 31, 2000 for these power plants. All of the guaranteed debt is recorded on the Company’s consolidated balance sheet.

      Calpine routinely arranges for the issuance of letters of credit and various forms of surety bonds to third parties in support of its subsidiaries’ contractual arrangements of the types described above and may guarantee the operating performance of some of its partially owned subsidiaries up to the Company’s ownership percentage. The letters of credit outstanding under various credit facilities support CES risk management, and other operational and construction activities. Of the total letters of credit outstanding, $106.1 million and $236.1 million were issued to support CES risk management at December 31, 2002 and 2001, respectively. In the event a subsidiary were to fail to perform its obligations under a contract supported by such a letter of credit or surety bond, and the issuing bank or surety were to make payment to the third party, Calpine would be responsible for reimbursing the issuing bank or surety within an agreed timeframe, typically a period of 1 to 10 days. To the extent liabilities are incurred as a result of activities covered by letters of credit or the surety bonds, such liabilities are included in the consolidated balance sheets.

      At December 31, 2002, investee debt was $639.3 million. Based on the Company’s ownership share of each of the investments, the Company’s share would be approximately $238.6 million. However, all such debt is non-recourse to the Company.

      In the course of its business, Calpine and its subsidiaries have entered into various purchase and sale agreement relating to stock and assets. These purchase and sale agreements customarily provide for indemnification by each of the purchaser and the seller, and/or their respective parent, to the counter-party for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party. These indemnification obligations generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or impossible to quantify at the time of the consummation of a particular transaction. We have no reason to believe that Calpine currently has any material liability relating to such routine indemnification obligations.

      Calpine has in a few limited circumstances directly or indirectly guaranteed the performance of obligations by unrelated third parties. These circumstances have arisen in situations in which a third party has contractual obligations with respect to the construction, operation or maintenance of a power generating facility or related equipment owned in whole or in part by Calpine. Generally, the third party’s obligations with respect to such facility or generating are guaranteed for the direct or indirect benefit of Calpine by the third party’s parent or other party. A financing party or investor in such facility or equipment may negotiate for Calpine also to guarantee the performance of such third party’s obligations as additional support for the third party’s obligations. For example, in conjunction with the financing of California peaker program, Calpine guaranteed for the benefit of the lenders certain warranty obligations of third party suppliers and contractors. Calpine has entered into few guarantees of unrelated third party’s obligations. Calpine has no reason to believe that currently has any liability with respect to these guarantees.

      The Company believes that the likelihood that it would be required to perform or otherwise incur any significant losses associated with any of these guarantees is remote.

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 financial statements.

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      Securities Class Action Lawsuits. Fourteen shareholder lawsuits have been filed against the Company and certain of its officers in the United States District Court, Northern District of California. The actions captioned Weisz v. Calpine Corp., et al., filed March 11, 2002, and Labyrinth Technologies, Inc. v. Calpine Corp., et al., filed March 28, 2002, are purported class actions on behalf of purchasers of Calpine stock between March 15, 2001 and December 13, 2001. Gustaferro v. Calpine Corp., filed April 18, 2002, is purported class action on behalf of purchasers of Calpine stock between February 6, 2001 and December 13, 2001. The eleven other actions were filed between March 18, 2002 and April 23, 2002. The complaints in these eleven actions are virtually identical — three law firms, in conjunction with other law firms as co-counsel, filed them. All eleven lawsuits are purported class actions on behalf of purchasers of the Company’s securities between January 5, 2001 and December 13, 2001.

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

      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 the Company’s 8.5% Senior Notes due February 15, 2011 (“2011 Notes”) and the alleged class period is October 15, 2001 through December 13, 2001. The Ser Complaint alleges that in violation of Sections 11 and 15 of the Securities Act of 1933, the Prospectus Supplement dated October 11, 2001, for the 2011 Notes contained false and misleading statements regarding the Company’s financial condition. This action names as defendants the Company, certain of its officers and directors, and the underwriters of the 2011 Note 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. In January 2003, Plaintiffs filed an amended consolidated complaint naming additional officers as defendants and adding new security law claims. The Company considers these lawsuits to be without merit and intends to defend vigorously 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 styled 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 the Company and stock sales by certain of the director defendants and the officer defendant. In December 2002, the court dismissed the complaint with respect to certain of the director defendants for lack of personal jurisdiction, though the plaintiff may appeal this ruling. In early February 2003, the plaintiff filed an amended complaint. The Company considers this lawsuit to be without merit and intends to vigorously defend against it.

      Gordon v. Peter Cartwright, et al. On August 8, 2002, a shareholder filed a derivative lawsuit in the United States District Court for the Northern District of California on behalf of the Company against its directors, captioned Gordon v. Cartwright, et al., similar to Johnson v. Cartwright. Motions have been filed to dismiss the action against certain of the director defendants on the grounds of lack of personal jurisdiction, as well as to dismiss the complaint in total on other grounds. In February 2003, the plaintiff agreed to stay these proceedings in favor of the consolidated federal securities class action described above and to dismiss without prejudice certain director defendants. The Company considers this lawsuit to be without merit and intends to vigorously defend against it.

      California Business & Professions Code Section 17200 Cases. The lead case T&E Pastorino Nursery v. Duke Energy Trading and Marketing, L.L.C., et al. This purported class action complaint filed in May 2002 against twenty energy traders and energy companies including CES alleges that defendants exercised market power and manipulated prices in violation of California Business & Professions Code Section 17200 et seq., and seeks injunctive relief, restitution and attorneys’ fees. The Company also has been named in seven other similar complaints for violations of Section 17200. All seven cases have been removed from the various state courts in which they were originally filed to federal court for pretrial proceedings with other cases in which the

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Company is not named as a defendant. In addition, plaintiffs in the case have filed a motion to remand that matter to California state court.

      The Company considers the allegations against Calpine and its subsidiaries in each of these lawsuits to be without merit, and intends to vigorously defend against them.

      McClintock et al. v. Vikram Budhraja, et al. California Department of Water Resources Case. On May 1, 2002, California State Senator Tom McClintock and others filed a complaint against Vikram Budhraja, a consultant to the California Department of Water Resources (“DWR”), DWR itself, and more than twenty nine energy providers and other interested parties, including the Company. The complaint alleges that the long term power contracts that DWR entered into with these energy providers, including the Company, are rendered void because Budhraja, who negotiated the contracts on behalf of the DWR, allegedly had an undisclosed financial interest in the contracts due to his connection to one of the energy providers, Edison International. Among other things, the complaint seeks an injunction prohibiting further performance of the long-term contracts and restitution of any funds paid to energy providers by the State of California under the contracts. The action has been stayed by order of the Court since August 26, 2002, pending resolution of an earlier-filed state court action involving the same parties and subject matter captioned Carboneau v. State of California in which the Company is not a defendant. The Company considers the allegations against the Company in this lawsuit to be without merit and intends to vigorously defend against them.

      Nevada Power Company and Sierra Pacific Power Company v. Calpine Energy Services, L.P. before the FERC, filed on December 4, 2001. Nevada Section 206 Complaint. On December 4, 2001, NPC and SPPC filed a complaint with FERC under Section 206 of the Federal Power Act against a number of parties to their power sales agreements, including the Company. NPC and SPPC allege in their complaint, which seeks a refund, that the prices they agreed to pay in certain of the power sales agreements, including those signed with the Company, where negotiated during a time when the power market was dysfunctional and that they are unjust and unreasonable. The Company considers the complaint to be without merit and is vigorously defending against it. The Administrative Law Judge issued an Initial Decision on December 19, 2002 that found for the Company and the other respondents in the case and denied Nevada Power the relief that it was seeking. The parties are waiting for a final FERC order in this proceeding.

      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”). The Company wrote-off $17.7 million in December 2001 related to losses that it alleged were caused by ACE. The Company and ACE entered into a settlement agreement on March 29, 2002, pursuant to which ACE made a payment to the Company of $7 million and transferred to the Company the rights to the emission reduction credits to be held by ACE. The Company recognized the $7 million in the second quarter of 2002. In June 2002 a complaint was filed by InterGen North America, L.P. (“InterGen”) against Anne M. Sholtz, the owner of ACE, and EonXchange, another Sholtz-controlled entity, which filed for bankruptcy protection on May 6, 2002. InterGen alleges it suffered a loss of emission reduction credits from EonXchange in a manner similar to the Company’s loss from ACE. InterGen’s complaint alleges that Anne Sholtz co-mingled assets among ACE, EonXchange and other Sholtz entities and that ACE and other Sholtz entities should be deemed to be one economic enterprise and all retroactively included in the EonXchange bankruptcy filing as of May 6, 2002. InterGen’s complaint refers to the payment by ACE of $7 million to the Company alleging that InterGen’s ability to recover from EonXchange has been undermined thereby. The company is unable to assess the likelihood of InterGen’s complaint being upheld at this time.

      Geysers Reliability Must Run Section 206 Proceeding. California Independent System Operator, California Electricity Oversight Board, Public Utilities Commission of the State of California, Pacific Gas and Electric Company, San Diego Gas & Electric Company, and Southern California Edison (collectively referred to as the “Buyers Coalition”), filed a complaint on November 2, 2001 at the Federal Energy Regulatory Commission requesting the commencement of a Federal Power Act Section 206 proceeding to challenge one

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component of a number of separate settlements previously reached on the terms and conditions of “reliability must-run” contracts (“RMR Contracts”) with certain generation owners, including Geysers Power Company, LLC, which settlements were also previously approved by the FERC. RMR contracts require the owner of the specific generation unit to provide energy and ancillary services when called upon to do so by the ISO to meet local transmission reliability needs or to manage transmission constraints. The Buyers Coalition has asked FERC to find that the availability payments under these RMR Contracts are not just and reasonable. Geysers Power Company, LLC filed an answer to the complaint in November 2001. To date, FERC has not established a section 206 proceeding. The outcome of this litigation and the impact on the Company’s business cannot be presently determined.

      International Paper Company v. Androscoggin Energy LLC. In October 2000, International Paper Company filed a complaint against Androscoggin Energy LLC (“AELLC”) alleging that AELLC breached certain contractual representations and warranties by failing to disclose facts surrounding the termination, effective May 8, 1998, of one of AELLC’s fixed-cost gas supply agreements. The Company had acquired a 32.3% interest in AELLC as part of the Skygen transaction which closed in October 2000. AELLC filed a counterclaim against International Paper Company that has been referred to arbitration. AELLC may commence the arbitration counterclaim after discovery has progressed further, depending on the outcome of the discussions referred to below. On November 7, 2002, the court issued an opinion on the parties’ cross motions for summary judgment finding in AELLC’s favor on certain matters though granting summary judgment to International Paper Company on the liability aspect of a particular claim against AELLC. While the matter is expected to proceed to the damages aspect of trial in mid-2003, the Company is seeking to engage IP in discussions to explore a commercial resolution to the matter. The Company cannot currently estimate the possible loss, if any, it may ultimately incur as a result of this matter.

      In addition, the Company is involved in various other legal actions proceedings, and state and regulatory investigations relating to the Company’s business. The Company is involved in various other claims and legal actions arising out of the normal course of its business. The Company does not expect that the outcome of these proceedings will have a material adverse effect on the Company’s financial position or results of operations.

27. Operating Segments

      The Company is first and foremost an electric generating company. In pursuing this single business strategy, it is the Company’s objective to provide approximately 25% of its fuel consumption from its own natural gas production (“equity gas”). Since the Company’s oil and gas production and marketing activity has reached the quantitative criteria to be considered a reportable segment under SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” the following represents reportable segments and their defining criteria. The Company’s segments are electric generation and marketing; oil and gas production and marketing; and corporate and other activities. Electric generation and marketing includes the development, acquisition, ownership and operation of power production facilities, hedging, balancing, optimization, and trading activity transacted on behalf of the Company’s power generation facilities. Oil and gas production includes the ownership and operation of gas fields, gathering systems and gas pipelines for internal gas consumption, third party sales and hedging, balancing, optimization, and trading activity transacted on behalf of the Company’s oil and gas operations. Corporate activities and other consists primarily of financing activities, the Company’s specialty data center engineering business, which was divested in the third quarter of 2003 and general and administrative costs. Certain costs related to company-wide functions are allocated to each segment, such as interest expense, distributions on HIGH TIDES, and interest income, which are allocated based on a ratio of segment assets to total assets.

      The Company evaluates performance based upon several criteria including profits before tax. The accounting policies of the operating segments are the same as those described in Note 3 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies.” The financial results for the Company’s operating segments have been prepared on a basis consistent with the manner in which the Company’s management internally disaggregates financial information for the purposes of assisting in making internal operating decisions.

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      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			Corporate,
	Generation		Production			Other and
	and Marketing		and Marketing			Eliminations			Total
	(In thousands)
2002
Total Revenue	$	7,146,754	$	301,601		$	1,892		$	7,450,247
Depreciation and amortization		302,166		149,264			8,035			459,465
Interest expense		331,078		30,514			52,110			413,702
Interest income		34,529		3,182			5,405			43,116
Income before taxes		187,095		(7,856	)		(132,275	)		46,964
Discontinued operations, net of tax		24,842		44,684			(10,053	)		59,473
Equity income		16,552		—			—			16,552
Total assets		18,587,342		1,713,085			2,926,565			23,226,992
Investments in power plants		421,402		—			—			421,402
Property Additions		3,274,051		413,174			344,311			4,031,536
Equipment cancellation and asset		404,737		—			—			404,737
Intersegment revenues		—		180,374			—			180,374
2001
Total Revenue	$	6,322,459	$	406,814		$	18,091		$	6,747,364
Depreciation and amortization		182,871		122,265			6,166			311,302
Interest expense		152,089		15,281			31,103			198,473
Interest income		55,518		5,578			11,363			72,459
Income before taxes		856,041		116,261			(85,456	)		886,846
Discontinued operations, net of tax		1,544		34,601			(1,108	)		35,037
Equity income		16,946		—			—			16,946
Total assets		16,808,395		1,688,751			3,440,081			21,937,227
Investments in power plants		367,290		—			—			367,290
Property Additions		4,814,024		485,944			532,438			5,832,406
Merger costs		—		41,627			—			41,627
Intersegment revenues		—		123,845			—			123,845
2000
Total Revenue	$	2,189,799	$	274,153		$	(88,774	)	$	2,375,178
Depreciation and amortization		112,888		82,305			670			195,863
Interest expense		54,271		9,902			17,717			81,890
Interest income		26,844		4,898			8,762			40,504
Income before taxes		632,148		107,571			(175,465	)		564,254
Discontinued operations, net of tax		484		35,797			—			36,281
Equity income		30,085		(1,289	)		—			28,796
Total assets		7,031,852		1,282,950			2,295,430			10,610,232
Investments in power plants		156,969		47,983			—			204,952
Property Additions		2,558,620		317,486			192,422			3,068,528
Intersegment revenues		—		66,524			—			66,524

      Intersegment revenues primarily relate to the use of internally procured gas for the Company’s power plants. These intersegment revenues have been included in Total Revenue and Income before taxes in the oil and gas production and marketing reporting segment and eliminated in the corporate and other reporting segment.

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Geographic Area Information

      As of December 31, 2002, the Company owned interests in 79 operating power plants in the United States, two operating power plants in Canada and one operating power plant in the United Kingdom. In addition, the Company had oil and gas interests in the United States and Canada. Geographic revenue and property, plant and equipment information is based on physical location of the assets at the end of each period.

					United
	United States		Canada		Kingdom		Total
2002
Total Revenue	$	7,120,455	$	123,908	$	205,884	$	7,450,247
Property, plant and equipment, net		16,957,618		925,787		963,175		18,846,580
2001
Total Revenue	$	6,460,572	$	192,097	$	94,695	$	6,747,364
Property, plant and equipment, net		13,562,822		844,832		919,376		15,327,030
2000
Total Revenue	$	2,214,408	$	160,770	$	—	$	2,375,178
Property, plant and equipment, net		7,138,045		521,972		—		7,660,017

28. 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”) 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 June 19, 2001, FERC ordered price mitigation throughout the western United States in an attempt to reduce the dependence of the California market on spot markets in favor of longer-term committed energy supplies. Subsequently, the Chief Administrative Law Judge (“Chief ALJ”) issued his report and recommendations to FERC on July 12, 2001 on how refunds should be calculated. Based on the Chief ALJ’s report, FERC established a subsequent proceeding to determine the refund liability for each seller for a refund period of October 2, 2000 through June 19, 2001. During this refund period the Company sold much of its California merchant capacity in the bilateral markets, which sales are not subject to refund under this proceeding. As a result of an order by the U.S. Court of Appeals for the Ninth Circuit, FERC is required to consider the impact on possible market manipulation on potential refund liability. In November 2002, FERC issued an order establishing a special hundred-day period for additional discovery. In March 2003 the parties were required to submit reports addressing any such market manipulation. This aspect of the proceeding has not yet been concluded.

      On December 12, 2002, the Administrative Law Judge issued a Certification of Proposed Finding on California Refund Liability making an initial determination of refund liability (the “December 12 Certification”). Under the December 12 Certification, Calpine had potential direct and indirect refund liability of approximately $6.2 million, considering the offsets available to the Company. We have fully reserved the amount of refund liability that would potentially be owed under the December 12 Certification. See Note 29 for an update.

      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

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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 the Company set forth or described in the Initial Report.

CPUC Proceedings

      The Company is involved from time to time in administrative litigation at the California Public Utilities Commission (“CPUC”). In addition, the Company frequently intervenes in proceedings at the CPUC where it is not a direct party to protect its interests. See Note 23 Customers for more information.

City of Lodi Agreement

      On February 9, 2001, the Company entered into an agreement with the City of Lodi (the Northern California Power Agency acted as agent on behalf of the City of Lodi) whereby CES would sell 25 MW of ATC fixed price power plus a 1.7 MW day-ahead call option to the City of Lodi for delivery from January 1, 2002 through December 31, 2011. In September 2002, the City of Lodi and Calpine agreed to terminate this agreement resulting in a $41.5 million gain. The gain is included in Other income in the accompanying consolidated financial statements.

29. Subsequent Events

      On February 13, 2003, the Company completed a secondary offering of 17,034,234 Warranted Units of the Calpine Power Income Fund for gross proceeds of Cdn$153.3 million (US$100.2 million). The Warranted Units were sold to a syndicate of underwriters at a price of Cdn$9.00. Each Warranted Unit consists of one Trust Unit and one-half of one Trust Unit purchase warrant. Each Warrant entitles the holder to purchase one Trust Unit at a price of Cdn$9.00 per Trust Unit at any time on or prior to December 30, 2003, after which time the Warrant will be null and void. Assuming the exercise in full of the Warrants, Calpine will not own or control any of the outstanding Trust Units. However, Calpine will retain its 30% subordinated interest in the Canadian power generating assets and will continue to operate and manage the Calpine Power Income Fund and the Fund assets.

      A sixteenth securities class action, Hawaii Structural Ironworkers Pension Fund v. Calpine, et al., was filed on March 11, 2003 against the Company, 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 those in the above-referenced actions. 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 the Company’s April 2002 equity offering. The Hawaii action alleges that the Registration Statement and Prospectus filed by the Company which became effective on April 24, 2002 contained false and misleading statements regarding the Company’s financial condition in violation of Sections 11, 12 and 15 of the Securities Act of 1933. The Hawaii action relies in part on the Company’s restatement of certain past financial results, announced on March 3, 2003, to support its allegations. The Hawaii action seeks an unspecified amount of damages, in addition to other forms of relief. The Company considers this lawsuit to be without merit and intends to defend vigorously against it.

      On March 26, 2003, the staff of the FERC issued a final report in an investigation the FERC had initiated on February 13, 2002 of potential manipulation of electric and natural gas prices in the western United States (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 Company believes that it did not violate these tariffs and that, to the extent that such a finding could be made, any potential liability would not be material. The Final

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Report also recommended that FERC modify the basis for determining potential liability in the California Refund Proceeding discussed above.

      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”). See Note 28 for a discussion of the December 12 Certification. In addition, as a result of certain findings by the FERC staff concerning the unreliability or mis-reporting 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. At this time, the Company is unable to determine its potential liability under the March 26 Order. However, based upon a preliminary understanding, the Company believes that such liability is likely to increase from that calculated in accordance with the December 12 Certification, but the Company is unable to estimate the amount of such potential increase at this time.

      The final outcome of this proceeding and the impact on the Company’s business is uncertain at this time.

30. Quarterly Consolidated Financial Data (unaudited)

      The Company’s quarterly operating results have fluctuated in the past and may continue to do so in the future as a result of a number of factors, including, but not limited to, the timing and size of acquisitions, the completion of development projects, the timing and amount of curtailment of operations under the terms of certain power sales agreements, the degree of risk management and trading activity, and variations in levels of production. Furthermore, the majority of the dollar value of capacity payments under certain of the Company’s power sales agreements are received during the months of May through October.

      The Company’s common stock has been traded on the New York Stock Exchange since September 19, 1996. There were 1,849 common stockholders of record at December 31, 2002. No dividends were paid for the years ended December 31, 2002 and 2001. All share data has been adjusted to reflect the two-for-one stock split effective June 8, 2000, and the two-for-one stock split effective November 14, 2000.

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      The quarterly operating results below include both the amounts as originally reported in prior periods and the amounts as restated. See Note 2 for further information on the restatement of prior period financial statements.

		Quarter Ended
		December 31,			September 30,			June 30,		March 31,
		(In thousands, except per share amounts)
2002, Restated (for periods through September 30, 2002)
Total revenue		$	1,886,470		$	2,474,698		$	1,758,371	$	1,330,708
Gross profit			236,708			350,552			247,347		180,248
Income (loss) from operations			(71,387	)		288,854			169,101		(55,890	)
Income before discontinued operations			(64,431	)		141,867			59,361		(77,652	)
Discontinued operations, net of tax			39,273			9,261			8,960		1,979
Net income (loss)		$	(25,158	)	$	151,128		$	68,321	$	(75,673	)
Basic earnings per common share:
	Income (loss) before discontinued operations	$	(0.17	)	$	0.38		$	0.17	$	(0.25	)
	Discontinued operations, net of tax		0.10			0.02			0.02		—
	Net income (loss)		(0.07	)		0.40			0.19		(0.25	)
Diluted earnings per common share:
	Income (loss) before discontinued operations and dilutive effect of certain trust preferred securities	$	(0.17	)	$	0.37		$	0.16	$	(0.25	)
	Dilutive effect of certain trust preferred securities		—			(0.05	)		—		—
	Income (loss) before discontinued operations		(0.17	)		0.32			0.16		(0.25	)
	Discontinued operations, net of tax		0.10			0.02			0.02		—
	Net income (loss)		(0.07	)		0.34			0.18		(0.25	)
Common stock price per share:
	High	$	4.69		$	7.29		$	13.55	$	17.28
	Low		1.55			2.36			5.30		6.15

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		Quarter Ended
		December 31,			September 30,			June 30,			March 31,
		(In thousands, except per share amounts)
2002, As Reported
Total revenue		$	1,888,763		$	2,495,010		$	1,941,806		$	1,738,347
Gross profit			237,504			362,332			256,306			177,964
Income (loss) from operations			(74,602	)		277,416			177,992			(62,106	)
Income (loss) before discontinued operations and extraordinary gain (loss)			(66,637	)		144,397			72,516			(76,397	)
Discontinued operations, net of tax			41,179			16,950			—			—
Extraordinary gain (loss), net of tax			—			—			—			2,130
Net income (loss)		$	(25,158	)	$	161,347		$	72,516		$	(74,267	)
Basic earnings per common share:
	Income (loss) before discontinued operations and extraordinary gain (loss)	$	(0.18	)	$	0.38		$	0.20		$	(0.25	)
	Discontinued operations, net of tax		0.11			0.05			—			—
	Extraordinary gain (loss), net of tax		—			—			—			0.01
	Net income (loss)		(0.07	)		0.43			0.20			(0.24	)
Diluted earnings per common share:
	Income (loss) before discontinued operations, extraordinary gain (loss) and dilutive effect of certain trust preferred securities	$	(0.18	)	$	0.38		$	0.20		$	(0.25	)
	Dilutive effect of certain trust preferred securities		—			(0.05	)		(0.01	)		—
	Income (loss) before discontinued operations and extraordinary gain (loss)		(0.18	)		0.33			0.19			(0.25	)
	Discontinued operations, net of tax		0.11			0.03			—			—
	Extraordinary gain (loss), net of tax		—			—			—			0.01
	Net income (loss)		(0.07	)		0.36			0.19			(0.24	)
Common stock price per share:
	High	$	4.69		$	7.29		$	13.55		$	17.28
	Low		1.55			2.36			5.30			6.15

F-71

		Quarter Ended
		December 31,			September 30,			June 30,			March 31,
		(In thousands, except per share amounts)
2001, Restated
Total revenue		$	1,464,943		$	2,505,500		$	1,490,654		$	1,286,267
Gross profit			211,741			504,068			278,992			236,435
Income from operations			166,588			483,525			191,300			178,810
Income before discontinued operations and cumulative effect of a change in accounting principle			94,884			307,806			92,617			92,112
Discontinued operations, net of tax			1,588			7,218			10,786			15,445
Cumulative effect of a change in accounting principle			—			—			—			1,036
Net income		$	96,472		$	315,024		$	103,403		$	108,593
Basic earnings per common share:
	Income before discontinued operations and cumulative effect of a change in accounting principle	$	0.31		$	1.01		$	0.31		$	0.31
	Discontinued operations, net of tax		0.01			0.02			0.03			0.05
	Cumulative effect of a change in accounting principle		—			—			—			—
	Net income		0.32			1.03			0.34			0.36
Diluted earnings per common share:
	Income before dilutive effect of certain convertible securities, discontinued operations and cumulative effect of a change in accounting principle	$	0.30		$	0.97		$	0.29		$	0.29
	Dilutive effect of certain convertible securities		(0.02	)		(0.11	)		(0.01	)		(0.01	)
	Income before discontinued operations and cumulative effect of a change in accounting principle		0.28			0.86			0.28			0.28
	Discontinued operations, net of tax		0.01			0.02			0.03			0.05
	Cumulative effect of a change in accounting principle		—			—			—			—
	Net income		0.29			0.88			0.31			0.33
Common stock price per share:
	High	$	28.85		$	46.00		$	57.35		$	58.04
	Low		10.00			18.90			36.20			29.00

F-72

		Quarter Ended
		December 31,			September 30,			June 30,			March 31,
		(In thousands, except per share amounts)
2001, As Reported
Total revenue		$	1,721,249		$	2,520,151		$	1,612,873		$	1,339,751
Gross profit			215,836			521,145			304,225			275,568
Income (loss) from operations			164,192			486,894			213,710			217,623
Income (loss) before discontinued operations, extraordinary gain (loss) and cumulative effect of a change in accounting principle			92,671			313,496			108,965			118,627
Discontinued operations, net of tax			—			7,303			—			—
Extraordinary gain (loss), net of tax			7,307			—			(1,300	)		—
Cumulative effect of a change in accounting principle			—			—						1,036
Net income (loss)		$	99,978		$	320,799		$	107,665		$	119,663
Basic earnings per common share:
	Income (loss) before discontinued operations, extraordinary gain (loss) and cumulative effect of a change in accounting principle	$	0.30		$	1.03		$	0.36		$	0.39
	Discontinued operations, net of tax		—			0.02			—			—
	Extraordinary gain (loss), net of tax		0.03			—			—			—
	Cumulative effect of a change in accounting principle		—			—			—			0.01
	Net income (loss)		0.33			1.05			0.36			0.40
Diluted earnings per common share:
	Income (loss) before discontinued operations, extraordinary gain (loss), cumulative effect of a change in accounting principle and dilutive effect of certain trust preferred securities	$	0.29		$	0.98		$	0.34		$	0.37
	Dilutive effect of certain trust preferred securities		(0.01	)		(0.12	)		(0.02	)		(0.02	)
	Income (loss) before discontinued operations, extraordinary gain (loss) and cumulative effect of a change in accounting principle		0.28			0.86			0.32			0.35
	Discontinued operations, net of tax		—			0.02			—			—
	Extraordinary gain (loss), net of tax		0.02			—			—			—
	Cumulative effect of a change in accounting principle		—			—			—			0.01
	Net income (loss)		0.30			0.88			0.32			0.36
Common stock price per share:
	High	$	28.85		$	46.00		$	57.35		$	58.04
	Low		10.00			18.90			36.20			29.00

F-73

SUPPLEMENTAL OIL AND GAS DISCLOSURES

(Unaudited)

Oil and Gas Producing Activities

      The following disclosures for Calpine Corporation (the “Company”) are made in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 69, “Disclosures About Oil and Gas Producing Activities (An Amendment of FASB Statements 19, 25, 33 and 39)”. Users of this information should be aware that the process of estimating quantities of proved, proved developed and proved undeveloped crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.

      Proved reserves represent estimated quantities of natural gas and crude oil that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made.

      Proved developed reserves are proved reserves expected to be recovered, through wells and equipment in place and under operating methods being utilized at the time the estimates were made.

      Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

      Estimates of proved and proved developed reserves as of December 31, 2002 and 2001, were based on estimates made by Netherland, Sewell & Associates Inc. (“NSA”), independent petroleum consultants, for reserves in the United States; and Gilbert Laustsen Jung Associates Ltd. (“GLJ”), independent petroleum consultants, for reserves in Canada.

      Estimates of proved and proved developed reserves as of December 31, 2000, were based on estimates made by NSA for reserves in the United States; and GLJ and McDaniel & Associates Consultants, Ltd., both independent petroleum consultants, for reserves in Canada.

      Market prices as of each year-end were used for future sales of natural gas, crude oil and natural gas liquids. Future operating costs, production and ad valorem taxes and capital costs were based on current costs as of each year-end, with no escalation. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. Reserve data represent estimates only and should not be construed as being exact. Moreover, the standardized measure should not be construed as the current market value of the proved oil and gas reserves or the costs that would be incurred to obtain equivalent reserves. A market value determination would include many additional factors including (a) anticipated future changes in natural gas and crude oil prices, production and development costs, (b) an allowance for return on investment, (c) the value of additional reserves, not considered proved at present, which may be recovered as a result of further exploration and development activities, and (d) other business risk.

F-74

Capitalized Costs Relating to Oil and Gas Producing Activities

      The following table sets forth the capitalized costs relating to the Company’s natural gas and crude oil producing activities (excluding pipeline and related assets) at December 31, 2002, 2001 and 2000, (in thousands):

		2002			2001			2000
Proved properties		$	1,668,626		$	1,913,025		$	1,339,938
Unproved properties			305,639			322,735			76,075
	Total		1,974,265			2,235,760			1,416,013
Less — Accumulated depreciation, depletion and amortization			(525,700	)		(519,747	)		(337,922	)
	Net capitalized costs	$	1,448,565		$	1,716,013		$	1,078,091

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

      The acquisition, exploration and development costs disclosed in the following tables are in accordance with definitions in SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” Acquisition costs include costs incurred to purchase, lease or otherwise acquire property. Exploration costs include exploration expenses and additions to exploration wells, including those in progress. Development costs include additions to production facilities and equipment, as well as additions to development wells, including those in progress. The following table sets forth costs incurred related to the Company’s oil and gas activities for the years ended December 31, 2002, 2001, and 2000, (in thousands):

				United States		Canada		Total
December 31, 2002 —
	Acquisition costs of properties —
		Proved		$	9,763	$	2,650	$	12,413
		Unproved			8,460		1,694		10,154
			Subtotal		18,223		4,344		22,567
	Exploration costs				10,958		7,559		18,517
	Development costs				54,986		61,209		116,195
			Total	$	84,167	$	73,112	$	157,279
December 31, 2001 —
	Acquisition costs of properties —
		Proved		$	342,941	$	6,762	$	349,703
		Unproved			234,789		17,780		252,569
			Subtotal		577,730		24,542		602,272
	Exploration costs				20,495		17,970		38,465
	Development costs				86,311		162,343		248,654
			Total	$	684,536	$	204,855	$	889,391
December 31, 2000 —
	Acquisition costs of properties —
		Proved		$	101,618	$	307,356	$	408,974
		Unproved			1,119		71,141		72,260
			Subtotal		102,737		378,497		481,234
	Exploration costs				4,100		62,469		66,569
	Development costs				26,233		90,820		117,053
			Total	$	133,070	$	531,786	$	664,856

F-75

Results of Operations for Oil and Gas Producing Activities

      The following table sets forth results of operations for oil and gas producing activities (excluding pipeline and related operations) for the years ended December 31, 2002, 2001, and 2000, (in thousands):

				United States			Canada			Total
December 31, 2002 —
	Oil and gas production revenues —
		Third-party		$	40,035		$	61,067		$	101,102
		Intercompany			136,562			62,844			199,406
			Total revenues		176,597			123,911			300,508
	Exploration expenses, including dry hole				10,287			2,797			13,084
	Production costs				37,329			42,304			79,633
	Depreciation, depletion and amortization				80,314			67,400			147,714
	Income before income taxes				48,667			11,410			60,077
	Income tax provision				18,980			5,438			24,418
	(Income)/loss after income taxes from discontinued operations				13			(15,762	)		(15,749	)
			Results of operations	$	29,674		$	21,734		$	51,408
December 31, 2001 —
	Oil and gas production revenues —
		Third-party		$	92,622		$	194,452		$	287,074
		Intercompany			112,171			3,730			115,901
			Total revenues		204,793			198,182			402,975
	Exploration expenses, including dry hole				4,311			9,284			13,595
	Production costs				28,518			40,645			69,163
	Depreciation, depletion and amortization				58,915			62,082			120,997
	Income before income taxes				113,049			86,171			199,220
	Income tax provision				40,513			41,069			81,582
	(Income)/loss after income taxes from discontinued operations				(117	)		(38,009	)		(38,126	)
			Results of operations	$	72,653		$	83,111		$	155,764
December 31, 2000 —
	Oil and gas production revenues —
		Third-party		$	45,421		$	176,570		$	221,991
		Intercompany			62,809			—			62,809
			Total revenues		108,230			176,570			284,800
	Exploration expenses, including dry hole				1,836			13,824			15,660
	Production costs				15,806			33,162			48,968
	Depreciation, depletion and amortization				29,983			50,836			80,819
	Income before income taxes				60,605			78,748			139,353
	Income tax provision				23,583			36,072			59,655
	(Income)/loss after income taxes from discontinued operations				112			(38,929	)		(38,817	)
			Results of operations	$	36,910		$	81,605		$	118,515

      The results of operations for oil and gas producing activities exclude interest charges and general corporate expenses.

F-76

Net Proved and Proved Developed Reserve Summary

      The following table sets forth the Company’s net proved and proved developed reserves at December 31 for each of the three years in the period ended December 31, 2002, and the changes in the net proved reserves for each of the three years in the period then ended as estimated by the independent petroleum consultants.

			United States			Canada			Total
Natural gas (Bcf)(1) —
	Net proved reserves at December 31, 1999			213			439			652
		Revisions of previous estimates		28			(66	)		(38	)
		Purchases in place		97			148			245
		Extensions, discoveries and other additions		21			78			99
		Sales in place		(1	)		(10	)		(11	)
		Production		(25	)		(52	)		(77	)
	Net proved reserves at December 31, 2000			333			537			870
		Revisions of previous estimates		(24	)		(49	)		(73	)
		Purchases in place		208			—			208
		Extensions, discoveries and other additions		125			31			156
		Sales in place		(11	)		(13	)		(24	)
		Production		(41	)		(61	)		(102	)
	Net proved reserves at December 31, 2001			590			445			1,035
		Revisions of previous estimates		(23	)		(1	)		(24	)
		Purchases in place		—			—			—
		Extensions, discoveries and other additions		64			22			86
		Sales in place		(3	)		(119	)		(122	)
		Production		(53	)		(46	)		(99	)
	Net proved reserves at December 31, 2002			575			301			876
Natural gas liquids and crude oil (MBbl)(2)(3) —
	Net proved reserves at December 31, 1999			1,860			30,400			32,260
		Revisions of previous estimates		89			(170	)		(81	)
		Purchases in place		1,732			14,133			15,865
		Extensions, discoveries and other additions		108			7,600			7,708
		Sales in place		(10	)		(100	)		(110	)
		Production		(240	)		(5,202	)		(5,442	)
	Net proved reserves at December 31, 2000			3,539			46,661			50,200
		Revisions of previous estimates		(238	)		(1,492	)		(1,730	)
		Purchases in place		1,116			450			1,566
		Extensions, discoveries and other additions		671			2,243			2,914
		Sales in place		(80	)		(3,054	)		(3,134	)
		Production		(434	)		(6,192	)		(6,626	)

F-77

			United States			Canada			Total
	Net proved reserves at December 31, 2001			4,574			38,616			43,190
		Revisions of previous estimates		265			782			1,047
		Purchases in place		—			—			—
		Extensions, discoveries and other additions		191			819			1,010
		Sales in place		(347	)		(23,620	)		(23,967	)
		Production		(574	)		(3,704	)		(4,278	)
	Net proved reserves at December 31, 2002			4,109			12,893			17,002
(Bcfe)(1) equivalent(4) —
	Net proved reserves at December 31, 1999			224			621			845
		Revisions of previous estimates		29			(67	)		(38	)
		Purchases in place		108			233			341
		Extensions, discoveries and other additions		22			124			146
		Sales in place		(1	)		(11	)		(12	)
		Production		(27	)		(84	)		(111	)
	Net proved reserves at December 31, 2000			355			816			1,171
		Revisions of previous estimates		(25	)		(58	)		(83	)
		Purchases in place		214			3			217
		Extensions, discoveries and other additions		129			45			174
		Sales in place		(12	)		(32	)		(44	)
		Production		(44	)		(97	)		(141	)
	Net proved reserves at December 31, 2001			617			677			1,294
		Revisions of previous estimates		(21	)		4			(17	)
		Purchases in place		—			—			—
		Extensions, discoveries and other additions		65			27			92
		Sales in place		(5	)		(261	)		(266	)
		Production		(56	)		(69	)		(125	)
	Net proved reserves at December 31, 2002			600			378			978
Net proved developed reserves
	Natural gas (Bcf)(1) —
		December 31, 2000		268			391			659
		December 31, 2001		378			394			772
		December 31, 2002		378			262			640
	Natural gas liquids and crude oil (MBbl)(2)(3) —
		December 31, 2000		2,567			32,929			35,496
		December 31, 2001		2,719			34,131			36,850
		December 31, 2002		2,509			11,623			14,132
	Bcf(1) equivalents(4) —
		December 31, 2000		283			588			871
		December 31, 2001		394			599			993
		December 31, 2002		393			332			725

(1)	Billion cubic feet or billion cubic feet equivalent, as applicable.
(2)	Thousand barrels.

F-78

(3)	Includes crude oil, condensate and natural gas liquids.
(4)	Natural gas liquids and crude oil volumes have been converted to equivalent gas volumes using a conversion factor of six cubic feet of gas to one barrel of natural gas liquids and crude oil.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

      The following information has been developed utilizing procedures prescribed by SFAS No. 69 and based on natural gas and crude oil reserve and production volumes estimated by the independent petroleum consultants. This information may be useful for certain comparison purposes but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of the Company’s oil and gas assets.

      The future cash flows presented below are based on sales prices, cost rates and statutory income tax rates in existence as of the date of the projections. It is expected that material revisions to some estimates of natural gas and crude oil reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used. Income tax expense, for both the United States and Canada, has been computed using expected future tax rates and giving effect to tax deductions and credits available, under current laws, and which relate to oil and gas producing activities.

      Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

      The following table sets forth the standardized measure of discounted future net cash flows from projected production of the Company’s natural gas and crude oil reserves for the years ended December 31, 2002, 2001, and 2000, (in millions):

		United States			Canada			Total
December 31, 2002 —
	Future cash inflows	$	2,798		$	1,569		$	4,367
	Future production and development costs		(852	)		(435	)		(1,287	)
	Future net cash flows before income taxes		1,946			1,134			3,080
	Future income taxes		(548	)		(379	)		(927	)
	Future net cash flows		1,398			755			2,153
	Discount to present value at 10% annual rate		(622	)		(272	)		(894	)
	Standardized measure of discounted future net cash flows relating to proved gas, natural gas liquids and crude oil reserves	$	776		$	483		$	1,259
December 31, 2001 —
	Future cash inflows	$	1,609		$	1,621		$	3,230
	Future production and development costs		(602	)		(569	)		(1,171	)
	Future net cash flows before income taxes		1,007			1,052			2,059
	Future income taxes		(217	)		(245	)		(462	)
	Future net cash flows		790			807			1,597
	Discount to present value at 10% annual rate		(349	)		(269	)		(618	)

F-79

		United States			Canada			Total
	Standardized measure of discounted future net cash flows relating to proved gas, natural gas liquids and crude oil reserves	$	441		$	538		$	979
December 31, 2000 —
	Future cash inflows	$	3,815		$	5,559		$	9,374
	Future production and development costs		(475	)		(759	)		(1,234	)
	Future net cash flows before income taxes		3,340			4,800			8,140
	Future income taxes		(970	)		(1,808	)		(2,778	)
	Future net cash flows		2,370			2,992			5,362
	Discount to present value at 10% annual rate		(1,172	)		(1,112	)		(2,284	)
	Standardized measure of discounted future net cash flows relating to proved gas, natural gas liquids and crude oil reserves	$	1,198		$	1,880		$	3,078

Changes in Standardized Measure of Discounted Future Net Cash Flows

      The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, 2002, 2001, and 2000 (in millions):

		United States			Canada			Total
Balance, December 31, 1999		$	153		$	550		$	703
	Sales and transfers of gas, natural gas liquids and crude oil produced, net of production costs		(93	)		(245	)		(338	)
	Net changes in prices and production costs		985			1,717			2,702
	Extensions, discoveries, additions and improved recovery, net of related costs		131			475			606
	Development costs incurred		6			25			31
	Revisions of previous quantity estimates and development costs		102			(215	)		(113	)
	Accretion of discount		15			39			54
	Net change in income taxes		(462	)		(938	)		(1,400	)
	Purchases of reserves in place		492			603			1,095
	Sales of reserves in place		(2	)		(17	)		(19	)
	Changes in timing and other		(129	)		(114	)		(243	)
Balance, December 31, 2000		$	1,198		$	1,880		$	3,078
	Sales and transfers of gas, natural gas liquids and crude oil produced, net of production costs		(177	)		(273	)		(450	)
	Net changes in prices and production costs		(1,314	)		(1,733	)		(3,047	)
	Extensions, discoveries, additions and improved recovery, net of related costs		165			70			235
	Development costs incurred		26			46			72
	Revisions of previous quantity estimates and development costs		(110	)		(298	)		(408	)
	Accretion of discount		120			40			160
	Net change in income taxes		370			869			1,239
	Purchases of reserves in place		187			6			193
	Sales of reserves in place		(48	)		(36	)		(84	)
	Changes in timing and other		24			(33	)		(9	)

F-80

		United States			Canada			Total
Balance, December 31, 2001		$	441		$	538		$	979
	Sales and transfers of gas, natural gas liquids and crude oil produced, net of production costs		(140	)		(143	)		(283	)
	Net changes in prices and production costs		529			640			1,169
	Extensions, discoveries, additions and improved recovery, net of related costs		120			44			164
	Development costs incurred		47			(22	)		25
	Revisions of previous quantity estimates and development costs		(88	)		12			(76	)
	Accretion of discount		44			6			50
	Net change in income taxes		(181	)		(65	)		(246	)
	Purchases of reserves in place		—			2			2
	Sales of reserves in place		(6	)		(515	)		(521	)
	Changes in timing and other		10			(14	)		(4	)
Balance, December 31, 2002		$	776		$	483		$	1,259

F-81