UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_______________

Form 10-Q

(Mark One)

xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September30,2006

or

oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period fromto

Commission file number: 1-12079

_______________

Calpine Corporation

(A Delaware Corporation)

I.R.S. Employer Identification No.

77-0212977

50 West San Fernando Street

San Jose, California 95113

Telephone: (408) 995-5115

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.               x Yes      o No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer   x               Accelerated filer   o               Non-accelerated filer   o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).          o Yes      x No

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:  538,844,664 shares of Common Stock, par value $.001 per share, outstanding on November 7, 2006.

CALPINE CORPORATION AND SUBSIDIARIES

(Debtor-in-Possession)

REPORT ON FORM 10-Q

For the Quarter Ended September30,2006

INDEX
						Page
PART I — FINANCIAL INFORMATION
	Item 1.		Financial Statements
				Consolidated Condensed Balance Sheets September 30, 2006 and December 31, 2005		1
				Consolidated Condensed Statements of Operations for the Three and Nine Months Ended September 30, 2006 and 2005		3
				Consolidated Condensed Statements of Cash Flows for the Nine Months Ended September 30, 2006 and 2005		5
				Notes to Consolidated Condensed Financial Statements		7
			1.		Basis of Presentation and Summary of Significant Accounting Policies	7
			2.		Chapter 11 Cases and CCAA Proceedings	10
			3.		U.S. Debtors Condensed Combined Financial Statements	17
			4.		Property, Plant and Equipment, Net and Capitalized Interest	19
			5.		Investments	20
			6.		Comprehensive Income (Loss)	20
			7.		Debt	21
			8.		Liabilities Subject to Compromise	25
			9.		Derivative Instruments	26
			10.		Earnings (Loss) Per Share	28
			11.		Stock-Based Compensation	28
			12.		Commitments and Contingencies	31
			13.		Assets Held for Sale	35
			14.		Operating Segments	36
			15.		California Power Market	37
	Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			39
				Selected Operating Information		40
				Overview		41
				Results of Operations		42
				Performance Metrics		48
				Liquidity and Capital Resources		51
				Summary of Key Activities for the Three Months Ended September 30, 2006		58
				California Power Market		58
				Recent Regulatory Developments		58
				Financial Market Risks		59
				Recent Accounting Pronouncements		63
	Item 3.		Quantitative and Qualitative Disclosures About Market Risk			63
	Item 4.		Controls and Procedures			63
PART II — OTHER INFORMATION
		Item 1.	Legal Proceedings			65
		Item 3.	Defaults Upon Senior Securities			65
		Item 6.	Exhibits			65
Signatures						70

i

DEFINITIONS

As used in this Report, the abbreviations contained herein have the meanings set forth below. Additionally, the terms, “Calpine,” “we,” “us” and “our” refer to Calpine Corporation and its consolidated subsidiaries, unless the context clearly indicates otherwise. For clarification, such terms will not include the Canadian and other foreign subsidiaries that were deconsolidated effective December 31, 2005, as a result of the filings by the Canadian Debtors under the CCAA in the Canadian Court. The term “Calpine Corporation” shall refer only to Calpine Corporation and not to any of its subsidiaries. Unless and as otherwise stated, any references in this Report to any agreement means such agreement and all schedules, exhibits and attachments thereto in each case as amended, restated, supplemented or otherwise modified to the date of this Report.

ABBREVIATION	DEFINITION
2005 Form 10-K	Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on May 19, 2006
2014 Convertible Notes	Contingent Convertible Notes Due 2014
345(b) Waiver Order	Order pursuant to Section 345(b) of the Bankruptcy Code authorizing continued (i) use of existing investment guidelines and (ii) operation of certain bank accounts dated May 4, 2006
401k Plan	Calpine Corporation Retirement Savings Plan
Acadia PP	Acadia Power Partners, LLC
AOCI	Accumulated Other Comprehensive Income
APB	Accounting Principles Board
Aries	MEP Pleasant Hill, LLC
ASC	Aircraft Services Corporation, an affiliate of General Electric Capital Corporation
Bankruptcy Code	United States Bankruptcy Code
Bankruptcy Courts	The U.S. Bankruptcy Court and the Canadian Court
Btu(s)	British thermal unit(s)
CAISO	California Independent System Operator
Calgary Energy Centre	Calgary Energy Centre Limited Partnership
CalGen	Calpine Generating Company, LLC, formerly Calpine Construction Finance Company II LLC
Calpine Debtor(s)	The U.S. Debtors and the Canadian Debtors
Calpine Jersey II	Calpine European Funding (Jersey) Limited
CalPX	California Power Exchange
CalPX Price	CalPX zonal day-ahead clearing price
Canadian Court	The Court of Queen’s Bench of Alberta, Judicial District of Calgary
Canadian Debtor(s)	The subsidiaries and affiliates of Calpine Corporation that have been granted creditor protection under the CCAA in the Canadian Court

ii

ABBREVIATION	DEFINITION
Cash Collateral Order	Second Amended Final Order of the U.S. Bankruptcy Court Authorizing Use of Cash Collateral and Granting Adequate Protection, dated February 24, 2006, as modified by orders entered by the U.S. Bankruptcy Court on June 21, 2006, July 12, 2006, and October 25, 2006
CCAA	Companies’ Creditors Arrangement Act (Canada)
CCFC	Calpine Construction Finance Company, L.P
CCFCP	CCFC Preferred Holdings, LLC
CCRC	Calpine Canada Resources Company, formerly Calpine Canada Resources Ltd.
CDWR	California Department of Water Resources
CES	Calpine Energy Services, L.P.
CES-Canada	Calpine Energy Services Canada Partnership
Chapter 11	Chapter 11 of the Bankruptcy Code
Chubu	Chubu Electric Power Company, Inc.
Cleco	Cleco Corp.
CNEM	Calpine Northbrook Energy Marketing, LLC
Collateral Trustee	The Bank of New York as collateral trustee for holders of the First Priority Notes and the Second Priority Debt
Committees	The Creditors’ Committee and the Ad Hoc Committee of Second Lien Holders of Calpine Corporation
Company	Calpine Corporation, a Delaware corporation, and subsidiaries
Creditors’ Committee	The Official Committee of Unsecured Creditors of Calpine Corporation
CPUC	California Public Utilities Commission
DB London	Deutsche Bank AG London
Deer Park	Deer Park Energy Center Limited Partnership
DIP	Debtor-in-possession

iii

ABBREVIATION	DEFINITION
DIP Facility	The Revolving Credit, Term Loan and Guarantee Agreement, dated as of December 22, 2005, as amended on January 26, 2006, and as amended and restated by that certain Amended and Restated Revolving Credit, Term Loan and Guarantee Agreement, dated as of February 23, 2006, among Calpine Corporation, as borrower, the Guarantors party thereto, the Lenders from time to time party thereto, Credit Suisse Securities (USA) LLC and Deutsche Bank Securities Inc., as joint syndication agents, Deutsche Bank Trust Company Americas, as administrative agent for the First Priority Lenders, General Electric Capital Corporation, as Sub-Agent for the Revolving Lenders, Credit Suisse, as administrative agent for the Second Priority Term Lenders, Landesbank Hessen Thuringen Girozentrale, New York Branch, General Electric Capital Corporation and HSH Nordbank AG, New York Branch, as joint documentation agents for the First Priority Lenders and Bayerische Landesbank, General Electric Capital Corporation and Union Bank of California, N.A., as joint documentation agents for the Second Priority Lenders
E&S	Electricity and steam
EOB	California Electricity Oversight Board
ERISA	Employee Retirement Income Security Act
ESPP	2000 Employee Stock Purchase Plan
Exchange Act	United States Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FFIC	Fireman’s Fund Insurance Company
FIN	FASB Interpretation Number
First Priority Notes	9 5/8% First Priority Senior Secured Notes Due 2014
First Priority Trustee	Until February 2, 2006, Wilmington Trust Company, as trustee, and from February 3, 2006, and thereafter, Law Debenture Trust Company of New York, as successor trustee, under the Indenture, dated as of September 30, 2004, with respect to the First Priority Notes
FPA	Federal Power Act
Freeport	Freeport Energy Center, LP
GAAP	Generally accepted accounting principles in the United States
GEC	Gilroy Energy Center, LLC
General Electric	General Electric Company
Geysers Assets	19 geothermal power plant assets located in northern California
GPC	Geysers Power Company, LLC
Greenfield LP	Greenfield Energy Centre LP

iv

ABBREVIATION	DEFINITION
Harbert Convertible Fund	Harbert Convertible Arbitrage Master Fund, L.P.
Harbert Distressed Fund	Harbert Distressed Investment Master Fund, Ltd.
Heat Rate	A measure of the amount of fuel required to produce a unit of electricity
IRS	United States Internal Revenue Service
ISO	Independent System Operator
King City Cogen	Calpine King City Cogen, LLC
KWh	Kilowatt hour(s)
LIBOR	London Inter-Bank Offered Rate
LSTC	Liabilities Subject to Compromise
Mankato	Mankato Energy Center, LLC
Metcalf	Metcalf Energy Center, LLC
Mitsui	Mitsui & Co., Ltd.
MMBtu	Million Btu
Moapa	Moapa Energy Center, LLC
MRTU	CAISO’s Market Redesign and Technology Upgrade
MW	Megawatt(s)
MWh	Megawatt hour(s)
Ninth Circuit Court of Appeals	United States Court of Appeals for the Ninth Circuit
NOL	Net operating loss
Non-Debtor(s)	The subsidiaries and affiliates of Calpine Corporation that are not Calpine Debtors
Non-U.S. Debtor(s)	The consolidated subsidiaries and affiliates of Calpine Corporation that are not U.S. Debtor(s)
Northern District Court	United States District Court for the Northern District of California
NPC	Nevada Power Company
OCI	Other Comprehensive Income
Oneta	Oneta Energy Center

v

ABBREVIATION	DEFINITION
Panda	Panda Energy International, Inc., and related party PLC II, LLC
PCF	Power Contract Financing, L.L.C.
PCF III	Power Contract Financing III, LLC
Petition Date	December 20, 2005
PG&E	Pacific Gas and Electric Company
POX	Plant operating expense
PPA(s)	Power purchase agreement(s)
QF(s)	Qualifying facility(ies)
RMR Contracts	Reliability Must Run contracts
Rosetta	Rosetta Resources Inc.
Saltend	Saltend Energy Centre
SAB	Staff Accounting Bulletin
SDG&E	San Diego Gas & Electric Company
SDNY Court	United States District Court for the Southern District of New York
SEC	United States Securities and Exchange Commission
Second Priority Debt	Calpine Corporation’s Second Priority Secured Floating Rate Notes Due 2007, 8 1/2% Second Priority Senior Secured Notes Due 2010, 8 3/4% Second Priority Senior Secured Notes Due 2013, 9 7/8% Second Priority Senior Secured Notes Due 2011, and Senior Secured Term Loans Due 2007
Second Priority Notes	Calpine Corporation’s Second Priority Senior Secured Floating Rate Notes Due 2007, 8 1/2% Second Priority Senior Secured Notes Due 2010, 8 3/4% Second Priority Senior Secured Notes Due 2013 and 9 7/8% Second Priority Senior Secured Notes Due 2011
Second Priority Secured Debt Instruments	The Indentures between the Company and Wilmington Trust Company, as Trustee, relating to the Second Priority Notes and the Credit Agreement among the Company, as Borrower, Goldman Sachs Credit Partners L.P., as Administrative Agent, Sole Lead Arranger and Sole Book Runner, The Bank of Nova Scotia, as Arranger and Syndication Agent, TD Securities (USA) Inc., ING (U.S.) Capital LLC and Landesbank Hessen-Thuringen, as Co-Arrangers, and Credit Lyonnais New York Branch and Union Bank of California, N.A., as Managing Agent, relating to the Company’s Senior Secured Term Loans Due 2007
Second Priority Trustee	Wilmington Trust Company, as trustee under the Indentures with respect to the Second Priority Notes
Securities Act	United States Securities Act of 1933, as amended

vi

ABBREVIATION	DEFINITION
SFAS	Statement of Financial Accounting Standards
SFAS No. 123-R	FASB Statement No. 123-R (As Amended), “Accounting for Stock-Based Compensation—Share-Based Payment”
SIP	1996 Stock Incentive Plan
SPPC	Sierra Pacific Power Company
TSA(s)	Transmission service agreement(s)
TTS	Thomassen Turbine Systems, B.V.
ULC I	Calpine Canada Energy Finance ULC
ULC II	Calpine Canada Energy Finance II ULC
U.S.	United States of America
U.S. Bankruptcy Court	United States Bankruptcy Court for the Southern District of New York
U.S. Debtor(s)	Calpine Corporation and each of its subsidiaries and affiliates that have filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court, which matters are being jointly administered in the U.S. Bankruptcy Court under the caption In re Calpine Corporation, et al., Case No. 05-60200 (BRL)
Valladolid	Valladolid III Energy Center

vii

Index  Definitions

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements.

CALPINE CORPORATION AND SUBSIDIARIES

(DEBTOR-IN-POSSESSION)

CONSOLIDATED CONDENSED BALANCE SHEETS

September30,2006 and December31,2005

(Unaudited)

	September30,		December31,
	2006		2005
	(In thousands, except share and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	988,975	$	785,637
Accounts receivable, net		828,043		1,008,430
Margin deposits and other prepaid expense		341,972		434,363
Inventories		180,757		150,444
Restricted cash		431,769		457,510
Current derivative assets		184,878		489,499
Current assets held for sale		367,600		39,542
Other current assets		102,592		62,612
Total current assets		3,426,586		3,428,037
Restricted cash, net of current portion		191,999		613,440
Notes receivable, net of current portion		145,294		165,124
Project development costs		26,309		24,232
Investments		101,311		83,620
Deferred financing costs		157,843		210,809
Prepaid lease, net of current portion		184,781		515,828
Property, plant and equipment, net		13,889,035		14,119,215
Goodwill		45,160		45,160
Other intangible assets, net		51,332		54,143
Long-term derivative assets		394,392		714,226
Other assets		613,672		570,963
Total assets	$	19,227,714	$	20,544,797

The accompanying notes are an integral part of these

Consolidated Condensed Financial Statements.

1

Index  Definitions

CONSOLIDATED CONDENSED BALANCE SHEETS – (Continued)

(Unaudited)

	September30,			December31,
	2006			2005
	(In thousands, except share and per share amounts)
LIABILITIES&STOCKHOLDERS’DEFICIT
Current liabilities:
Accounts payable	$	483,904		$	399,450
Accrued payroll and related expense		37,848			29,483
Accrued interest payable		174,542			195,980
Income taxes payable		99,073			99,073
Notes payable and other borrowings, current portion		149,738			188,221
Preferred interest, current portion		8,722			9,479
Capital lease obligations, current portion		284,530			191,497
CCFC financing, current portion		3,208			784,513
CalGen financing, current portion		2,510,827			2,437,982
Construction/project financing, current portion		558,354			1,160,593
Senior notes and term loans, current portion		—			641,652
DIP Facility, current portion		3,500			—
Current derivative liabilities		277,880			728,894
Current liabilities held for sale		363,780			—
Other current liabilities		335,580			275,595
Total current liabilities		5,291,486			7,142,412
Notes payable and other borrowings, net of current portion		420,719			558,353
Preferred interests, net of current portion		574,893			583,417
Capital lease obligations, net of current portion		224			95,260
CCFC financing, net of current portion		778,663			—
Construction/project financing, net of current portion		1,474,200			1,200,432
DIP Facility, net of current portion		993,875			25,000
Deferred income taxes, net of current portion		405,153			353,386
Deferred revenue		109,920			138,653
Long-term derivative liabilities		528,159			919,084
Other liabilities		156,363			151,437
Total liabilities not subject to compromise		10,733,655			11,167,434
Liabilities subject to compromise		15,039,613			14,610,064
Commitments and contingencies (see Note 12)		—			—
Minority interests		270,712			275,384
Stockholders’ equity (deficit):
Preferred stock, $.001 par value per share; authorized 10,000,000 shares; none issued and outstanding in 2006 and 2005		—			—
Common stock, $.001 par value per share; authorized 2,000,000,000 shares; issued and outstanding 543,844,664 in 2006 and 569,081,863 in 2005		544			569
Additional paid-in capital		3,270,575			3,265,458
Additional paid-in capital, loaned shares		185,600			258,100
Additional paid-in capital, returnable shares		(185,600	)		(258,100	)
Accumulated deficit		(10,018,700	)		(8,613,160	)
Accumulated other comprehensive loss		(68,685	)		(160,952	)
Total stockholders’ deficit		(6,816,266	)		(5,508,085	)
Total liabilities and stockholders’ deficit	$	19,227,714		$	20,544,797

The accompanying notes are an integral part of these

Consolidated Condensed Financial Statements.

2

Index  Definitions

CALPINE CORPORATION AND SUBSIDIARIES

(DEBTOR-IN-POSSESSION)

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

For the Three and Nine Months Ended September30,2006 and 2005

(Unaudited)

	Three Months Ended						Nine Months Ended
	September30,						September30,
	2006			2005			2006			2005
	(In thousands, except share and per share amounts)
Revenue:
Electricity and steam revenue	$	1,842,575		$	2,096,323		$	4,070,045		$	4,625,078
Sales of purchased power and gas for hedging and optimization		272,932			1,110,131			891,092			2,767,604
Mark-to-market activities, net		28,461			40,854			88,151			40,197
Other revenue		14,411			34,282			56,657			93,349
Total revenue		2,158,379			3,281,590			5,105,945			7,526,228
Cost of revenue:
Plant operating expense		174,552			180,336			519,877			555,433
Royalty expense		7,151			9,988			18,411			28,348
Transmission purchase expense		18,213			23,088			56,218			63,770
Purchased power and gas expense for hedging and optimization		296,385			1,068,129			857,484			2,583,802
Fuel expense		1,105,248			1,567,504			2,473,657			3,336,248
Depreciation and amortization expense		121,569			131,006			350,642			371,340
Operating plant impairments		7			—			52,507			—
Operating lease expense		11,432			28,792			53,030			79,097
Other cost of revenue		14,232			33,620			53,433			106,865
Total cost of revenue		1,748,789			3,042,463			4,435,259			7,124,903
Gross profit		409,590			239,127			670,686			401,325
(Income) from unconsolidated investments		—			(5,384	)		—			(14,644	)
Equipment, development project and other impairments		(3,462	)		460			64,169			47,356
Long-term service agreement cancellation charge		—			553			—			34,445
Project development expense		5,153			10,399			13,249			24,972
Research and development expense		4,184			3,342			11,178			15,502
Sales, general and administrative expense		49,026			54,593			147,349			176,318
Income from operations		354,689			175,164			434,741			117,376
Interest expense		227,724			380,994			819,576			1,027,382
Interest (income)		(19,918	)		(26,640	)		(59,442	)		(57,417	)
Minority interest expense		7,658			10,977			10,325			31,763
(Income) loss from repurchase of various issuances of debt		—			(15,530	)		18,131			(166,456	)
Other (income) expense, net		(8,912	)		50,311			(10,766	)		71,446

The accompanying notes are an integral part of these

Consolidated Condensed Financial Statements.

3

Index  Definitions

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS — (Continued)

(Unaudited)

	Three Months Ended					Nine Months Ended
	September30,					September30,
	2006		2005			2006			2005
	(Inthousands,exceptpershareamounts)
Income (loss) before reorganization items, provision (benefit) for income taxes, discontinued operations and cumulative effect of a change in accounting principle	$	148,137	$	(224,948	)	$	(343,083	)	$	(789,342	)
Reorganization items		145,273		—			1,098,594			—
Income (loss) before provision (benefit) for income taxes, discontinued operations and cumulative effect of a change in accounting principle		2,864		(224,948	)		(1,441,677	)		(789,342	)
Provision (benefit) for income taxes		1,202		17,487			(35,632	)		(167,866	)
Income (loss) before discontinued operations and cumulative effect of a change in accounting principle		1,662		(242,435	)		(1,406,045	)		(621,476	)
Discontinued operations, net of tax provision (benefit) of $—, $170,514, $—, and $137,629		—		25,746			—			(62,403	)
Cumulative effect of a change in accounting principle, net of tax provision of $—, $—, $312, and $—		—		—			505			—
Net income (loss)	$	1,662	$	(216,689	)	$	(1,405,540	)	$	(683,879	)
Basic and diluted income (loss) per common share:
Weighted average shares of common stock outstanding		479,136		478,461			479,136			458,483
Income (loss) before discontinued operations and cumulative effect of a change in accounting principle	$	—	$	(0.51	)	$	(2.93	)	$	(1.36	)
Discontinued operations, net of tax				0.06			—			(0.13	)
Cumulative effect of a change in accounting principle, net of tax		—		—			—			—
Net income (loss)	$	—	$	(0.45	)	$	(2.93	)	$	(1.49	)

The accompanying notes are an integral part of these

Consolidated Condensed Financial Statements.

4

Index  Definitions

CALPINE CORPORATION AND SUBSIDIARIES

(DEBTOR-IN-POSSESSION)

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September30,2006 and 2005

(Unaudited)

	Nine Months Ended
	September30,
	2006			2005
	(In thousands)
Cash flows from operating activities:
Net loss	$	(1,405,540	)	$	(683,879	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation and amortization		437,265			596,118
Impairment charges		116,676			261,532
Deferred income taxes, net		(35,632	)		(30,237	)
Loss (gain) on sale of assets		1,594			(351,950	)
Foreign currency transaction (gain) loss		(1,658	)		57,182
Gain on settlement of notes receivable		(6,025	)		—
Loss (gain) on repurchase of debt		18,131			(166,456	)
Minority interest expense		10,325			31,763
Change in net derivative liability		31,757			17,041
Income from unconsolidated investments in power projects		—			(14,804	)
Distributions from unconsolidated investments in power projects		—			16,862
Stock compensation expense		5,909			16,430
Reorganization items		975,922			—
Other		170			47,647
Change in operating assets and liabilities:
Accounts receivable		154,719			(416,488	)
Other current assets		19,992			15,788
Other assets		2,349			(35,587	)
Accounts payable, liabilities subject to compromise and accrued expenses		(238,203	)		205,737
Other liabilities		78,995			25,328
Net cash provided by (used in) operating activities		166,746			(407,973	)
Cash flows from investing activities:
Purchases of property, plant and equipment		(159,319	)		(675,714	)
Disposals of property, plant and equipment		12,924			1,860,981
Purchase of Geysers Assets		(266,846	)		—
Disposals of investments, net of holdbacks		37,988			169,400
Advances to joint ventures		(31,000	)		—
Project development costs		—			(13,095	)
Cash flows from derivatives not designated as hedges		(95,371	)		45,777
Decrease (increase) in restricted cash		441,953			(559,946	)
Other		13,478			(4,714	)
Net cash (used in) provided by investing activities		(46,193	)		822,689

The accompanying notes are an integral part of these

Consolidated Condensed Financial Statements.

5

Index  Definitions

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS – (Continued)

(Unaudited)

	Nine Months Ended
	September30,
	2006			2005
	(In thousands)
Cash flows from financing activities:
Borrowings from notes payable and lines of credit	$	—		$	6,488
Repayments of notes payable and lines of credit		(173,616	)		(808,784	)
Borrowings from project financing		121,097			620,956
Repayments of project financing		(108,986	)		(176,799	)
DIP Facility borrowings		1,150,000			—
Repayments of DIP Facility		(177,625	)		—
Proceeds from issuance of convertible senior notes		—			650,000
Repurchase of convertible senior notes		—			(15	)
Repayment of convertible debentures to Calpine Capital Trust III		—			(517,500	)
Repayments and repurchases of senior notes		(646,105	)		(821,252	)
Proceeds from issuance of preferred interests		—			565,000
Redemptions of preferred interests		(9,281	)		—
Proceeds from Deer Park prepaid commodity contract		—			290,571
Financing costs		(34,428	)		(89,318	)
Other		(20,819	)		(28,318	)
Net cash provided by (used in) financing activities		100,237			(308,971	)
Effect of exchange rate changes on cash and cash equivalents		—			741
Net increase in cash and cash equivalents, including discontinued operations cash		220,790			106,486
Change in discontinued operations cash classified as assets held for sale		(17,452	)		18,627
Net increase in cash and cash equivalents		203,338			125,113
Cash and cash equivalents, beginning of period		785,637			718,023
Cash and cash equivalents, end of period	$	988,975		$	843,136
Cash paid during the period for:
Interest, net of amounts capitalized	$	772,462		$	962,866
Income taxes	$	234		$	23,653
Reorganization items included in operating activities	$	77,784		$	—
Reorganization items included in financing activities	$	33,838		$	—

	Nine Months Ended
	September30,
	2006		2005
	(In thousands)
Supplemental disclosure of non-cash investing and financing activities:
Acquisition of Geysers Assets	$	180,607	$	—
Letter of credit draws under the CalGen financing	$	71,458	$	—
Capital contribution (equipment) to Greenfield Energy Centre	$	27,854	$	—
Fair value of common stock issued to extinguish convertible notes	$	—	$	94,315

The accompanying notes are an integral part of these

Consolidated Condensed Financial Statements.

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CALPINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

September30,2006

(Unaudited)

1.Basis of Presentation and Summary of Significant Accounting Policies

Basis of Interim Presentation — The accompanying unaudited interim Consolidated Condensed Financial Statements of Calpine Corporation, a Delaware corporation, and subsidiaries have been prepared by the Company pursuant to the rules and regulations of the SEC. In the opinion of management, the Consolidated Condensed Financial Statements include the adjustments necessary for a fair statement of the information required to be set forth therein. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted from these statements pursuant to such rules and regulations and, accordingly, these financial statements should be read in conjunction with the audited Consolidated Financial Statements of the Company for the year ended December 31, 2005, included in our 2005 Form 10-K. The results for interim periods are not necessarily indicative of the results for the entire year.

Upon filing under Chapter 11 in the United States and for creditor protection under the CCAA in Canada, we deconsolidated most of our Canadian and other foreign entities as we determined that the administration of the CCAA proceedings in a jurisdiction other than that of the U.S. Debtors resulted in a loss of the elements of control necessary for consolidation. Because our Consolidated Condensed Financial Statements exclude the financial statements of the Canadian Debtors, the information in this Report principally describes the Chapter 11 cases and only describes the CCAA proceedings where they have a material effect on our operations or where such information provides necessary background information. See Note 2 for further discussion.

Reclassifications — Certain prior years’ amounts in the Consolidated Condensed Financial Statements were reclassified to conform to the current period presentation. Sales of purchased gas for hedging and optimization were combined with sales of purchased power for hedging and optimization and are now being reported as sales of purchased power and gas for hedging and optimization. Purchased gas expense for hedging and optimization was combined with purchased power expense for hedging and optimization and is now being reported as purchased power and gas expense for hedging and optimization. Equipment cancellation and impairment cost is now being reported as equipment, development project and other impairments. Transmission sales revenue is now included in other revenue.

Unrestricted Subsidiaries — The information in this paragraph is required to be provided under the terms of the Second Priority Secured Debt Instruments. We have designated certain of our subsidiaries as “unrestricted subsidiaries” under the Second Priority Secured Debt Instruments. A subsidiary with “unrestricted” status thereunder generally is not required to comply with the covenants contained therein that are applicable to “restricted subsidiaries.” We have designated Calpine Gilroy 1, Inc., Calpine Gilroy 2, Inc. and Calpine Gilroy Cogen, L.P. as “unrestricted subsidiaries” for purposes of the Second Priority Secured Debt Instruments.

Cash and Cash Equivalents — We have certain project finance facilities and lease agreements that establish segregated cash accounts. These accounts have been pledged as security in favor of the lenders to such project finance facilities, and the use of certain cash balances on deposit in such accounts with our project financed securities is limited to the operations of the respective projects. At September 30, 2006, and December 31, 2005, $675.8 million and $518.1 million, respectively, of the cash and cash equivalents balance were subject to such project finance facilities and lease agreements.

Restricted Cash — We are required to maintain cash balances that are restricted by provisions of certain of our debt and lease agreements or by 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, major maintenance and debt repurchases. Funds that can be used to satisfy obligations due during the next twelve months are classified as current

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restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents in the Consolidated Condensed Statements of Cash Flows.

The table below represents the components of our consolidated restricted cash as of September 30, 2006, and December 31, 2005 (in thousands):

	September30,2006						December31,2005
	Current		Non-Current		Total		Current		Non-Current		Total
Debt service	$	97,962	$	113,681	$	211,643	$	152,512	$	118,000	$	270,512
Rent reserve		32,511		—		32,511		50,020		—		50,020
Construction/major maintenance		83,935		29,526		113,461		77,448		36,732		114,180
Security/project reserves		71,061		32,000		103,061		—		406,905		406,905
Collateralized letters of credit and other credit support		101,632		—		101,632		148,959		9,327		158,286
Other		44,668		16,792		61,460		28,571		42,476		71,047
Total	$	431,769	$	191,999	$	623,768	$	457,510	$	613,440	$	1,070,950

Commodity Margin Deposits — As of September 30, 2006, and December 31, 2005, to support commodity transactions, we had margin deposits with third parties of $194.9 million and $287.5 million, respectively. Counterparties had deposited with us $6.9 million and $27.0 million as margin deposits at September 30, 2006, and December 31, 2005, respectively.

Effective Tax Rate — For the three months ended September 30, 2006 and 2005, the effective tax rate from continuing operations was 42.0% and (7.8)%, respectively. The quarterly tax provision on continuing operations is based on the estimated annual effective tax rate calculated by considering the Company’s annual forecast; the effect of permanent non-taxable and non-deductible items; and the establishment of valuation allowances on deferred tax assets; and therefore, we believe that an evaluation of the effective rate is more meaningful on a year-to-date basis.

For the nine months ended September 30, 2006 and 2005, the effective tax rate from continuing operations was 2.5% and 21.3%, respectively. The effective tax rate for the nine months ended September 30, 2006 was primarily impacted by valuation allowances of approximately $355 million that we recorded against deferred tax assets to the extent they cannot be used to offset future income arising from the expected reversal of taxable differences. Primarily due to the valuation allowances, we recognized less tax benefit on our pre-tax loss from continuing operations for the nine months ended September 30, 2006, than for the same period in the prior year. In addition, we recorded certain discrete items for the nine months ended September 30, 2006, including tax benefits of $57.5 million primarily from the reversal of valuation allowances on deferred tax assets related to our cash flow hedges and CCFC NOL deferred tax assets. These tax benefits were partially offset by a $21.9 million provision related to adjustments of certain estimated deferred tax items from property differences. For the nine months ended September 30, 2005, the impact of a $143.4 million valuation allowance recorded against certain NOL deferred tax assets associated with CCFC was substantially offset by additional tax benefit resulting from the increase in estimated pre-tax losses for full year 2005.

During the fourth quarter of 2005, Calpine Corporation and many of its subsidiaries filed for Chapter 11 protection and recorded significant restructuring charges. Further, in accordance with Section 382 of the Internal Revenue Code certain transfers of our equity, or issuances of equity in connection with our restructuring, may impair our ability to utilize our federal income tax NOL carryforwards in the future. Under federal income tax law, a corporation is generally permitted to deduct from taxable income in any year NOLs carried forward from prior years subject to certain time limitations as prescribed by the Internal Revenue Code. Our ability to deduct such NOL carryforwards could be subject to a significant limitation if we were to undergo an “ownership change” during or as a result of our Chapter 11 filings. The U.S. Bankruptcy

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Court has entered an order that places certain limitations on trading in our common stock or certain securities, including options, convertible into our common stock during the pendency of the Chapter 11 cases. However, we can provide no assurances that these limitations will prevent an “ownership change” or that our ability to utilize our NOL carryforwards may not be significantly limited as a result of our reorganization. We also cannot provide any assurances that our NOL carryforwards will exist after our Chapter 11 restructuring, in light of the cancellation of indebtedness income that may be recognized as a result of the Chapter 11 restructuring.

GAAP requires that all available evidence, both positive and negative, be considered to determine whether, based on the weight of that evidence, a valuation allowance is needed. Future realization of the tax benefit of an existing deductible temporary difference or carryforward ultimately depends on the existence of sufficient taxable income of the appropriate character within the carryback or carryforward periods available under the tax law. Primarily due to our inability to assume future profits and due to our reduced ability to implement tax-planning strategies to utilize our NOLs while in Chapter 11, we concluded that valuation allowances on a portion of our deferred tax assets were required. See Note 2 for information regarding our Chapter 11 filings.

We are under an IRS review for the years 1999 through 2002 and are periodically under audit for various state and foreign jurisdictions for income and sales and use taxes. We believe that the ultimate resolution of these examinations will not have a material effect on our consolidated financial position.

Recent Accounting Pronouncements

SFAS No.123-R

In December 2004, FASB issued SFAS No. 123-R which requires a public company to use the fair value method of accounting for stock-based compensation. We adopted this standard as of January 1, 2006, and applied the modified prospective transition method. The modified prospective approach applies to the unvested portion of all awards granted prior to January 1, 2006, and to all prospective awards. Prior financial statements are not restated under this method.

SFAS No. 123-R also requires the cash flows resulting from the tax benefits that occur from estimated tax deductions in excess of the compensation cost recognized be presented as financing cash flows in the statement of cash flows. Prior to adopting this statement, we presented tax benefits from allowable deductions as operating cash flows in our Consolidated Condensed Statement of Cash Flows.

As we previously adopted the fair value method of accounting under SFAS No. 123 as amended by SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure” (“SFAS No. 123”) on January 1, 2003, the adoption of SFAS No. 123-R did not have a material impact on our results of operations, cash flows or financial position. Upon adoption as of January 1, 2006, we recorded a cumulative effect of a change in accounting principle that increased income by $0.5 million, net of tax. See Note 11 for further details.

SFAS No.154

In May 2005, FASB issued SFAS No. 154, “Accounting Changes and Error Corrections.” This statement replaces APB Opinion No. 20, “Accounting Changes,” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements,” and changes the requirements for the accounting for and reporting of a change in accounting principle. SFAS No. 154 applies to all voluntary changes in accounting principle. SFAS No. 154 is effective for fiscal years beginning after December 15, 2005. Adoption of this statement did not materially impact our results of operations, cash flows or financial position.

FASB Interpretation No.48

In June 2006, FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109.” FIN 48 addresses the recognition and measurement of a tax position taken or expected to be taken in a

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tax return. This interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006, with early adoption permitted. We are currently assessing the impact this standard will have on our results of operations, cash flows and financial position.

SFAS No.157

In September 2006, FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value in GAAP, and enhances disclosures about fair value measurements. SFAS No. 157 applies when other accounting pronouncements require fair value measurements; it does not require new fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, with early adoption encouraged. We are currently assessing the impact this standard will have on our results of operations, cash flows and financial position.

SAB No. 108

In September 2006, the SEC Staff issued SAB No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements.” SAB No. 108 establishes a “dual approach” for quantifying the effects of financial statement errors which requires the quantification of the effect of financial statement errors on each financial statement, as well as related disclosures. SAB No. 108 permits public companies to initially adopt its provisions either by (i) restating prior financial statements as if the “dual approach” had always been applied or (ii) recording the cumulative effect of initially applying the “dual approach” as adjustments to the carrying values of assets and liabilities as of January 1, 2006 with an offsetting adjustment recorded in the opening balance of retained earnings. Public companies must begin to apply the provisions of SAB No. 108 no later than their annual financial statements for their first fiscal year ending after November 15, 2006. We do not expect the application of the provisions of SAB No. 108 will have a material impact on our results of operations, cash flows or financial condition.

2.Chapter11 Cases and CCAA Proceedings

Since the Petition Date, Calpine Corporation and 273 of its wholly owned subsidiaries in the U.S. have filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court. Similarly, since the Petition Date, 12 of Calpine’s Canadian subsidiaries have filed for creditor protection under the CCAA in the Canadian Court. Certain other subsidiaries could file under Chapter 11 in the U.S. or for creditor protection under the CCAA in Canada in the future. The Chapter 11 cases are being jointly administered for procedural purposes only by the U.S. Bankruptcy Court under the case captioned In re Calpine Corporation et al., Case No. 05-60200 (BRL). The Calpine Debtors are continuing to operate their business as debtors-in-possession and will continue to conduct business in the ordinary course under the protection of the Bankruptcy Courts. Generally, while a plan or plans of reorganization (with respect to the U.S. Debtors) or arrangement (with respect to the Canadian Debtors) are developed, all actions to enforce or otherwise effect repayment of liabilities preceding the Petition Date as well as all pending litigation against the Calpine Debtors are stayed while the Calpine Debtors continue their business operations as debtors-in-possession.

At this time, it is not possible to accurately predict the effects of the reorganization process on our business or if and when some or all of the U.S. Debtors may emerge from Chapter 11 or the Canadian Debtors may emerge from the CCAA proceedings. The prospects for future results depend primarily on the timely and successful development, confirmation and implementation of a plan or plans of reorganization by the U.S. Debtors. There can be no assurance that a successful plan or plans of reorganization will be proposed by the U.S. Debtors, supported by the U.S. Debtors’ creditors or confirmed by the U.S. Bankruptcy Court, or that any such plan or plans will be consummated. The ultimate recovery, if any, that creditors and equity security holders receive will not be determined until confirmation of a plan or plans of reorganization. No assurance can be given as to what values, if any, will be ascribed in the Chapter 11 cases or in the CCAA proceedings to the interests of each of the various creditor and equity or other security holder constituencies, and it is possible that the equity interests in or other securities issued by Calpine and the other Calpine Debtors will be restructured in a manner that will substantially reduce or eliminate any remaining value of such equity interests or other securities, or that certain creditors may ultimately

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receive little or no payment with respect to their claims. Whether or not a plan or plans of reorganization or arrangement are approved, it is possible that the assets of any one or more of the Calpine Debtors may be liquidated.

As a result of our Chapter 11 filings and the other matters described herein, including the uncertainties related to the fact that we have not yet had time to complete and have approved a plan of reorganization, there is substantial doubt about our ability to continue as a going concern. Our ability to continue as a going concern, including our ability to meet our ongoing operational obligations, is dependent upon, among other things: (i) our ability to maintain adequate cash on hand; (ii) our ability to generate cash from operations; (iii) the cost, duration and outcome of the restructuring process; (iv) our ability to comply with our DIP Facility agreement and the adequate assurance provisions of the Cash Collateral Order and (v) our ability to achieve profitability following a restructuring. These challenges are in addition to those operational and competitive challenges faced by us in connection with our business. In conjunction with our advisors, we are implementing strategies to ensure that we maintain adequate liquidity and will be able to continue as a going concern. However, there can be no assurance as to the success of such efforts.

Chapter11 Cases

On January 26, 2006, the U.S. Bankruptcy Court entered a final order approving our DIP Facility and removing its previously imposed limitation on our ability to borrow thereunder. See Note 7 for further details regarding the DIP Facility. In addition, the U.S. Bankruptcy Court approved cash collateral and adequate assurance stipulations in connection with the approval of the DIP Facility, which has allowed our business activities to continue to function. We have also sought and obtained U.S. Bankruptcy Court approval through our “first day” and subsequent motions to continue to pay critical vendors, meet our pre-petition and post-petition payroll obligations, maintain our cash management systems, collateralize certain of our gas supply contracts, enter into and collateralize trading contracts, pay our taxes, continue to provide employee benefits, maintain our insurance programs and implement an employee severance program, which has allowed us to continue to operate the existing business in the ordinary course. In addition, the U.S. Bankruptcy Court has approved certain trading notification and transfer procedures designed to allow us to restrict trading in our common stock (and related securities) which could negatively impact our accumulated NOLs and other tax attributes, and granted us extensions of time during which we have the exclusive right to file and seek approval of a plan of reorganization.

The U.S. Bankruptcy Court had established August 1, 2006, as the bar date for filing proofs of claim against the U.S. Debtors’ estates, other than claims against Calpine Geysers Company, L.P., one of the U.S. Debtors, as to which the bar date is October 31, 2006. Under certain limited circumstances, some creditors will be permitted to file claims after the applicable bar dates. Accordingly, it is likely that not all potential claims were filed as of September 30, 2006. As to claims that are filed, differences between amounts recorded by the U.S. Debtors and proofs of claim filed by the creditors will be investigated and resolved through the claims reconciliation process. Because of the number of creditors and claims, the claims reconciliation process may take considerable time to complete and we expect will continue after our emergence from Chapter 11. We have begun the claims review process, and have filed claims objections (and expect that we will file additional claims objections) with the U.S. Bankruptcy Court pursuant to which we seek to expunge, disallow or reclassify certain claims. Accordingly, the ultimate number and amount of allowed claims is not presently known, nor can the ultimate recovery with respect to such allowed claims be presently determined. Notwithstanding the foregoing, we have recognized certain charges related to expected allowed claims. The U.S. Bankruptcy Court will ultimately determine liability amounts that will be allowed for claims. As claims are resolved, or where better information becomes available and is evaluated, we will make adjustments to the liabilities recorded on our financial statements as appropriate. Any such adjustments could be material to our consolidated financial position and results of operations in any given period.

Under the Bankruptcy Code, we have the right to assume, assume and assign, or reject certain executory contracts and unexpired leases, subject to the approval of the U.S. Bankruptcy Court and certain other conditions. Parties to executory contracts or unexpired leases rejected or deemed rejected by a U.S. Debtor may file proofs of claim against that U.S. Debtor’s estate for damages and parties to executory contracts or unexpired leases that are assumed have an opportunity to assert cure amounts prior to such assumptions. Due to the ongoing evaluation of contracts for assumption or rejection and the uncertain nature of many of the potential claims for damages, we cannot project the magnitude of these potential claims at this time. We had until July 18, 2006, to assume unexpired non-residential real property leases. Absent the consent of the applicable

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counterparty, such leases not assumed by that date are deemed rejected (except for Calpine Debtors filing after the Petition Date, which have a commensurately longer period of time). We have entered into stipulations with counterparties extending the time to assume certain of such leases that we are still examining. All other non-assumed leases have been deemed rejected. Further, on July 12, 2006, the U.S. Bankruptcy Court approved our motion to extend the time for us to assume leases between U.S. Debtor-lessees and any affiliated lessors until the confirmation of a plan of reorganization of the applicable U.S. Debtor-lessee. Without an extension of time to assume, leases between U.S. Debtors and their affiliates would also have been deemed rejected if not assumed by July 18, 2006.

Under the Bankruptcy Code, we have the exclusive right to file and solicit acceptances of a plan or plans of reorganization for a limited period of time. On April 11, 2006, the U.S. Bankruptcy Court granted our application for an extension of the period during which we have the exclusive right to file a reorganization plan or plans from April 20, 2006, to December 31, 2006, and granted us the exclusive right until March 31, 2007, to solicit acceptances of such plan or plans. We intend to seek to extend these deadlines as needed and permitted under the Bankruptcy Code. There can be no assurance, however, that the U.S. Bankruptcy Court will agree to further extend the period during which we have the exclusive right to file a reorganization plan or plans, nor can there be any assurance that the U.S. Bankruptcy Court will agree to further extend the period during which we have the exclusive right to solicit acceptances of such plan or plans.

Significant Pending Matters and Recent Developments

The U.S. Debtors have assumed certain contracts and unexpired leases related to non-residential real property and have identified certain significant contracts and leases to be rejected or repudiated. The following list describes the most significant of these matters that were pending or occurred during or after the nine months ended September 30, 2006.

• On December 21, 2005, we filed a motion with the U.S. Bankruptcy Court to reject eight PPAs and to enjoin FERC from asserting jurisdiction over the rejections. The U.S. Bankruptcy Court issued a temporary restraining order against FERC and set the matter for a hearing on January 5, 2006. Under most of the PPAs sought to be rejected, we are obligated to sell power at prices that are significantly lower than currently prevailing market prices. On December 29, 2005, certain counterparties to the various PPAs filed an action in the SDNY Court arguing that the U.S. Bankruptcy Court did not have jurisdiction over the dispute. On January 5, 2006, the SDNY Court entered an order that had the effect of transferring our motion seeking to reject the eight PPAs and our related request for an injunction against FERC to the SDNY Court from the U.S. Bankruptcy Court. Earlier, however, on December 19, 2005, CDWR, a counterparty to one of the eight PPAs, had filed a complaint with FERC seeking to obtain injunctive relief to prevent us from rejecting our PPA with CDWR and contending that FERC had exclusive jurisdiction over the matter. On January 3, 2006, FERC determined that it did not have exclusive jurisdiction, and that the matter could be heard by the U.S. Bankruptcy Court. However, despite the FERC ruling, on January 27, 2006, the SDNY Court determined that FERC had jurisdiction over whether the contracts could be rejected. We appealed the SDNY Court’s decision to the United States Court of Appeals for the Second Circuit. The appeal was heard on April 10, 2006, and we have not yet received a decision. We cannot determine at this time whether the SDNY Court, the U.S. Bankruptcy Court or FERC will ultimately determine whether we may reject any or all of the eight PPAs, or when such determination will be made. In the meantime, three of the PPAs have been terminated by the applicable counterparties, and three of the PPAs are the subject of negotiated settlements. We continue to perform under the PPAs that remain in effect, subject to any modifications agreed to by the parties. We cannot presently determine the ultimate outcome of the pending court cases nor the market factors that will need to be considered in valuing the rejected contracts and therefore are unable to estimate the expected allowed claims related to these PPAs.

• On January 16, 2006, CES-Canada, a Canadian debtor, repudiated its tolling agreement with Calgary Energy Centre. Calpine Corporation had guaranteed CES-Canada’s performance under the tolling agreement. We recorded a non-cash charge of $232.5 million, which was reported as a reorganization item in our Consolidated Condensed Statements of Operations in the first quarter of 2006. This charge represented the estimated out-of-the-money value of the contract to CES-Canada and the expected allowable claim from Calgary Energy Centre to Calpine Corporation under the guarantee.

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• On May 24, 2006, the U.S. Bankruptcy Court authorized the amendment and assumption of a steam agreement and related ground lease between Texas City Cogeneration, L.P. and Union Carbide Corporation and the amendment and assumption of a gas refinery agreement between Texas City Cogeneration, L.P. and BP Products North America Inc.

• On June 5, 2006, the U.S. Bankruptcy Court approved our motion to assume geothermal leases related to the Geysers Assets steam field operations and the Glass Mountain area, and the associated executory contracts, surface use agreements and site leases that allow the geothermal leases to be utilized to harness geothermal energy and operate these facilities. The geothermal leases combined with the operations at these facilities make up the core collateral for the DIP Facility.

• On June 8, 2006, the U.S. Bankruptcy Court approved the transition agreement and the effective date of the rejection of certain of our leases related to our Rumford and Tiverton power plants. On June 23, 2006, we closed the transaction contemplated in the transition agreement and the receiver now has possession and control of the Rumford and Tiverton power plants, as well as the ancillary assets related to the power plants transferred under the transition agreement. In connection with the lease rejections, we recorded a non-cash charge of $234.6 million in the second quarter of 2006, which includes our current estimate of the expected allowed claim related to the lease rejections, the write-off of prepaid lease expense and certain fees and expenses related to the transaction. The amount is reported as a reorganization item in our Consolidated Condensed Statements of Operations and the portion representing the expected allowed claim is included in liabilities subject to compromise in our Consolidated Condensed Balance Sheet.

• On June 21 and July 12, 2006, the U.S. Bankruptcy Court approved our motions to assume more than 60 natural gas pipeline leases and related real property licenses that support our pipelines across the country, covering more than 350 miles of both gathering and transmission pipelines. Assumption of these leases and licenses is necessary to allow for gas transportation to our customers, including Calpine affiliates.

• On June 21 and July 12, 2006, the U.S. Bankruptcy Court approved our motion to assume more than 20 leases related to the operation of our power plants (including ground leases, facility leases, operating leases, warehouse leases, etc). Assumption of these leases is necessary to allow for continued operation of the affected power plants.

• On July 12, 2006, the U.S. Bankruptcy Court approved our motions to assume (or assume and assign) office leases in Folsom, Houston, Pasadena, San Jose, Boca Raton, Jupiter, and Washington.

• On July 12, 2006, the U.S. Bankruptcy Court approved our motion to assume approximately 130 oil and gas leases to the extent that such leases are, in fact, leases of real property. Many of these oil and gas leases are the subject of an ongoing dispute with Rosetta stemming from our sale of domestic oil and gas assets to Rosetta in July 2005. By assuming these leases, we preserved our rights in the leases by avoiding the rejection of such leases on July 18, 2006.

• On October 25, 2006, the U.S. Bankruptcy Court authorized CES to assume a PPA with CCFC and enter into a settlement agreement with CCFC. The settlement agreement, which provided for CES to assume the PPA (allowing CES to reduce potential cure and administrative expense claims against its estate in the amount of approximately $250 million), also allows CCFC and CCFCP to secure a substantial majority of the cash flow from CCFC necessary to service their debt and redeemable preferred shares, respectively, and allows Calpine Corporation to maintain control of and preserve its equity value in CCFC and its subsidiaries.

• During the course of the Chapter 11 cases, the U.S. Debtors have determined that certain gas transportation and power transmission contracts no longer provide any benefit to the U.S. Debtors or their estates. In certain instances, the U.S. Debtors have given notice to counterparties to these contracts that the U.S. Debtors will no longer accept or pay for service under such contracts. We believe that any claims resulting from the repudiation,

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rejection, or termination of these contracts will be treated as pre-petition general unsecured claims. Accordingly, we recorded non-cash charges of $96.6 million and $405.4 million for the three and nine months ended September 30, 2006, respectively, as our current estimate of the expected allowed claims related primarily to these contracts. These charges are reported as reorganization items in our Consolidated Condensed Statements of Operations and are included in liabilities subject to compromise in the Consolidated Condensed Balance Sheet at September 30, 2006.

In addition, we are required to obtain U.S. Bankruptcy Court approval of sales of assets, subject to certain exceptions including with respect to de minimus assets. Such sales are subject in certain cases to U.S. Bankruptcy Court approved auction procedures. The most significant of these matters that were pending or occurred during or after the nine months ended September 30, 2006, are listed below.

• On July 26, 2006, the U.S. Bankruptcy Court approved our motion to sell our leasehold interest in the Fox Energy Center, a 560-MW natural gas-fired facility located in Kaukauna, Wisconsin, for $16.3 million and the extinguishment of financing obligations of $352.3 million, plus accrued interest. Closing of the transaction occurred on October 11, 2006. See Note 4 for further discussion.

• On September 13, 2006, the U.S. Bankruptcy Court approved our motion to sell the Dighton Power Plant, a 170-MW natural gas-fired facility located in Dighton, Massachusetts to BG North America, LLC, for approximately $90 million after completing an auction process in the U.S. Bankruptcy Court. Closing of the transaction occurred on October 1, 2006.

• On September 21, 2006, the U.S. Bankruptcy Court approved our motion to sell a partial ownership interest in Russell City Energy Company, LLC, a proposed 600-MW natural gas-fired facility to be built in Hayward, California, to ASC after completing an auction process in the U.S. Bankruptcy Court. As part of the transaction, we received approval from the U.S. Bankruptcy Court to transfer the Russell City project assets, which the parties have agreed are valued at approximately $81 million, to a newly formed entity in which we have a 65% ownership interest and ASC has a 35% ownership interest. In exchange for its 35% ownership interest, ASC has agreed to provide approximately $44 million of capital funding and to post an approximately $37 million letter of credit as required under a PPA with PG&E related to the Russell City project. We have the right to reacquire ASC’s 35% interest during the period beginning on the second anniversary and ending on the fifth anniversary of commercial operations of the facility. Exercise of the buyout right requires 180 days prior written notice to ASC and payment of an amount necessary to yield a stipulated pre-tax internal rate of return to ASC, calculated using assumptions specified in the transaction agreements. Closing of the transaction occurred on October 2, 2006.

• On September 22, 2006, our wholly owned subsidiary, MEP Pleasant Hill, LLC, entered into an asset purchase agreement with Aquila, Inc. to sell substantially all of the assets related to the Aries Project, a 590-MW natural gas-fired facility in Pleasant Hill, Missouri, for approximately $159 million. On October 12, 2006, the U.S. Bankruptcy Court approved an auction process in which qualifying bidders can make competing offers on the transaction. The sale hearing is currently scheduled for December 6, 2006, before the U.S. Bankruptcy Court. Closing of the transaction is subject to certain additional conditions including receipt of any required regulatory approvals.

• We have identified for potential sale 15 turbines, comprising 14 combustion turbines and one steam turbine. The generating capacities of the turbines range from approximately 45 MW to approximately 180 MW. The U.S. Bankruptcy Court approved our sale of one of the combustion turbines for $16.0 million on October 12, 2006, and on October 25, 2006, approved bidding procedures for the sale of four additional combustion turbines for which the outstanding bid is $48.0 million. The sale hearing for the four turbines is currently scheduled for November 15, 2006.

• On November 3, 2006, we entered into an asset purchase agreement with Puget Sound Energy to sell substantially all of the assets of the Goldendale Energy Center, a 271-MW natural gas-fired combined-cycle power plant

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located in Goldendale, Washington, for approximately $100 million, plus the assumption by Puget Sound Energy of certain liabilities. The sale is subject to U.S. Bankruptcy Court approval of an auction process in which qualified bidders can make competing offers for the project. Closing of the transaction is subject to certain additional conditions including receipt of any required regulatory approvals.

Other significant matters in the Chapter 11 cases that were pending or occurred during or after the nine months ended September 30, 2006, include the following:

• By order dated May 10, 2006 (as well as successive orders implementing the May 10 order), the U.S. Bankruptcy Court approved our motion to repay the outstanding principal amount of First Priority Notes at par ($646.1 million) plus accrued and unpaid interest. The repayment orders provided that such repayment was without prejudice to the rights of the holders of the First Priority Notes to pursue their demand for payment of a “make whole” premium they alleged to be due as a result of our repayment of First Priority Notes prior to their stated maturity. Pursuant to the U.S. Bankruptcy Court’s repayment orders, we completed the repayment of the First Priority Notes in June 2006. The First Priority Trustee appealed each of the repayment orders to the SDNY Court. In addition, on May 5, 2006, the First Priority Trustee filed an adversary proceeding in the U.S. Bankruptcy Court on behalf of the holders of the First Priority Notes seeking a declaratory judgment on the merits of their demand for a “make whole” premium. On June 21, 2006, the U.S. Bankruptcy Court entered an order approving our request to extend the date by which we must answer or otherwise move with respect to the First Priority Trustee’s adversary proceeding until ten days after the conclusion of the First Priority Trustee’s appeal to the SDNY Court of the U.S. Bankruptcy Court’s repayment orders. The First Priority Trustee then appealed the U.S. Bankruptcy Court’s June 21, 2006 order to the SDNY Court as well, and on July 24, 2006, the SDNY Court entered an order consolidating both appeals. The consolidated appeal is pending.

• On September 13, 2006, the U.S. Bankruptcy Court approved our motion seeking authority to make capital contributions for the continued development of Greenfield Energy Centre, a 1,005-MW natural gas-fired facility being developed in Ontario, Canada. We expect to make approximately $45 million in capital contributions to the project between such date and December 2006.

• On October 23, 2006, we filed a motion in the U.S. Bankruptcy Court for approval of certain transfers and other agreements relating to the Otay Mesa Energy Center, LLC, a 593-MW natural gas-fired facility currently under development in San Diego County, California. The agreements include a revised 10-year PPA with SDG&E, a sublease agreement which includes options in favor of Calpine and SDG&E, under certain circumstances, to purchase the Otay Mesa Energy Center from the other after 10 years of operations. The motion also seeks, among other things, approval of the transfer of certain facility assets to Otay Mesa Energy Center free and clear of any existing liens and authorization for Calpine to make cash contributions to Otay Mesa Energy Center, a Non-Debtor, not to exceed $35 million. A hearing on this motion is currently scheduled for November 15, 2006.

• RockGen Energy LLC leases a 460-MW natural gas-fired facility located in Christiana, Wisconsin. On November 2, 2006, we entered into a Forbearance Agreement with the RockGen owner lessors and owner participants, as well as the trustees and other parties to the RockGen sale/leaseback financing and, due to the highly confidential and proprietary information set forth in the Forbearance Agreement, sought and obtained the approval of the U.S. Bankruptcy Court to file the motion to approve the Forbearance Agreement under seal. Following entry of the order approving the request to file under seal, on November 2, 2006, we filed under seal the motion to approve the Forbearance Agreement with the U.S. Bankruptcy Court, which motion will be heard by the U.S. Bankruptcy Court on November 15, 2006. We believe that the Forbearance Agreement will provide a consensual mechanism to maximize the value of the RockGen facility and to minimize claims in the Chapter 11 cases.

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CCAA Proceedings

The following describes certain significant recent events, pending matters, and recent developments in the CCAA proceedings:

• Unlike the automatic stay provided under the Bankruptcy Code, there is no provision for an automatic stay under the CCAA. Accordingly, the Canadian Debtors sought and obtained a stay of proceedings from the Canadian Court in connection with the CCAA filings. Pursuant to various orders, the most recent dated September 18, 2006, the Canadian Court extended its stay of proceedings through November 13, 2006.

• By order entered April 11, 2006, the Canadian Court established June 30, 2006 as the date by which claims must be filed against the Canadian Debtors. This bar date was later extended through August 1, 2006 by order entered June 23, 2006.

• By order entered August 17, 2006, the Canadian Court authorized the Canadian Debtors to proceed to market and sell (i) approximately US$360 million face amount of senior notes issued by ULC I, (ii) approximately Euro 57.6 million face amount of senior notes issued by ULC II, and (iii) approximately Pound Sterling 78.6 million face amount of senior notes issued by ULC II, all of which senior notes purport to be held by the Canadian Debtors and are the subject of Calpine Corporation guarantees. The Canadian Court further ordered that all claims properly filed in advance of the bar date, or not subject to the bar date, that in any way purport to differentiate the rights, privileges and entitlements associated with such senior notes held by the Canadian Debtors from any other senior notes are reserved pending further order of the Canadian Court.

• On August 4, 2006, our indirect wholly owned subsidiary, Calpine European Finance LLC, executed definitive documentation in which it agreed to sell its entire equity interest in its wholly owned subsidiary TTS to Ansaldo Energia S.p.A for a contract price (subject to certain adjustments) of Euro 18.5 million or US$23.5 million (at then-current exchange rates). Both Calpine European Finance LLC and TTS were deconsolidated for accounting purposes as a result of the CCAA filings. On August 17, 2006, the Canadian Court entered an order authorizing the sale. On September 13, 2006, the U.S. Bankruptcy Court entered an order authorizing Power Systems MFG. LLC, a U.S. Debtor, to reject certain contracts with TTS and enter into new contracts with TTS as part of the TTS sale transaction. Closing of the transaction occurred on September 28, 2006. The proceeds of the sale have been deposited in an escrow account to be ultimately divided among Calpine, Power Systems MFG. LLC, and Calpine Canada Resources Company (a Canadian Debtor), based primarily on accounts receivable from TTS and certain other intercompany obligations.

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3.U.S. Debtors Condensed Combined Financial Statements

Condensed combined financial statements of the U.S. Debtors are set forth below.

Condensed Combined Balance Sheet

September30,2006 and December31,2005

	U.S. Debtors
	September30, 2006			December31, 2005
	(in millions)
Assets:
Current assets	$	4,343		$	5,448
Restricted cash, net of current portion		48			458
Investments		2,261			2,113
Property, plant and equipment, net		7,942			7,730
Other assets		1,340			1,647
Total assets	$	15,934		$	17,396
Liabilities not subject to compromise:
Current liabilities	$	3,861		$	4,866
Long-term debt		1,416			175
Long-term derivative liabilities		420			744
Other liabilities		328			235
Liabilities subject to compromise		16,736			16,714
Minority interest		—			275
Stockholders’ deficit		(6,827	)		(5,613	)
Total liabilities and stockholders’ deficit	$	15,934		$	17,396

See Note 8 for detail of liabilities subject to compromise.

Condensed Combined Statements of Operations

For the Three and Nine Months Ended September30,2006

	U.S. Debtors
	Three Months Ended September 30, 2006			Nine Months Ended September 30, 2006
	(in millions)
Total revenue	$	2,110		$	4,744
Total cost of revenue		1,929			4,501
Operating expenses		(46	)		134
Income from operations		227			109
Interest expense		113			503
Other (income) expense, net		(32	)		(38	)
Reorganization items, net		145			1,099
Provision for income taxes		30			7
Loss before cumulative effect of a change in accounting principle		(29	)		(1,462	)
Cumulative effect of a change in accounting principle		—			1
Net loss	$	(29	)	$	(1,461	)

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Condensed Combined Statements of Cash Flows

For the Nine Months Ended September30,2006

	U.S.Debtors
	(in millions)
Net cash provided by (used in):
Operating activities	$	(113	)
Investing activities		90
Financing activities		272
Net increase in cash and cash equivalents		249
Cash and cash equivalents, beginning of period		444
Effect on cash of new debtor filings		66
Cash and cash equivalents, end of period	$	759
Cash paid for reorganization items included in operating activities	$	78
Cash paid for reorganization items included in financing activities	$	34

Basis of Presentation

The U.S. Debtors’ Condensed Combined Financial Statements exclude the financial statements of the Non-U.S. Debtor parties. Transactions and balances of receivables and payables between U.S. Debtors are eliminated in consolidation. However, the U.S. Debtors’ Condensed Combined Balance Sheet includes receivables from and payables to related Non-U.S. Debtor parties. Actual settlement of these related party receivables and payables is, by historical practice, made on a net basis.

Interest Expense

Interest expense related to pre-petition LSTC has been reported only to the extent that it will be paid during the pendency of the Chapter 11 cases or is permitted by the Cash Collateral Order or is expected to be an allowed claim. Contractual interest (at non-default rates) to unrelated parties on LSTC not reflected in the financial statements for the three and nine months ended September 30, 2006, was approximately $157.8 million and $318.0 million, respectively. Pursuant to an order of the U.S. Bankruptcy Court, we made periodic cash interest payments to the holders of the Second Priority Debt through June 30, 2006. The Cash Collateral Order provides that the holders of the Second Priority Debt must seek further orders from the U.S. Bankruptcy Court for any additional interest to be paid.

Reorganization Items

Reorganization items represent the direct and incremental costs of being in Chapter 11, such as professional fees, pre-petition liability claim adjustments related to terminated contracts that are probable and can be estimated and charges related to expected allowed claims. The table below lists the significant items recognized within this category for the three and nine months ended September 30, 2006 (in millions).

	Three Months Ended September30, 2006		Nine Months Ended September30, 2006
Provision for expected allowed claims(1)	$	93.8	$	882.7
Professional fees		38.9		106.9
DIP financing costs		3.1		34.8
Other(2)		9.5		74.2
Total reorganization items	$	145.3	$	1,098.6

__________

(1) This charge primarily includes repudiation, rejection or termination of contracts or guarantee of obligations.

(2) This charge primarily includes foreign exchange on LSTC items denominated in a foreign currency and governed by foreign law, employee severance costs and net of interest income earned on cash accumulated as a result of our Chapter 11 cases.

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

As of September 30, 2006, and December 31, 2005, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in thousands):

	September30, 2006			December31, 2005
Buildings, machinery and equipment	$	14,210,645		$	14,023,358
Oil and gas pipelines		90,673			106,752
Geothermal properties		933,684			480,149
Other		178,331			178,145
		15,413,333			14,788,404
Less: Accumulated depreciation		(2,200,233	)		(1,872,989	)
		13,213,100			12,915,415
Land		86,095			92,595
Construction in progress		589,840			1,111,205
Property, plant and equipment, net	$	13,889,035		$	14,119,215

Geothermal Properties — Our subsidiary GPC acquired the Geysers Assets on February 3, 2006. Previously, GPC leased the plants from Geysers Statutory Trust (which is not an affiliate of ours) pursuant to a leveraged operating lease. The purchase price was approximately $157.6 million, plus certain costs and expenses (including an $8.0 million option payment). Immediately following the acquisition, we redeemed certain notes issued by Geysers Statutory Trust in connection with the leveraged lease structure at a cost of approximately $109.3 million. As a result of the acquisition, prepaid lease expense, net of deferred items, of $172.6 million was reclassified to property, plant and equipment, net in the Consolidated Condensed Balance Sheet.

Construction in Progress — In January 2006, the Freeport Energy Center in Freeport, Texas began producing steam through the use of auxiliary boilers. In March 2006, Phase II of the Fox Energy Center in Kaukauna, Wisconsin began commercial operation. In July 2006, Mankato Power Plant in Mankato, Minnesota began commercial operations. Accordingly, the construction in progress costs were transferred to the applicable property category, primarily buildings, machinery and equipment.

Capitalized Interest — For the three months ended September 30, 2006 and 2005, the total amount of interest capitalized was $3.9 million and $36.6 million, respectively. For the nine months ended September 30, 2006 and 2005, the total amount of interest capitalized was $20.9 million and $170.9 million, respectively. The decrease in the amount of interest capitalized year over year reflects the completion of construction for several power plants, the suspension of certain of our development and construction projects, and a reduction in our development and construction program in general.

Impairment Evaluation — For the three and nine months ended September 30, 2006, we recorded to operating plant impairments in the Consolidated Condensed Statement of Operations net impairment charges of $0 million and $52.5 million, respectively, primarily related to the Fox Energy Center for which a near-term sale was deemed likely in the first quarter of 2006. Additionally, for the nine months ended September 30, 2006, we recorded $64.2 million of non-cash impairment charges to equipment, development project and other impairments, primarily related to certain turbine-generator equipment not assigned to projects which are included in other assets in our Consolidated Condensed Balance Sheets. During the second quarter of 2006, we determined that a near-term sale of this equipment was likely and recorded an impairment charge to write down the net book value to estimated market prices.

Asset Sales — In connection with the closing of the sale of our leasehold interest in the Fox Energy Center on October 11, 2006, we received a cash payment of $16.3 million and the extinguishment of financing obligations of $352.3 million, plus accrued interest. As of September 30, 2006, long-lived assets related to the Fox Energy Center have been reclassified to current assets held for sale in our Consolidated Condensed Balance Sheets. See Note 13 for further discussion.

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5.Investments

At September 30, 2006, and December 31, 2005, our joint venture investments included the following (in thousands):

	Ownership Interestasof		Investment Balance at
	September30, 2006		September30, 2006		December31, 2005
Greenfield Energy Centre(1)		50%	$	101,289	$	40,698
Valladolid		—		—		42,900
Other(2)		—		22		22
Total investments in power projects			$	101,311	$	83,620

__________

(1) Greenfield LP is a limited partnership formed for the purpose of constructing and operating the Greenfield Energy Centre, a 1,005-MW combined-cycle plant in Ontario, Canada. Our investment is accounted for under the equity method.

(2) We hold a 100% interest in Canadian and other foreign subsidiaries most of which were deconsolidated at December 31, 2005, due to the Canadian subsidiaries’ filing for creditor protection under the CCAA in Canada. All of these investments were fully impaired at December 31, 2005, and are accounted for under the cost method.

Contribution — During the three and nine months ended September 30, 2006, we contributed $10.0 million and $31.0 million in cash to our investment in the Greenfield Energy Centre. We also contributed $27.9 million of steam turbine equipment during the three months ended September 30, 2006.

Asset Sales — On April 18, 2006, we completed the sale of our 45% indirect equity interest in the 525-MW Valladolid project to the two remaining partners, Mitsui and Chubu, for $42.9 million, less a 10% holdback and transaction fees. Under the terms of the purchase and sale agreement, we received cash proceeds of $38.6 million at closing. The 10% holdback, plus interest, will be returned to us in one year’s time. We eliminated $87.8 million of non-recourse unconsolidated project debt, representing our 45% share of the total project debt of approximately $195.0 million. In addition, funds held in escrow for credit support of $9.4 million were released to us. We recorded an impairment charge of $41.3 million for our investment in the project during the year ended December 31, 2005; accordingly, no material gain or loss was recognized on this sale.

6.Comprehensive Income (Loss)

Comprehensive loss is the total of net loss and all other non-owner changes in equity. Comprehensive loss includes our net loss, unrealized gains and losses from derivative instruments that qualify as cash flow hedges, unrealized gains and losses from available-for-sale securities which are marked-to-market, our share of equity method investee’s OCI, and the effects of foreign currency translation adjustments. We report AOCI in our Consolidated Condensed Balance Sheet. The table below details the changes during the three and nine months ended September 30, 2006 and 2005, in the Company’s AOCI balance and the components of our comprehensive loss (in thousands):

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Statement of Comprehensive Income (Loss):

	ThreeMonthsEndedSeptember30,						NineMonthsEndedSeptember30,
	2006			2005			2006			2005
Net income (loss)	$	1,662		$	(216,689	)	$	(1,405,540	)	$	(683,879	)
Other comprehensive income (loss), net of tax:
Comprehensive pre-tax gain (loss) on cash flow hedges before reclassification adjustment		(29,024	)		(209,814	)		43,335			(434,822	)
Reclassification adjustment for losses included in net income (loss)		92,636			277,055			103,721			314,085
Pre-tax gain on available-for-sale investments		—			(4,523	)		—			(958	)
Foreign currency translation (loss)		(81	)		(171,686	)		(1,752	)		(205,376	)
Income tax benefit (provision)		(20,084	)		(14,285	)		(53,037	)		42,187
Total comprehensive income (loss)	$	45,109		$	(339,942	)	$	(1,313,273	)	$	(968,763	)

7.Debt

DIP Facility — On January 26, 2006, the U.S. Bankruptcy Court entered a final order approving the $2.0 billion DIP Facility and removing its previously imposed limitation on our ability to borrow thereunder. The DIP Facility, which will remain in place until the earlier of an effective plan of reorganization or December 20, 2007, is comprised of a $1.0 billion revolving credit facility priced at LIBOR plus 225 basis points or base rate plus 125 basis points, a $400 million first-priority term loan priced at LIBOR plus 225 basis points or base rate plus 125 basis points and a $600 million second-priority term loan priced at LIBOR plus 400 basis points or base rate plus 300 basis points. The DIP Facility is secured by first priority liens on all of the unencumbered assets of the U.S. Debtors, including the Geysers Assets, and junior liens on all of their encumbered assets. The proceeds of borrowings and letters of credit issued under the DIP Facility’s revolving credit facility will be used, among other things, for working capital and other general corporate purposes.

The DIP Facility was amended on May 3, 2006, to, among other things, provide us with extensions of time to provide certain financial information to the DIP Facility lenders, including financial statements for the year ended December 31, 2005, and for the quarter ended March 31, 2006. Also in May 2006, the DIP Facility lenders consented to the use of borrowings under the DIP Facility to repay a portion of the First Priority Notes in accordance with the orders of the U.S. Bankruptcy Court. The DIP Facility was further amended on September 25, 2006, to increase the portion of the revolving credit facility that may be used for letters of credit to $375 million from $300 million (to allow for $75 million to be issued on behalf of Non-Debtors), grant the administrative agents the authority to extend the time to deliver financial statements, permit guarantees in connection with certain letters of credit, permit investments in Calpine Greenfield Commercial Trust solely to finance Greenfield LP in an amount not to exceed $45 million, and permit the establishment of a separate account to hold funds constituting “restricted cash” for the benefit of certain project lessors.

In July 2006, the DIP Facility lenders consented to the assignment of certain PPAs by Broad River Energy, LLC, our subsidiary that leases the Broad River facility pursuant to a leveraged lease, to the owner-lessors of such facility in connection with a settlement agreement with the owner-lessors. The DIP Facility lenders also consented to Broad River’s granting to the owner-lessors a temporary security interest in the same PPAs until FERC approves the assignment. The July 2006 consent was conditioned upon the U.S. Bankruptcy Court’s approval of the settlement agreement with the owner-lessors. The U.S. Bankruptcy Court approved the settlement agreement on June 27, 2006, and FERC approved the assignment of the PPAs on August 11, 2006.

As of September 30, 2006, there was $997.4 million outstanding under the term loan facilities, nothing outstanding under the revolving credit facility, and $11.7 million of letters of credit were issued against the revolving credit facility. In

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May 2006 and June 2006, a portion of the funds drawn under the term loan facilities, together with approximately $409 million of restricted cash, plus accrued interest, were used to repay the remaining outstanding $646.1 million of our First Priority Notes.

Debt, Lease and Indenture Covenant Compliance — Pursuant to the DIP Facility, we are subject to a number of affirmative and restrictive covenants, reporting requirements and financial covenants. As of September 30, 2006, we were in compliance with the DIP Facility covenants.

Our filings under Chapter 11 and the CCAA constituted events of default or otherwise triggered repayment obligations under the instruments governing substantially all of the indebtedness of the Calpine Debtors outstanding at the Petition Date. As a result of the events of default, the debt outstanding under the affected debt instruments generally became automatically and immediately due and payable. We believe that any efforts to enforce such payment obligations against U.S. Debtors are stayed as a result of the Chapter 11 filings and subject to our Chapter 11 cases. Although the CCAA does not provide an automatic stay, the Canadian Court has granted a stay to the Canadian Debtors which currently extends through November 13, 2006. Such events of default generally also constituted breaches of executory contracts and unexpired leases of U.S. Debtors. Actions taken by counterparties or lessors based on such breaches, we believe, are also stayed as a result of the Chapter 11 filings. However, under the Bankruptcy Code, we must cure all pre-petition defaults of executory contracts and unexpired leases that we seek to assume. Once we assume an executory contract or unexpired lease pursuant to an order of the U.S. Bankruptcy Court, such executory contract or unexpired lease becomes a post-petition obligation of the applicable U.S. Debtor, and efforts on the part of counterparties or lessors to enforce the U.S. Debtor’s obligations under such contracts or leases may or may not be stayed as a result of the Chapter 11 filings. See Note 2 for information regarding the assumption of executory contracts and unexpired leases.

In addition, as described further below, the Chapter 11 filings by certain of the U.S. Debtors caused, directly or indirectly, defaults or events of default under the debt of certain Non-Debtor entities. Such events of default (or defaults that become events of default) could give holders of debt under the relevant instruments the right to accelerate the maturity of all debt outstanding thereunder if the defaults or events of default were not cured or waived. There can be no assurance that such remedies can be obtained.

Calpine Debtor Entities

In addition to the events of default caused as a result of our Chapter 11 or CCAA filings, we may not be in compliance with certain other covenants under the indentures or other debt or lease instruments of certain Calpine Debtor entities, the obligations under all of which have been accelerated. In particular:

• We were required to use the proceeds of certain asset sales and issuances of preferred stock completed in 2005 to make capital expenditures, to acquire permitted assets or capital stock, or to repurchase or repay indebtedness in the first three quarters of 2006. However, as a result of the Chapter 11 filings, we have not been, and do not expect to be, able to do so.

• We sold substantially all of our remaining oil and gas assets on July 7, 2005. The gas component of such sale constituted a sale of “designated assets” under certain of our indentures, which restrict the use of the proceeds of sales of designated assets. In accordance with the indentures, we used $138.9 million of the net proceeds of $902.8 million from the sale to repurchase First Priority Notes from holders pursuant to an offer to purchase. We used approximately $308.2 million, plus accrued interest, of the net proceeds to purchase natural gas assets in storage. The remaining $406.9 million and interest income subsequently earned thereon, remained in a restricted designated asset sale proceeds account pursuant to the indentures governing the First Priority Notes and the Second Priority Notes until it was used to purchase First Priority Notes in May 2006. As described in Note 12, in a lawsuit captioned Calpine Corporation v. The Bank of New York, Collateral Trustee for Senior Secured Note Holders, et al., the Delaware Court of Chancery found in November 2005 that our use of the approximately $308.2 million of proceeds to make purchases of gas assets in storage was in violation of such indentures and ordered that amount plus accrued interest (for a total of approximately $313 million) be returned to a designated

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asset sale proceeds account. The Delaware Supreme Court affirmed the Delaware Court of Chancery’s decision on December 20, 2005. Later that same day, the case was stayed upon our Chapter 11 filing. As a result, we have not refunded the amount to date.

Further, as part of our “first day” filings in the Chapter 11 cases, we assumed certain unexpired leases and executory contracts related to the sale/leaseback transaction at the Agnews power plant. We have failed to deliver to the financing parties certain financial reports, operational reports and officers’ certificates for this project as required under the financing documents. Such delayed delivery may become an event of default if the information is not provided, entitling the financing parties to certain rights and remedies. As a result, our obligations under this financing have been classified as current.

While it does not affect a debt instrument, we own a 50% interest in Acadia PP through our wholly owned subsidiary, Calpine Acadia Holdings, LLC, which is a U.S. Debtor. The remaining 50% is owned by a subsidiary of Cleco, Acadia Power Holdings, LLC. Calpine Acadia Holdings, LLC and Acadia Power Holdings, LLC are subject to a limited liability company agreement which, among other things, governs their relationship with regard to ownership of Acadia PP. The limited liability company agreement provides that bankruptcy of Calpine Acadia Holdings, LLC is an event of default under such agreement and sets forth certain exclusive remedies in the event that default occurs, including winding up Acadia PP or permitting the non-defaulting party to buy out the defaulting party’s interest at market value less 20%. However, we believe that any efforts to enforce such remedies would be stayed as a result of the Chapter 11 filings and subject to our Chapter 11 cases. To date, no default of the limited liability company agreement has been declared. The parties are currently discussing a restructure of the ownership of Acadia PP.

Non-Debtor Entities

Blue Spruce Energy Center.  In connection with the project financing transaction by Blue Spruce, an event of default existed under the project credit agreement as of March 31, 2006, due to cross default provisions related to the Chapter 11 filing by CES. Subsequently, we have obtained an amendment and waiver under the project credit agreement from the lender, which waived the defaults unless and until the CES tolling agreement related to the Blue Spruce facility is rejected in the Chapter 11 cases. In addition, the waiver agreement and the terms of the project credit agreement provide us with additional time to deliver certain financial information required under the project financing documents so long as we are seeking to cure such failure and it does not have a material adverse effect. We are seeking to cure such failure and therefore, our obligations under this financing have been classified as non-current.

Calpine King City Cogen.  In connection with the sale/leaseback transaction at the King City power plant, the Chapter 11 filings by certain affiliates of King City Cogen constituted an event of default under the lease agreement. We have obtained a forbearance agreement that is in effect until January 1, 2007. Certain financial information and officers’ certificates for this project that we had failed to deliver within the times provided under the lease and participation agreement have now been delivered as required. As a result of the limited nature of the forbearance agreement, our obligations under this financing have been classified as current.

CCFC.  In connection with the note and term loan financing at CCFC, on June 9, 2006, CCFC entered into waiver agreements under the indenture governing its notes and the credit agreement governing its term loans upon the receipt by CCFC of the consent of the holders of a majority in outstanding principal amount of CCFC’s notes and the agreement of the lenders of a majority in outstanding principal amount of the CCFC term loans pursuant to a consent solicitation and request for amendment. The June 9 waiver agreements provide for the waiver of certain defaults and events of default that resulted from, among other things, the failure of CES, a U. S. Debtor, to make a portion of the payments due to CCFC in March 2006 under a PPA between CES and CCFC. The June 9 waiver agreements required CCFC to reach agreement with its noteholders and term loan lenders regarding the treatment of the CES PPA with CCFC in the Chapter 11 cases by August 4, 2006; if such agreement was not reached by that time, the June 9 waivers would have ceased to be effective. On each of August 4, 2006, and August 11, 2006, in each case upon the receipt by CCFC of the consent of holders of a majority of the outstanding principal amount of its notes and the agreement of the lenders of a majority in outstanding principal amount of its term loans pursuant to a consent solicitation and request for amendment, the June 9 waivers were amended to extend the August 4, 2006, deadline to August 11, 2006, and August 25, 2006, respectively. On August 25, 2006, upon receipt of the consent of the

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Index  Definitions

holders of a majority in outstanding principal amount of CCFC’s notes and the agreement of the lenders of a majority in outstanding principal amount of the term loans pursuant to a consent solicitation and request for amendment, CCFC entered into amendment agreements under the indenture and credit agreement regarding the treatment of the CES PPA in the Chapter 11 cases and certain other matters. In accordance with the amendment agreements, we filed a motion with the U.S. Bankruptcy Court requesting authority for (i) CES to assume the CES PPA with CCFC and (ii) CES and CCFC to enter into a related settlement agreement. On October 25, 2006, the U.S. Bankruptcy Court approved the motion and the settlement agreement, which allowed CES to assume the PPA and at the same time reduce potential cure and administrative expense claims. Accordingly, the June 9 waivers have become permanent, and all defaults under the CCFC notes indenture and term loan credit agreement have been cured. As a result, the CCFC notes and terms loans have been classified as non-current.

CCFCP.  The amendments to the CCFC indenture and credit agreement contained in the August 25 amendment agreements were subject to the condition that the holders of the CCFCP redeemable preferred shares agree to similar amendments to the corresponding provisions of the CCFCP operating agreement. On October 24, 2006, upon the agreement of the holders of all of the preferred shares, CCFCP entered into an amendment agreement to amend the operating agreement on terms which correspond to the amendments to the CCFC indenture and credit agreement, and to address the treatment of the CES PPA with CCFC in the Chapter 11 cases and certain other matters. Under the amendment, CCFCP is required to cause us to replace or reaffirm our guarantee of the obligations of CES and its affiliates under the CES PPA with CCFC and related agreements after our emergence from Chapter 11 and to use reasonable efforts to cause us to replace or reaffirm our guarantee during the pendency of the Chapter 11 cases. If the June 9 waiver agreements with respect to the CCFC notes and term loans had ceased to be effective and an event of default therefore had occurred under the CCFC notes indenture and term loan credit facility, the holders of the CCFCP redeemable preferred shares may have been entitled to declare a voting rights trigger event to have occurred, which would have entitled them to remove and replace the existing CCFCP directors unless and until the consequences of the CCFCP voting rights trigger event have been fully cured. Pursuant to the October 24 amendment agreement under the operating agreement, the holders of the CCFCP redeemable preferred shares permanently waived any such rights they may have had.

Fox Energy Center.  The Chapter 11 filings by certain affiliates of Calpine Fox LLC constituted an event of default under the lease and certain other agreements relating to the sale/leaseback transaction at the Fox Energy Center. In addition, Calpine Fox LLC failed to make scheduled lease payments on March 30, 2006, and September 30, 2006, and also failed to deliver certain financial information and officers’ certificates within prescribed deadlines. Calpine Fox LLC entered into a forbearance agreement and side letter with the Fox Energy Center owner lessor and owner participant, pursuant to which the owner lessor and owner participant have agreed not to exercise certain rights and remedies under the lease and other agreements relating to the events of default. The protections afforded by the forbearance agreement and side letter were extended to the earlier of December 31, 2006, and the occurrence of any other default under the lease and related agreements. On October 11, 2006, we completed the sale of our leasehold interest in the Fox Energy Center. The terms of the sale provide that the lease documents will terminate 91 days after the closing date, subject to compliance by Calpine Fox LLC with certain covenants and provided that it is not the subject of a voluntary or involuntary bankruptcy filing during that period. Upon the termination of the lease documents, any defaults under the sale/leaseback documents will be released and the approximately $352.3 million of obligations under the sale/leaseback transaction will be eliminated. As a result, our obligations under the credit agreement have been classified as current liabilities held for sale. See Notes 4 and 13 for further information regarding the sale of this facility.

Freeport Energy Center and Mankato Energy Center.  In connection with the project financing transaction by Freeport and Mankato, an event of default existed under the project credit agreement due to cross default provisions related to the Chapter 11 filings by certain Calpine affiliates. The lenders under the project credit agreement provided a waiver of the event of default in exchange for a fee of 6.25 basis points (0.06%) of the total outstanding amounts of the loans unless and until any of the major project documents related to the facilities, to which such Calpine affiliates are party is rejected in the Chapter 11 cases. Certain financial information and related officers’ certificates for these projects that we had failed to deliver within the times provided under the project credit agreement have now been delivered as required. As a result, our obligations under the project credit agreement have been classified as non-current.

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Metcalf Energy Center.  In connection with the financing transactions by Metcalf, certain events of default occurred under the project credit agreement as a result of our Chapter 11 filings and related failures to fulfill certain payment obligations under a PPA between CES and Metcalf. Such events of default also constituted a voting rights trigger event under Metcalf’s limited liability company agreement, which contains the terms of Metcalf’s redeemable preferred shares. Upon the occurrence of a voting rights trigger event, the holders of the Metcalf redeemable preferred shares may, at their option, remove and replace the existing Metcalf directors unless and until the voting rights trigger event has been waived by the holders of a majority of the Metcalf redeemable preferred shares or until the consequences of the voting rights trigger event have been fully cured. Metcalf entered into waiver agreements on April 18, 2006, and June 22, 2006, with the requisite lenders under the credit agreement waiving the foregoing events of default in exchange for a fee of 20 basis points (0.20%) of the total outstanding amounts of the loans and Metcalf’s commitment to assert claims in the Chapter 11 cases against Calpine, CES, and Calpine Construction Management Company, Inc., which claims were timely filed by Metcalf in accordance with the waiver. The waiver is effective unless and until any major project document, as defined under the credit agreement, is rejected in connection with the Chapter 11 cases. In addition, financial information that we had failed to deliver within the time provided under the project credit agreement has now been delivered as required. As a result of the contingent nature of the waiver, our obligations under the credit agreement have been classified as current.

Pasadena Power Plant.  In connection with our Pasadena lease financing transaction, our Chapter 11 filings constituted an event of default under Pasadena’s participation agreement and certain other agreements relating to the transaction, which resulted in events of default under the indenture governing certain notes issued by the Pasadena owner lessor. We entered into a forbearance agreement with the holders of a majority of the outstanding notes pursuant to which the noteholders have agreed to forebear from taking any action with respect to the events of default, which forbearance agreement was extended from month to month until May 1, 2006. Such forbearance agreement has lapsed and there is currently no forbearance agreement in place. In addition, we have failed to deliver certain financial information for this project within the times provided under the participation agreement and certain of the financial information previously delivered was not stated in accordance with GAAP as required under the participation agreement, each of which could result in events of default under the participation agreement and certain other agreements related to the transaction after receipt of notice and with the passage of time. As a result, our obligations with respect to this lease financing have been classified as current.

Riverside Energy Center and Rocky Mountain Energy Center.  In connection with the project financing transactions by Riverside and Rocky Mountain, an event of default occurred under the project credit agreements due to cross default provisions related to the Chapter 11 filings by certain Calpine affiliates. The lenders under the project credit agreements provided an omnibus amendment and waiver of such events of default unless and until any of the major project documents related to the facilities to which any U.S. Debtor is a party are rejected in the Chapter 11 cases. Certain financial information for these projects that we had failed to deliver within the times provided under the project credit agreements has now been delivered as required. As a result, our obligations under the project credit agreements have been classified as non-current.

8.Liabilities Subject to Compromise

The claims bar dates—the dates by which claims against the Calpine Debtors (other than Calpine Geysers Company, L.P.) were to be filed with the applicable Bankruptcy Court—were set for August 1, 2006, by each of the Bankruptcy Courts. On September 13, 2006, the U.S. Bankruptcy Court approved our motion to set the claims bar date for claims against Calpine Geysers Company, L.P., one of the Calpine Debtors, for October 31, 2006. Accordingly, not all potential claims would have been filed as of September 30, 2006. The amounts of LSTC at September 30, 2006, and December 31, 2005, consisted of the following (in millions):

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	September30, 2006		December31, 2005
Accounts payable and accrued liabilities(1)	$	374.8	$	724.2
Terminated commodity contracts and interest rate swaps		538.1		133.6
Project financing		159.1		166.5
Convertible notes		1,823.5		1,823.5
Second priority senior secured notes(2)		3,671.9		3,671.9
Unsecured senior notes		1,880.0		1,880.0
Notes payable and other liabilities – related party		1,118.1		1,078.0
Provision for expected allowed claims(3)		5,474.1		5,132.4
Total liabilities subject to compromise	$	15,039.6	$	14,610.1

____________

(1) Accounts payable and accrued liabilities within LSTC declined due primarily to settling by netting accounts receivables against pre-petition payables with certain CES counterparties, where netting agreements were in place.

(2) We have not made, and currently do not propose to make, an affirmative determination whether our Second Priority Debt is fully secured or under-secured. We do, however, believe that there is uncertainty about whether the market value of the assets securing the obligations owing in respect of the Second Priority Debt is less than, equals or exceeds the amount of these obligations. Accordingly, we have classified the Second Priority Debt as LSTC.

(3) Consists primarily of estimated allowed claims related to guarantees by Calpine Corporation of repayment of unsecured senior notes (original principal amount of $2,597.2 million) for two wholly owned finance subsidiaries of ours, ULC I and ULC II. The amounts outstanding to unrelated security holders had been reduced to $1,943.0 million at December 31, 2005, due to repurchases of such senior notes. However, some of the repurchased notes are held by certain of Calpine Corporation’s Canadian subsidiaries and are expected to give rise to allowed claims by these subsidiaries under the above guarantees. Additionally, there is a guarantee by Calpine Corporation of the obligations of its wholly owned subsidiary, Quintana Canada Holdings, LLC, under certain subscription agreements with ULC I, under which claims may be asserted for the same amounts sought under the Calpine Corporation guarantees of the ULC I notes. Although the expected claims are redundant relative to the underlying exposure to unrelated security holders, we determined that these duplicative claims were probable of being allowed into the claim pool by the U.S. Bankruptcy Court, although the U.S. Debtors fully reserve their rights in this regard.

9.Derivative Instruments

The table below reflects the amounts that are recorded as assets and liabilities at September 30, 2006, for our derivative instruments (in thousands):

	Interest Rate Derivative Instruments		Commodity Derivative Instruments Net			Total Derivative Instruments
Current derivative assets	$	5,772	$	179,106		$	184,878
Long-term derivative assets		4,175		390,217			394,392
Total assets	$	9,947	$	569,323		$	579,270
Current derivative liabilities	$	1,138	$	276,742		$	277,880
Long-term derivative liabilities		3,622		524,537			528,159
Total liabilities	$	4,760	$	801,279		$	806,039
Net derivative assets (liabilities)	$	5,187	$	(231,956	)	$	(226,769	)

Of our net derivative assets (liabilities), $98.2 million and $6.8 million are net derivative assets of PCF and CNEM, respectively, each of which is an entity with its existence separate from us and other subsidiaries of ours. We fully consolidate CNEM and we record the derivative assets of PCF in our balance sheet.

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Below is a reconciliation of our net derivative liabilities to our accumulated other comprehensive loss, net of tax from derivative instruments at September 30, 2006 (in thousands):

	September30, 2006
Net derivative liabilities	$	(226,769	)
Derivatives not designated as cash flow hedges and recognized hedge ineffectiveness		237,507
Cash flow hedges terminated prior to maturity		(111,534	)
Cumulative OCI tax benefit		36,086
Accumulated other comprehensive loss from derivative instruments, net of tax(1)	$	(64,710	)

____________

(1) Amount represents one portion of our total AOCI balance of $(68,685).

The tables below reflect the impact of mark-to-market gains (losses) on our pre-tax earnings for the three and nine months ended September 30, 2006 and 2005, respectively (in thousands):

	Three Months Ended September30,						Nine Months Ended September30,
	2006			2005			2006			2005
Natural gas derivatives(1)	$	(70,768	)	$	50,630		$	(194,385	)	$	(27,775	)
Power derivatives(1)		105,979			(9,776	)		273,702			67,972
Interest rate derivatives(1)(2)		(6,750	)		(1,123	)		8,834			(316	)
Total	$	28,461		$	39,731		$	88,151		$	39,881

____________

(1) Represents the realized and unrealized mark-to-market activity. The activity is presented in the Consolidated Condensed Statements of Operations as mark-to-market activities, net.

(2) Recorded within other income in the Consolidated Condensed Statements of Operations for periods prior to January 2006.

The table below reflects the contribution of our cash flow hedge activity to pre-tax earnings based on the reclassification adjustment from AOCI to earnings for the three and nine months ended September 30, 2006 and 2005, respectively (in thousands):

	Three Months Ended September30,						Nine Months Ended September30,
	2006			2005			2006			2005
Natural gas and crude oil derivatives	$	43,220		$	27,589		$	226,931		$	44,906
Power derivatives		(134,584	)		(297,481	)		(324,598	)		(336,922	)
Interest rate derivatives		(1,272	)		(6,665	)		(6,054	)		(20,570	)
Foreign currency derivatives		—			(498	)		—			(1,499	)
Total derivatives	$	(92,636	)	$	(277,055	)	$	(103,721	)	$	(314,085	)

As of September 30, 2006, the maximum length of time over which we were hedging our exposure to the variability in future cash flows for forecasted transactions was 2 and 7 years, for commodity and interest rate derivative instruments, respectively. We currently estimate that pre-tax losses of $69.4 million would be reclassified from AOCI into earnings during the twelve months ended September 30, 2007, 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 AOCI to earnings (positive or negative) will be for the next twelve months.

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

	2006			2007			2008			2009			2010			Thereafter			Total
Gas OCI	$	31,907		$	11,681		$	—		$	—		$	—		$	—		$	43,588
Power OCI		(75,804	)		(33,651	)		(5,960	)		(4,336	)		(3,037	)		—			(122,788	)
Interest Rate OCI		(907	)		70			(1,141	)		(1,196	)		(1,642	)		(16,780	)		(21,596	)
Total pre-tax OCI	$	(44,804	)	$	(21,900	)	$	(7,101	)	$	(5,532	)	$	(4,679	)	$	(16,780	)	$	(100,796	)

10.Earnings (Loss) per Share

Basic earnings (loss) per share is calculated using the average actual shares outstanding during the period. Diluted earnings (loss) per share is calculated by adjusting the average actual shares outstanding by the dilutive effect of unexercised in-the-money employee stock options, using the treasury stock method, and assumes that convertible securities were converted into common shares upon issuance, if dilutive. In periods of losses, diluted loss per share is computed on the same basis as basic loss per share as the inclusion of any other potential shares outstanding would be anti-dilutive.

Potentially convertible securities and unexercised in-the-money employee stock options to purchase a weighted average of 0.1 million and 1.9 million shares of our common stock for the three months ended September 30, 2006 and 2005, respectively, and 0.1 million and 7.7 million for the nine months ended September 30, 2006 and 2005, respectively, were not considered in the calculation as such inclusion would have been anti-dilutive. In addition, the computation of diluted earnings (loss) per share excluded the effects of unexercised out-of-the-money employee stock options of 24.9 million and 35.0 million for the three months ended September 30, 2006 and 2005, respectively, and 30.2 million and 33.8 million for the nine months ended September 30, 2006 and 2005, respectively, due to either the exercise prices being greater than the average fair market prices or due to our net losses before discontinued operations. We also excluded 64 million shares of common stock remaining outstanding, after the return in the third quarter of 2006 of 25 million of the original 89 million shares, that are subject to a share lending agreement with DB London. See our audited Consolidated Financial Statements for the year ended December 31, 2005, included in our 2005 Form 10-K, for a discussion of our contingent convertible senior notes, including the circumstances under which they would affect the computation of earnings (loss) per share and when they would be convertible into our common shares.

11.Stock-Based Compensation

1996 Stock Incentive Plan

Under the SIP, we granted stock options to directors, certain employees and consultants or other independent advisors at an exercise price that generally equals the stock’s fair market value on the date of grant. In accordance with the plan document, the SIP expired on July 16, 2006. All outstanding option grants and unvested stock issuances remain in effect in accordance with the provisions of the documents evidencing such grants or issuances. The SIP options generally vest ratably over four years with a maximum exercise period of 7 or 10 years after the grant date. Any stock exercised under the SIP would be satisfied by authorized but unissued or reacquired shares of our common stock. Over the life of the SIP, options exercised have equaled 5,353,308, leaving 23,659,196 granted and not yet exercised as of September 30, 2006.

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A summary of the SIP for the nine months ended September 30, 2006, is as follows:

	Numberof Options		Weighted Average ExercisePrice		Remaining Term (inyears)		Aggregate Intrinsic Value (inmillions)
Outstanding – December 31, 2005		37,090,268	$	7.62
Granted		—		—
Exercised		—		—
Forfeited		3,233,432		4.12
Expired		10,197,640		8.53
Outstanding – September 30, 2006		23,659,196	$	7.71
Exercisable – September 30, 2006		20,523,757	$	8.26		4.69	$	—
Vested and expected to vest – September 30, 2006		23,257,383	$	7.77		4.87	$	—

The fair value of options granted was determined on the grant date using the Black-Scholes pricing model. Certain assumptions were used in order to estimate fair value for options granted during the three and nine months ended September 30, 2005, as noted in the following table. No options were granted during the nine months ended September 30, 2006.

	Three Months Ended September30, 2005		Nine Months Ended September30, 2005
Expected term (in years)(1)		1.09 – 7.33		1.09 – 7.33
Risk-free interest rate(2)		4.05 – 4.08%		3.39 – 4.23%
Expected volatility(3)		79.72 – 86.25%		57.55 – 91.62%
Dividend yield		—		—
Weighted-average grant-date fair value (per option)	$	2.08 – 2.66	$	1.27 – 2.92

__________

(1) Expected term based on the remaining actual contractual term.

(2) U.S. Treasury rate based on expected term.

(3) Volatility based on expected term of the options over the period from September 1996 to May 2005.

For the three and nine months ended September 30, 2005, the intrinsic value of options exercised was $0. Cash received for options exercised during the three and nine months ended September 30, 2005, was $1.5 million and $2.1 million, respectively. No options were exercised during the nine months ended September 30, 2006.

Stock-based compensation expense recognized for stock options was $2.2 million and $3.8 million for the three months ended September 30, 2006 and 2005, respectively, and $5.9 million and $10.8 million for the nine months ended September 30, 2006 and 2005, respectively. At September 30, 2006, there was $3.6 million of unrecognized compensation cost related to stock options, which is expected to be recognized over a weighted-average period of 1.15 years.

Restricted Stock Awards

In general, we refer to an award of common stock that is subject to time-based vesting or achievement of performance measures as “restricted stock.” Restricted stock awards are generally subject to certain transfer restrictions and forfeiture upon termination of employment. There were no restricted stock awards in the nine months ended September 30, 2006.

The following table summarizes activity during the nine months ended September 30, 2006, related to restricted stock awards classified as equity awards.

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	Number of Restricted StockAwards		Weighted- Average Grant-Date Fair Value
Nonvested – December 31, 2005		946,222	$	3.32
Granted		—		—
Forfeited		237,199	$	3.32
Vested		—		—
Nonvested – September  30, 2006		709,023	$	3.32

At September 30, 2006, there was no unrecognized compensation cost related to restricted stock. Compensation cost associated with these restricted stock awards of $2.7 million was expensed during the nine months ended September 30, 2005.

2000 Employee Stock Purchase Plan

Prior to the suspension of the ESPP effective November 29, 2005, eligible employees could purchase, in the aggregate, up to 28,000,000 shares of our common stock through periodic payroll deductions. The purchase price for the shares under the ESPP was 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. Shares could be purchased on May 31 and November 30 of each year until termination of the ESPP. This plan is considered compensatory under SFAS No. 123-R.

Due to the suspension of the ESPP, no compensation cost was recognized and no shares were purchased during the three and nine months ended September 30, 2006. During the three and nine months ended September 30, 2005, we recognized $1.1 million and $3.1 million, respectively, of compensation expense. In May 2005, 2.4 million shares were purchased.

Pro Forma Impact of Stock-Based Compensation

The following table presents the effect on net loss and loss per share for the three and nine months ended September 30 2005, if we had used the fair value method of accounting for all periods prior to the prospective adoption of SFAS No. 123 as of January 1, 2003 (in thousands, except per share amounts):

	ThreeMonths Ended September30, 2005			NineMonths Ended September30, 2005
Net loss:
As reported	$	(216,689	)	$	(683,879	)
Pro Forma		(216,751	)		(684,678	)
Loss per share data:
Basic and diluted loss per share:
As reported		(0.45	)		(1.49	)
Pro Forma		(0.45	)		(1.49	)
Stock-based compensation cost included in net loss, as reported (net of tax)	$	2,711		$	9,963
Stock-based compensation cost included in net loss, pro forma (net of tax)	$	2,773		$	10,762

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12.Commitments and Contingencies

Litigation

We are party to various litigation matters arising out of the normal course of business, the more significant of which are summarized below. The ultimate outcome of each of these matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated presently for every case. The liability we may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued with respect to such matters and, as a result of these matters, may potentially be material to our financial position or results of operations. Further, we and the majority of our subsidiaries filed either for reorganization under Chapter 11 in the U.S. Bankruptcy Court or creditor protection under the CCAA in the Canadian Court on the Petition Date, and additional subsidiaries have filed thereafter. Generally, all actions to enforce or otherwise effect repayment of liabilities preceding the Petition Date as well as pending litigation against the Calpine Debtors are stayed while the Calpine Debtors continue their business operations as debtors-in-possession. Accordingly, unless indicated otherwise, each case listed below is currently stayed. To the extent that there are any judgments against us in any of these matters during the pendency of our Chapter 11 cases, we expect that such judgments would be classified as LSTC. See Note 2 for information regarding our Chapter 11 cases and CCAA proceedings.

Hawaii Structural Ironworkers Pension Fund v. Calpine, et al.  This case was brought as a class action on behalf of purchasers in Calpine’s April 2002 stock offering under Section 11 of the Securities Act. This case was filed in San Diego County Superior Court on March 11, 2003, and subsequently transferred to Santa Clara County Superior Court. Defendants in this case are Calpine Corporation, Peter Cartwright, Ann B. Curtis, John Wilson, Kenneth Derr, George Stathakis, Credit Suisse First Boston, Banc of America Securities, Deutsche Bank Securities, and Goldman, Sachs & Co. The Hawaii Structural Ironworkers Pension Fund alleges that the prospectus and registration statement for the April 2002 offering contained false or misleading statements regarding: Calpine’s actual financial results for 2000 and 2001; Calpine’s projected financial results for 2002; Mr. Cartwright’s agreement not to sell or purchase shares within 90 days of the April 2002 offering; and Calpine’s alleged involvement in “wash trades.” This action is stayed as to Calpine Corporation as a result of our Chapter 11 filing. In addition, Calpine Corporation filed a motion with the U.S. Bankruptcy Court to extend the automatic stay to the individual defendants listed above (or enjoin further prosecution of the action). The Hawaii Structural Ironworkers Pension Fund opposed that motion. On June 5, 2006, the motion was granted by the U.S. Bankruptcy Court. On June 13, 2006, the Santa Clara County Superior Court stayed the action as to Credit Suisse First Boston, Banc of America Securities, Deutsche Bank Securities, and Goldman, Sachs & Co., setting a case management conference for December 12, 2006, to review the status of the case. The case is now stayed as to all defendants. On June 16, 2006, the Hawaii Structural Ironworkers Pension Fund filed a notice of appeal of the U.S. Bankruptcy Court’s order extending the automatic stay to the individual defendants. Both sides have now filed briefs and oral argument is currently scheduled for December 11, 2006. There is no trial date in this action. We consider this lawsuit to be without merit and, should the case proceed against Calpine Corporation, intend to continue to defend vigorously against the allegations.

Phelps v. Calpine Corporation, et al.  Two nearly identical class action complaints alleging claims under ERISA were consolidated under the caption In re Calpine Corp. ERISA Litig., Master File No. C 03-1685 SBA as filed in the Northern District Court against Calpine Corporation, the members of Calpine Corporation’s Board of Directors, the 401k Plan’s Advisory Committee and its members, signatories of the 401k Plan’s Annual Return/Report of Employee Benefit Plan Forms 5500 for 2001 and 2002, an employee of a consulting firm hired by the 401k Plan, and unidentified fiduciary defendants alleging claims under ERISA purportedly on behalf of the participants in the 401k Plan from January 5, 2001, to the present who invested in the Calpine unitized stock fund. Plaintiffs allege that defendants breached their fiduciary duties involving the 401k Plan, in violation of ERISA. All of the plaintiffs’ claims were dismissed with prejudice by the Northern District Court. The plaintiffs appealed the dismissal to the Ninth Circuit Court of Appeals. In addition, Calpine Corporation filed a motion with the U.S. Bankruptcy Court to extend the automatic stay to the individual defendants. Plaintiffs opposed the motion and the hearing was scheduled for June 5, 2006; however, prior to the hearing, the parties stipulated to allow the appeal to proceed. If the Northern District Court ruling is reversed, the plaintiffs may then seek leave from the U.S. Bankruptcy Court to proceed with the action. Plaintiff’s opening brief is due to be filed with the Ninth Circuit Court of Appeals in November 2006. Defendant’s opposition is due in January 2007. Plaintiff may file a reply brief within 30 days of service of the

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opposition brief. We consider this lawsuit to be without merit and, should the case proceed against Calpine Corporation, intend to continue to defend vigorously against the allegations.

Johnson v. Peter Cartwright, et al.  On December 17, 2001, a shareholder filed a derivative lawsuit on behalf of Calpine Corporation against its directors and one of its senior officers. This lawsuit is styled Johnson vs. Cartwright, et al. (No. CV803872) and is pending, but stayed, in Santa Clara County Superior Court. Calpine Corporation is a nominal defendant in this lawsuit, which alleges claims relating to purportedly misleading statements about Calpine Corporation and stock sales by certain of the director defendants and the officer defendant. On July 1, 2003, the Santa Clara County Superior Court granted Calpine Corporation’s motion to stay this proceeding until In re Calpine Corporation Securities Litigation, an action then-pending in the Northern District of California, was resolved, or until its further order. In re Calpine Corporation Securities Litigation was resolved by a settlement in November 2005. This case is stayed as to Calpine Corporation as a result of our Chapter 11 filing. In addition, Calpine Corporation filed a motion with the U.S. Bankruptcy Court to extend the automatic stay to the individual defendants and plaintiff opposed the motion. On June 5, 2006, the motion was granted by the U.S. Bankruptcy Court extending the stay to the individual defendants and ruling that plaintiff has no standing to pursue derivative claims because they are now property of the estate. Accordingly, the case is now stayed as to Calpine Corporation and the individual defendants. We consider this lawsuit to be without merit and, should the case proceed against Calpine Corporation, intend to defend vigorously against the allegations if the stay is lifted.

Panda Energy International, Inc., et al. v. Calpine Corporation, et al.  On November 5, 2003, Panda filed suit in the U.S. District Court, Northern District of Texas against Calpine Corporation and certain of its affiliates alleging, among other things, that defendants breached duties of care and loyalty allegedly owed to Panda by failing to correctly construct and operate the Oneta power plant, which we had acquired from Panda, in accordance with Panda’s original plans. Panda alleges that it is entitled to a portion of the profits of the Oneta plant and that the defendant’s actions have reduced the profits from Oneta thereby undermining Panda’s ability to repay monies owed to Calpine on December 1, 2003, under a promissory note on which approximately $38.6 million (including related interest) is currently outstanding. Calpine has filed a counterclaim against Panda based on a guaranty. Defendants have also been successful in dismissing the causes of action alleged by Panda for federal and state securities laws violations. We consider Panda’s lawsuit to be without merit and intend to vigorously defend it. Calpine stopped accruing interest income on the promissory note due December 1, 2003, as of the due date because of Panda’s default on repayment of the note. Trial was set for May 22, 2006, but did not proceed due to the stay. There has been no activity since the Petition Date.

Snohomish PUD No.1, et al. v. FERC (regarding Nevada Power Company and Sierra Pacific Power Company v. Calpine Energy Services, L.P. complaint dismissed by FERC).  On December 4, 2001, NPC and SPPC filed a complaint with FERC under Section 206 of the FPA against a number of parties to their PPAs, including CES. NPC and SPPC allege in their complaint that the prices they agreed to pay in certain of the PPAs, including those signed with CES, were negotiated during a time when the spot power market was dysfunctional and that they are unjust and unreasonable. The complaint therefore sought modification of the contract prices. The administrative law judge issued an Initial Decision on December 19, 2002, that found for CES and the other respondents in the case and denied NPC and SPPC the relief that they were seeking. In a June 26, 2003 order, FERC affirmed the judge’s findings and dismissed the complaint, and subsequently denied rehearing of that order. The matter is pending on appeal before the Ninth Circuit Court of Appeals. CES has participated in briefing and arguments before the Ninth Circuit Court of Appeals defending the FERC orders, but we are not able to predict at this time the outcome of appeal before the Ninth Circuit Court of Appeals. There has been no activity since the Petition Date.

Transmission Service Agreement with Nevada Power Company.  On September 30, 2004, NPC filed a complaint in state district court of Clark County, Nevada against Calpine Corporation, Moapa, FFIC and unnamed parties alleging, among other things, breach by Calpine Corporation of its obligations under a TSA between Calpine Corporation and NPC for 400 MW of transmission capacity and breach by FFIC of its obligations under a surety bond, which surety bond was issued by FFIC to NPC to support Calpine Corporation’s obligations under this TSA. This proceeding was removed from state court to the United States District Court for the District of Nevada. On December 10, 2004, FFIC filed a motion to dismiss, which was granted on May 25, 2005 with respect to claims asserted by NPC that FFIC had breached its obligations under the surety bond by not honoring NPC’s demand that the full amount of the surety bond ($33,333,333.00) be paid to NPC in light of Calpine Corporation’s failure to provide replacement collateral upon the expiration of the surety bond on May 1, 2004. NPC’s motion to amend the complaint was granted on November 17, 2005 and its amended complaint was filed December 8,

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2005. This case was stayed as to Calpine Corporation and Moapa on the Petition Date, but not as to co-defendant FFIC. On February 10, 2006, FFIC filed a motion to dismiss NPC’s amended complaint for failure to state a claim against FFIC. On June 1, 2006, the district court issued an order denying FFIC’s motion. FFIC answered the amended complaint on June 16, 2006. On August 1, 2006, the U.S. Debtors filed an adversary complaint and motion against NPC seeking an extension of the automatic stay, or in the alternative, a temporary injunction to preclude NPC from pursuing its derivative claims against FFIC while the U.S. Debtors restructured. On August 16, 2006, NPC agreed to take no further action in the Nevada district court litigation until the U.S. Bankruptcy Court ruled on the U.S. Debtors’ motion. The Creditors’ Committee and FFIC filed motions to intervene in the adversary proceeding, which were granted on October 25, 2006. Also on October 25, 2006, the U.S. Bankruptcy Court granted the U.S. Debtors’ motion, enjoining prosecution of the NPC action until after the successful implementation of a plan of reorganization or further order of the U.S. Bankruptcy Court. On November 1, 2006, NPC filed a notice of appeal of the U.S. Bankruptcy Court’s decision enjoining prosecution of the NPC action.

Harbert Distressed Investment Master Fund, Ltd. v. Calpine Canada Energy Finance II ULC, et al.  On May 5, 2005, the Harbert Distressed Fund filed an application in the Supreme Court of Nova Scotia against Calpine Corporation and certain of its subsidiaries, including ULC II, the issuer of certain senior notes held by the Harbert Distressed Fund, and CCRC, the parent company of ULC II. Calpine Corporation has guaranteed the ULC II senior notes. In June 2005, the ULC II senior notes indenture trustee joined the application as co-applicant on behalf of all holders of the ULC II senior notes. The Harbert Distressed Fund and the ULC II senior notes indenture trustee alleged that Calpine Corporation, CCRC and ULC II violated the Harbert Distressed Fund’s rights under Nova Scotia laws in connection with certain financing transactions completed by CCRC or subsidiaries of CCRC.

On August 2, 2005, the Supreme Court of Nova Scotia denied all relief to the Harbert Distressed Fund and all other holders of the ULC II senior notes that purchased ULC II senior notes on or after September 1, 2004. However, the Supreme Court of Nova Scotia did state that a remedy should be granted to any holder of ULC II senior notes, other than the Calpine respondent companies, that purchased ULC II senior notes prior to September 1, 2004 and that continued to hold those ULC II senior notes on August 2, 2005 and in connection therewith ordered CCRC to maintain control of the net proceeds from the sale of the Saltend facility until a final order was issued. On November 30, 2005, the ULC II senior notes indenture trustee filed a final report confirming the aggregate face value of bonds held by holders of the ULC II senior notes that purchased such ULC II senior notes prior to September 30, 2004 and that continued to hold those ULC II senior notes on August 2, 2005 was (at then-current exchange rates) approximately $42,125,000.

On December 19 and 20, 2005, the parties reappeared before the Supreme Court of Nova Scotia to settle the terms of the final order. After argument, and to enable the parties to address an application by the ULC II senior notes indenture trustee to produce further information and documentation, this application was adjourned to January 12, 2006. On the Petition Date, in addition to Calpine’s Chapter 11 filing, the Canadian Debtors, including ULC II and CCRC instituted the CCAA proceedings before the Canadian Court. As a result of the Chapter 11 cases and CCAA proceedings, all Canadian legal proceedings are stayed, and in particular the application to settle the final order in the application has been adjourned indefinitely.

In connection with the CCAA proceedings, Calpine Corporation has given undertakings to the Canadian Court and to the ULC II senior notes indenture trustee that: (i) the net Saltend sale proceeds remain at Calpine UK Holdings Limited, a subsidiary of CCRC; (ii) Calpine Corporation intends to continue to hold the monies there and will provide advance notice to the ULC II senior notes indenture trustee and the service list in the CCAA proceedings if that intention changes; (iii) the Saltend sale proceeds held at Calpine UK Holdings Limited are not pledged as collateral for the DIP Facility; and (iv) Calpine Corporation will provide advance notice to the ULC II senior notes indenture trustee and the service list in the CCAA proceedings of any filing of Calpine UK Holdings Limited in Canada, the U.S. or the United Kingdom. On July 31, 2006, consistent with the undertakings given to the Canadian Court and the order entered by the Supreme Court of Nova Scotia dated August 2, 2005, the Canadian Debtors gave notice that the net proceeds of the Saltend sale were being (and now have been) repatriated to Canadian Debtor CCRC.

Harbert Convertible Arbitrage Master Fund, Ltd. et al. v. Calpine Corporation.  Plaintiff Harbert Convertible Fund and two affiliated funds filed this action on July 11, 2005, in the New York County Supreme Court, and filed an amended complaint on July 19, 2005. In their amended complaint, plaintiffs allege that in a July 5, 2005 letter to Calpine Corporation

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they provided “reasonable evidence” as required under the indenture governing the 2014 Convertible Notes that, on one or more days beginning on July 1, 2005, the trading price of the 2014 Convertible Notes was less than 95% of the product of the common stock price multiplied by the conversion rate, as those terms are defined in the 2014 Convertible Notes indenture, and that Calpine Corporation therefore was required to instruct the bid solicitation agent for the 2014 Convertible Notes to determine the trading price beginning on the next trading day. If the trading price as determined by the bid solicitation agent was below 95% of the product of the common stock price multiplied by the conversion rate for the next five consecutive trading days, then the 2014 Convertible Notes would become convertible into cash and common stock for a limited period of time. Plaintiffs have asserted a claim for breach of contract, seeking unspecified damages, because Calpine Corporation did not instruct the bid solicitation agent to begin to calculate the trading price. In addition, plaintiffs sought a declaration that Calpine had a duty, based on the statements in the July 5th letter, to commence the bid solicitation process, and also sought injunctive relief to force Calpine Corporation to instruct the bid solicitation agent to determine the trading price of the 2014 Convertible Notes.

On November 18, 2005, Harbert Convertible Fund filed a second amended complaint for breach and anticipatory breach of indenture, which also added the 2014 Convertible Notes trustee as a plaintiff. At a court hearing on November 22, 2005, counsel for Harbert Convertible Fund and the 2014 Convertible Notes trustee again sought an expedited trial, stating that plaintiffs were willing to forego affirmative discovery and could respond to Calpine Corporation’s forthcoming discovery requests promptly. The New York County Supreme Court ordered Harbert Convertible Fund and the 2014 Convertible Notes trustee to provide specified discovery immediately, to respond promptly to any additional discovery demands from Calpine Corporation, and ordered the parties to commence depositions in January 2006. The New York County Supreme Court did not set a firm trial date, but suggested that a trial could occur by early March 2006. Calpine Corporation moved to dismiss the second amended complaint on December 13, 2005. In the meantime, Harbert Convertible Fund and the 2014 Convertible Notes trustee delayed providing any discovery, stating their belief that a bankruptcy filing was imminent that could moot the case or in any event stay it. There has been no activity since the Petition Date.

Whitebox Convertible Arbitrage Fund, L.P., et al. v. Calpine Corporation.  Plaintiff Whitebox Convertible Arbitrage Fund, L.P. and seven affiliated funds filed an action in the New York County Supreme Court for breach of contract on October 17, 2004. The factual allegations and legal basis for the claims set forth in that action are nearly identical to those set forth in the Harbert Convertible Fund filings. On October 19, 2005, the Whitebox plaintiffs filed a motion for preliminary injunctive relief, but withdrew the motion on November 7, 2005. Whitebox had informed Calpine Corporation and the New York County Supreme Court that the Trustee was considering intervening in the case and/or filing a similar action for the benefit of all holders of the 2014 Convertible Notes. There has been no activity since the Petition Date.

Calpine Corporation v. The Bank of New York, Collateral Trustee for Senior Secured Note Holders, et al.  In September of 2005, Calpine Corporation received a letter from the Collateral Trustee informing Calpine of disagreements purportedly raised by certain holders of First Priority Notes regarding Calpine Corporation’s reinvestment of the proceeds from its recent sale of natural gas assets to Rosetta. As a result of these concerns, the Collateral Trustee informed Calpine Corporation that it would not allow further withdrawals from the gas sale proceeds account until these disagreements were resolved. On September 26, 2005, Calpine Corporation filed a Declaratory Relief Action in the Delaware Court of Chancery against the Collateral Trustee and the First Priority Trustee, seeking a declaration that Calpine Corporation’s past and proposed purchases of natural gas assets were permitted by the indenture for the First Priority Notes and related documents, and also seeking an injunction compelling the Collateral Trustee to release funds requested to be withdrawn.

The First Priority Trustee counterclaimed, seeking an order compelling Calpine Corporation to, among other things, (i) pay damages in an amount not less than $365 million plus prejudgment interest either to the First Priority Trustee or into the gas sale proceeds account; (ii) return to the gas sale proceeds account all amounts previously withdrawn from such account and used by Calpine Corporation to purchase natural gas in storage; and (iii) indemnify the First Priority Trustee for all expenses incurred in connection with defending the lawsuit and pursuing counterclaims. In addition, the Second Priority Trustee intervened on behalf of the holders of the Second Priority Notes. Calpine Corporation filed a motion to dismiss the First Priority Trustee’s counterclaims on the grounds that the holders of the First Priority Notes (and the First Priority Trustee on behalf of the holders of the First Priority Notes) had no remaining right under the indenture governing the First Priority Notes to obtain the relief requested because Calpine Corporation had made, and the holders of the First Priority Notes had

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subsequently declined, an offer to purchase all of the First Priority Notes at par. A bench trial on the above claims was held before the Delaware Court of Chancery on November 11, 2005.

Following a one-day bench trial, post-trial briefing and oral argument, the Delaware Chancery Court ruled against Calpine Corporation on November 22, 2005, holding that Calpine’s use of approximately $313 million of gas sale proceeds (including related interest) to purchase certain gas storage inventory violated the indentures governing Calpine’s Second Priority Notes and that use of the proceeds for similar contracts was impermissible. The Chancery Court denied the First Priority Trustee’s counterclaims on the grounds asserted in Calpine Corporation’s motion to dismiss—namely, that the First Priority Trustee had no right to the requested relief under the indenture governing the First Priority Notes because the holders of the First Priority Notes had declined an offer made by Calpine Corporation to purchase all of the First Priority Notes at par. On December 5, 2005, the Chancery Court entered a Final Order and Judgment affording Calpine Corporation until January 22, 2006, to restore to a collateral account $311,782,955.55, plus interest. Calpine Corporation appealed, and the First Priority Trustee and Second Priority Trustee cross-appealed. On December 16, 2005, the Delaware Supreme Court affirmed the Chancery Court’s ruling that Calpine’s use of proceeds was impermissible; reversed the decision that the First Priority Trustee lacked standing to object to such use; and directed the Chancery Court to issue a modified final order in accordance with the Supreme Court’s decision. An Amended Final Order was entered by the Chancery Court on December 20, 2005. There has been no activity since the Petition Date.

Other

See Note 2 for a description of the Chapter 11 cases and CCAA proceedings, including the description of a pending proceeding regarding our motion to reject eight PPAs and related FERC and other court proceedings. See also Note 15 for information concerning several matters with respect to the California power market.

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

13.Assets Held for Sale

On July 26, 2006, the U.S. Bankruptcy Court approved our motion to sell our leasehold interest in the Fox Energy Center, a 560-MW natural gas-fired facility located in Kaukauna, Wisconsin. The closing of this transaction occurred on October 11, 2006. Accordingly, we reclassified the assets and liabilities of Fox Energy Center as held for sale in our Consolidated Condensed Balance Sheet at September 30, 2006. On September 13, 2006, the U.S. Bankruptcy Court approved our motion to sell the Dighton Power Plant, a 170-MW natural gas-fired facility located in Dighton, Massachusetts. The closing of this transaction occurred on October 1, 2006. Dighton Power Plant meets the criteria of assets held for sale; however, due to the full impairment of its property, plant, and equipment and inventory in December 2005 and March 2006, respectively, there was no material impact on our Consolidated Condensed Balance Sheet at September 30, 2006. The carrying amounts of the major classes of assets and liabilities held for sale which are included in our Electric Generation and Marketing segment are as follows (in thousands):

	September 30, 2006
Assets
Cash and cash equivalents	$	17,452
Interest receivable		78
Inventories		1,126
Restricted cash		5,269
Property, plant and equipment, net		343,675
Total current assets held for sale	$	367,600
Liabilities
Accrued interest payable	$	11,452
Construction/project financing, current portion		352,328
Total current liabilities held for sale	$	363,780

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We have not reported the results of Fox Energy Center or Dighton Power Plant as discontinued operations in our Consolidated Condensed Statements of Operations due to our continuing involvement in the markets in which they operate.

In addition, we have reclassified $39.5 million from current assets held for sale to other assets in our Consolidated Condensed Balance Sheet at September 30, 2006, which represents the book value of the remaining oil and gas properties, which are being held in escrow until consents can be obtained. Due to the ongoing dispute related to the sale of our oil and gas properties to Rosetta, we believe there is substantial doubt that these assets will be disposed of within one year.

14.Operating Segments

We are first and foremost an electric generating company. In pursuing this business strategy, it had once been our objective to produce a portion of our fuel consumption requirements from our own natural gas reserves. However, in July 2005, we sold substantially all of our remaining domestic oil and gas assets to Rosetta. As a result of the sale of substantially all of our oil and gas assets, we now have two reportable segments, “Electric Generation and Marketing” and “Other.” The Electric Generation and Marketing segment includes the development, acquisition, ownership and operation of power production facilities, including hedging, balancing, optimization, and trading activity related to power generation. The Other segment includes the activities of our parts and services businesses and our gas pipeline assets.

We evaluate performance based upon several criteria including profits before tax. The financial results for our operating segments have been prepared on a basis consistent with the manner in which our management internally disaggregates financial information for the purposes of assisting in making internal operating decisions.

Certain costs related to company-wide functions are allocated to each segment, such as interest expense and interest income, based on a ratio of segment assets to total assets. Due to the integrated nature of the business segments, estimates and judgments have been made in allocating certain revenue and expense items, and reclassifications have been made to prior periods to present the allocation consistently.

	Electric Generation andMarketing		Other			Corporate and Eliminations			Total
For the three months ended September 30, 2006:
Total revenue from external customers	$	2,149,372	$	25,599		$	(16,592	)	$	2,158,379
Income (loss) before reorganization items and benefit for taxes		178,147		(560	)		(29,450	)		148,137

	Electric Generation andMarketing			Other			Corporate and Eliminations			Total
For the three months ended September 30, 2005:
Total revenue from external customers	$	3,258,135		$	39,819		$	(16,364	)	$	3,281,590
Loss before provision (benefit) for taxes and discontinued operations		(154,212	)		(24,197	)		(46,539	)		(224,948	)

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	Electric Generation andMarketing			Other			Corporate and Eliminations			Total
For the nine months ended September 30, 2006:
Total revenue from external customers	$	5,072,198		$	80,755		$	(47,008	)	$	5,105,945
Loss before reorganization items, benefit for taxes and cumulative effect of a change in accounting principle		(216,348	)		(1,419	)		(125,316	)		(343,083	)

	Electric Generation andMarketing			Other			Corporate and Eliminations			Total
For the nine months ended September 30, 2005:
Total revenue from external customers	$	7,458,475		$	193,700		$	(125,947	)	$	7,526,228
(Loss) income before benefit for taxes and discontinued operations		(758,772	)		(69,116	)		38,546			(789,342	)

	Electric Generation andMarketing		Other		Corporate and Eliminations		Total
Total assets:
September 30, 2006	$	18,502,449	$	302,514	$	422,751	$	19,227,714
December 31, 2005	$	19,380,779	$	311,902	$	852,116	$	20,544,797

15.California Power Market

CPUC Proceeding Regarding QF Contract Pricing for Past Periods.  Our 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 by determining the short run avoided cost, or SRAC, energy price formula. In mid-2000, our QF facilities elected the option set forth in Section 390 of the California Public Utilities Code, which provided QFs the right to elect to receive energy payments based on the CalPX market clearing price instead of the SRAC price administratively determined by the CPUC. Having elected such option, our QF facilities were paid based upon the CalPX Price for various periods commencing in the summer of 2000 until January 19, 2001, when the CalPX ceased operating a day-ahead market. The CPUC has conducted proceedings (R.99-11-022) to determine whether the CalPX Price was the appropriate price for the energy component upon which to base payments to QFs which had elected the CalPX-based pricing option. In late 2000, the CPUC Commissioner assigned to the matter issued a proposed decision to the effect that the CalPX Price was the appropriate energy price to pay QFs who selected the pricing option then offered by Section 390, but the CPUC has yet to issue a final decision. Therefore, it is possible that the CPUC could order a payment adjustment based on a different energy price determination.

On April 14, 2006, our QFs with existing QF contracts with PG&E executed amendments to, among other matters, adjust the energy price paid and to be paid to QFs and extinguish any potential refund obligation to PG&E for energy payments these QFs received based on the CalPX Price. Each amendment, when effective, authorizes PG&E to pay an adjusted energy price under our existing QF contracts prospectively for a number of years as part of the consideration for the extinguishment of the potential for any retroactive refund liability relating to the energy payments based on the CalPX Price. On April 18, 2006, PG&E and the Independent Energy Producers Association filed a joint motion requesting that the CPUC approve the settlement and the individual QF contract amendments, including our existing QF contracts. On June 21, 2006, a proposed decision was issued by the CPUC administrative law judges assigned to the case approving the joint motion. The amendments and the settlement were not effective until the CPUC issued a decision and such decision was deemed final. On July 20, 2006, the CPUC issued a decision approving both the settlement and the individual QF contract amendments. Pursuant to the settlement, both the settlement and the amendments were not effective until the thirty-day appeal period had been exhausted, which occurred on August 19, 2006. As a result of the settlement, we expect that PG&E will withdraw its proofs of claim in the Chapter 11 cases amounting to approximately $300 million.

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California Refund Proceeding.  On August 2, 2000, the California refund proceeding was initiated by a complaint made at the FERC, by SDG&E under Section 206 of the FPA alleging, among other things, that the markets operated by CAISO, and the CalPX, were dysfunctional. FERC established a refund effective period of October 2, 2000, to June 19, 2001 (the “Refund Period”), for sales made into those markets.

On December 12, 2002, an Administrative Law Judge issued a Certification of Proposed Finding on California Refund Liability (the “December 12 Certification”) making an initial determination of refund liability. On March 26, 2003, FERC issued an order (the “March 26 Order”) adopting many of the findings set forth in the December 12 Certification. In addition, as a result of certain findings by the FERC staff concerning the unreliability or misreporting of certain reported indices for gas prices in California during the Refund Period, FERC ordered that the basis for calculating a party’s potential refund liability be modified by substituting a gas proxy price based upon gas prices in the producing areas plus the tariff transportation rate for the California gas price indices previously adopted in the California refund proceeding. We believe, based on the available information, that any refund liability that may be attributable to us could total approximately $10.1 million (plus interest, if applicable), after taking the appropriate set-offs for outstanding receivables owed by the CalPX and CAISO to Calpine. We believe we have appropriately reserved for the refund liability that by our current analysis would potentially be owed under the refund calculation clarification in the March 26 Order. The final determination of the refund liability and the allocation of payment obligations among the numerous buyers and sellers in the California markets is subject to further FERC proceedings to ascertain the allocation of payment obligations among the numerous buyers and sellers in the California markets.

The numerous FERC orders concerning the refund proceeding are pending on appeal before the U.S. Ninth Circuit Court of Appeals. On August 2, 2006, the court issued an opinion on several discrete issues raised in the various appeals. Among other things, the court determined that FERC had properly established the Refund Period as beginning on October 2, 2000, and had properly limited the transactions subject to refund to transactions occurring within the CalPX and CAISO markets. However, the court also found that FERC had erred in not considering (1) whether any tariff violations had occurred prior to October 2, 2000 which might justify imposition of additional remedies, (2) whether refunds should be required for any transactions within the CalPX and CAISO markets for periods longer than 24 hours, and (3) whether certain “exchange transactions” within the CalPX and CAISO markets should be subject to refund. These latter issues were remanded to FERC for its further consideration. At this time, we are unable to predict the timing of the completion of these proceedings or the final refund liability. Thus, the impact on our business is uncertain.

Geysers RMR Section 206 Proceeding.  CAISO, EOB, CPUC, PG&E, SDG&E, and Southern California Edison Company, which we refer to collectively as the “Buyers Coalition” filed a complaint on November 2, 2001, at FERC requesting the commencement of a FPA Section 206 proceeding to challenge one component of a number of separate settlements previously reached on the terms and conditions of RMR Contracts with certain generation owners, including GPC, which settlements were also previously approved by 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 asked FERC to find that the availability payments under these RMR Contracts are not just and reasonable. On June 3, 2005, FERC issued an order dismissing the Buyers Coalition’s complaint against all named generation owners, including GPC. On August 2, 2005, FERC issued an order denying requests for rehearing of its order. On September 23, 2005, the Buyers Coalition (with the exclusion of the CAISO) filed a Petition for Review with the U.S. Court of Appeals for the D.C. Circuit, seeking review of FERC’s order dismissing the complaint. On May 18, 2006, FERC filed a motion with the D.C. Circuit Court requesting the court to hold the proceeding in abeyance and to voluntarily remand the case to FERC in order to permit FERC to further consider the issues raised. On June 19, 2006, the D.C. Circuit Court granted FERC’s motion. On July 10, 2006, the Buyers Coalition filed a motion asking FERC to establish hearing procedures in this proceeding. On July 25, 2006, Calpine submitted an answer to the Buyers Coalition motion, urging FERC to uphold its prior decisions rejecting the complaint and terminating the proceedings. FERC has taken no action on remand. On or about October 12, 2006, GPC, Delta Energy Center, LLC, and certain other Calpine entities executed a Settlement and Release of Claims Agreement with the CAISO, EOB and PG&E resolving the claims under the Geysers RMR Section 206 Proceeding and the Delta RMR Proceeding (discussed below).

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Delta RMR Proceeding.  Through our subsidiary Delta Energy Center, LLC, we are party to a recurring, yearly RMR Contract, which the CAISO originally entered into in 2003. When the Delta RMR Contract was first offered by us, several issues about the contract were disputed, including whether the CAISO accepted Delta’s bid for RMR service; whether the CAISO was bound by Delta’s bid price; and whether Delta’s bid price was just and reasonable. The Delta RMR Contract was filed and accepted by FERC effective February 10, 2003, subject to refund. On May 30, 2003, the CAISO, PG&E and Delta entered into a settlement regarding the Delta RMR Contract. Under the terms of this settlement, the parties agreed to interim RMR rates which Delta would collect, subject to refund, from February 10, 2003, forward. The parties agreed to defer further proceedings on the Delta RMR Contract until a similar RMR proceeding involving Mirant Corp. was resolved by FERC. Under the terms of the settlement, Delta continued to provide services to the CAISO pursuant to the interim RMR rates, terms and conditions. Since the settlement was entered into, Delta and CAISO have entered into RMR Contracts for the years 2003, 2004 and 2005 pursuant to the terms of the settlement.

On June 3, 2005, FERC issued a final order in the Mirant Corp. RMR proceeding, resolving that proceeding and triggering the reopening of the settlement. On November 30, 2005, Delta filed revisions to the Delta RMR contract with FERC, proposing to change the method by which RMR rates are calculated for Delta effective January 1, 2006. On January 27, 2006, FERC issued an order accepting the new Delta RMR rates effective January 1, 2006 and consolidated the issues from the settlement with the 2006 RMR case. FERC set the proceeding for hearing, but has suspended hearing procedures pending settlement discussions among the parties with respect to the rates for both the February 10, 2003 through December 31, 2005, period and the calendar year 2006 period. In addition, to resolve credit concerns raised by certain intervening parties, Delta has begun to direct into an escrow account the difference between the previously filed rate and the 2006 rate pending the determination by FERC as to whether Delta is obligated to refund some portion of the rate collected in 2006. On or about October 12, 2006, GPC, Delta Energy Center, LLC, and certain other Calpine entities executed a Settlement and Release of Claims Agreement with the CAISO, EOB and PG&E resolving the claims under the Delta RMR Proceeding and the Geysers RMR Section 206 Proceeding.

Settlement of Geysers and Delta RMR Proceedings.  The Settlement and Release of Claims Agreement with the CAISO, EOB and PG&E was filed on October 19, 2006, at the FERC. In addition to being subject to FERC approval, the effectiveness of the Settlement and Release of Claims Agreement is contingent upon the satisfaction of certain conditions precedent set forth in other agreements entered into between certain Calpine entities, including GPC, and PG&E. As the parties have agreed that Delta’s 2006 rates shall be the same as the 2005 rates, upon effectiveness of the Settlement and Release of Claims Agreement, Delta shall release to the CAISO amounts held in the escrow account. The Settlement and Release of Claims is part of a larger settlement involving the resolution of a number of RMR-related claims for which PG&E and the CAISO had filed proofs of claim in the Chapter 11 cases amounting to approximately $200 million. Pursuant to the Settlement Agreement, the $200 claim is required to be withdrawn by PG&E and CAISO within five business days after the agreement is approved by FERC and, to the extent necessary, the U.S. Bankruptcy Court and CPUC. Although the overall settlement is subject to FERC approval, on October 24, 2006, we filed a motion with the U.S. Bankruptcy Court for approval of the release of certain Calpine claims under the Settlement and Releases of Claims Agreement. The hearing before the U.S. Bankruptcy Court is currently scheduled for November 15, 2006.

Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations

In addition to historical information, this Report contains forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. We use words such as “believe,” “intend,” “expect,” “anticipate,” “plan,” “may,” “will” and similar expressions to identify forward-looking statements. Such statements include, among others, those concerning our expected financial performance and strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. You are cautioned that any such forward-looking statements are not guarantees of future performance and that a number of risks and uncertainties could cause actual results to differ materially from those anticipated in the forward-looking statements. Such risks and uncertainties include, but are not limited to: (i) the risks and uncertainties associated with our Chapter11 cases and CCAA proceedings, including impact on operations; (ii) our ability to attract, retain, and motivate key employees and successfully implement new strategies; (iii) our ability to successfully reorganize and emerge from Chapter11; (iv) our ability to attract and retain customers and counterparties; (v) our ability to implement our business plan; (vi) financial results that may be volatile and

39

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may not reflect historical trends; (vii) our ability to manage liquidity needs and comply with financing obligations; (viii) the direct or indirect effects on our business of our impaired credit, including increased cash collateral requirements; (ix) the expiration or termination of our PPAs and the related results on revenues; (x) potential volatility in earnings and requirements for cash collateral associated with the use of commodity contracts; (xi) price and supply of natural gas; (xii) risks associated with power project development, acquisition and construction activities; (xiii) risks associated with the operation of power plants including unscheduled outages of operating plants; (xiv) factors that impact the output of our geothermal resources and generation facilities, including unusual or unexpected steam field well and pipeline maintenance and variables associated with the waste water injection projects that supply added water to the steam reservoir; (xv) quarterly and seasonal fluctuations of our results; (xvi) competition; (xvii) risks associated with marketing and selling power from plants in the evolving energy markets; (xviii) present and possible future claims, litigation and enforcement actions; (xix) effects of the application of laws or regulations, including changes in laws or regulations or the interpretation thereof; and (xx) other risks identified in this Report. You should also carefully review other reports that we file with the SEC, including without limitation our 2005 Form 10-K. We undertake no obligation to update any forward-looking statements, whether as a result of new information, future developments or otherwise.

We file annual, quarterly and other reports, proxy statements and other information with the SEC. You may obtain and copy any document we file with the SEC at the SEC’s public reference room at 100 F Street, NE, Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the SEC’s public reference facilities by calling the SEC at 1-800-SEC-0330. You can request copies of these documents, upon payment of a duplicating fee, by writing to the SEC at its principal office at 100 F Street, NE, Room 1580, Washington, D.C. 20549-1004. The SEC maintains an Internet website at http://www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. Our SEC filings, including exhibits filed therewith, are accessible through the Internet at that website.

Our reports on Forms 10-K, 10-Q and 8-K, and amendments to those reports, are available for download, free of charge, as soon as reasonably practicable after these reports are filed with the SEC, at our website at http://www.calpine.com. The content of our website is not a part of this Report. You may request a copy of our SEC filings, at no cost to you, by writing or telephoning us at: Calpine Corporation, 50 West San Fernando Street, San Jose, California 95113, attention: Corporate Secretary, telephone: (408) 995-5115. We will not send exhibits to the documents, unless the exhibits are specifically requested and you pay our fee for duplication and delivery.

Selected Operating Information

	ThreeMonthsEnded				NineMonthsEnded
	September30,				September30,
	2006		2005		2006		2005
	(in thousands, except pricing data)
Power Plants(1):
Electricity and steam revenues:
Energy	$	1,474,759	$	1,634,373	$	3,068,082	$	3,430,720
Capacity		264,277		313,576		707,036		828,981
Thermal and other		103,539		148,374		294,927		365,377
Total electricity and steam revenues		1,842,575		2,096,323		4,070,045		4,625,078
MWh produced		28,385		28,709		62,826		68,240
Average electric price per MWh generated(2)	$	64.91	$	73.02	$	64.78	$	67.78

____________

(1) From continuing operations only. Discontinued operations are excluded.

(2) Excluding the effects of hedging, balancing and optimization activities related to our generating assets.

Set forth above is certain selected operating information for our power plants for which results are consolidated in our statements of operations. Electricity revenue is composed of fixed capacity payments, which are not related to production,

40

Index  Definitions

and variable energy payments, which are related to production. Capacity revenues include, besides traditional capacity payments, other revenues such as those from RMR Contracts and ancillary service revenues. The information set forth under thermal and other revenue consists of host steam sales and other thermal revenue.

Overview

Our core business and primary source of revenue is the generation and delivery of electric power to our customers through the integrated development, construction or acquisition, and operation of efficient and environmentally friendly electric power plants fueled primarily by natural gas and, to a much lesser degree, by geothermal resources. We protect and enhance the value of our electric assets and gas positions with a sophisticated risk management organization. We control certain of our costs by producing certain of the combustion turbine replacement parts that we use at our power plants, and we generate revenue by providing combustion turbine parts to third parties, although we are evaluating these activities in light of our Chapter 11 restructuring.

Currently, the Calpine Debtors continue to conduct business in the ordinary course as debtors-in-possession under the protection of the Bankruptcy Courts. Accordingly, we are devoting a substantial amount of our resources to our Chapter 11 restructuring, which includes developing a new business plan, beginning with a top-to-bottom review of our power assets, business units and markets where we are active, and developing a plan of reorganization, as well as resolving claims disputes and contingencies and determining enterprise value and capital structure. In addition to financial restructuring activities, we are preparing to operate after our emergence from Chapter 11.

Our historical financial performance is likely not indicative of our future performance during the pendency of the Chapter 11 cases and CCAA proceedings or beyond because, among other things: (1) we generally will not accrue interest expense on debt classified as LSTC during the pendency of the Chapter 11 cases; (2) we expect to dispose of or restructure agreements relating to certain plants that do not generate positive cash flow or which are considered non-strategic; (3) we have begun to implement overhead reduction programs, including staff reductions and office closures; (4) we have been able to or are seeking to reject certain unprofitable or burdensome contracts and leases, and we may further seek to reject contracts and leases in the future; (5) we have been able to or are seeking to assume certain beneficial contracts and leases, and we may further seek to assume contracts and leases in the future pursuant to the time frames set forth in the Bankruptcy Code; and (6) we have deconsolidated certain Canadian and other foreign subsidiaries as a result of the CCAA proceedings and currently account for our investment in such entities on a cost basis. We expect to incur substantial reorganization expenses and could record additional impairment charges. In addition, we may be required to adopt fresh start accounting upon emergence from Chapter 11. If fresh start accounting is applicable, our assets and liabilities will be recorded at fair value as of the fresh start reporting date. The fair value of our assets and liabilities as of such fresh start reporting date may differ materially from the recorded values of assets and liabilities on our consolidated balance sheets. In addition, if fresh start accounting is required, our financial results after the application of fresh start accounting may be different from historical trends.

Among other things, we arranged, and the U.S. Bankruptcy Court approved, our DIP Facility, including related cash collateral and adequate assurance motions which has allowed our business activities to continue to function. We have also sought and obtained U.S. Bankruptcy Court approval through our “first day” and subsequent motions to continue to pay critical vendors, meet our payroll pre-petition and post-petition obligations, maintain our cash management systems, collateralize our gas supply contracts, enter into and collateralize trading contracts, pay our taxes, continue to provide employee benefits, maintain our insurance programs and implement an employee severance program, which has allowed us to continue to operate the existing business in the ordinary course. In addition, the U.S. Bankruptcy Court has approved certain trading notification and transfer procedures designed to allow us to restrict trading in our common stock (and related securities) which could negatively impact our accumulated NOLs and other tax attributes, and granted us extensions of time to file and seek approval of a plan of reorganization. Additionally, we have established a systematic and comprehensive lease and executory contract review process to determine which leases and contracts we should assume and which we should reject in the Chapter 11 process. In addition, the Canadian Debtors have obtained protection under the CCAA in Canada, including obtaining a stay that has been extended through November 13, 2006. See Note 2 of the Notes to Consolidated Condensed Financial Statements for additional information regarding our Chapter 11 cases and the CCAA proceedings.

41

Index  Definitions

Comparative Table – Results of Operations for the Three Months Ended September30, 2006

In the comparative tables below, increases in revenue/income or decreases in expense (favorable variances) are shown without brackets while decreases in revenue/income or increases in expense (unfavorable variances) are shown with brackets. Prior year amounts reflect reclassifications for discontinued operations. Amounts are shown in thousands.

	ThreeMonthsEndedSeptember30,
	2006			2005			$ Change			% Change
	(unaudited)
Revenue:
Electricity and steam revenue	$	1,842,575		$	2,096,323		$	(253,748	)		(12	)%
Sales of purchased power and gas for hedging and optimization		272,932			1,110,131			(837,199	)		(75	)
Mark-to-market activities, net		28,461			40,854			(12,393	)		(30	)
Other revenue		14,411			34,282			(19,871	)		(58	)
Total revenue		2,158,379			3,281,590			(1,123,211	)		(34	)
Cost of revenue:
Plant operating expense		174,552			180,336			5,784			3
Royalty expense		7,151			9,988			2,837			28
Transmission purchase expense		18,213			23,088			4,875			21
Purchased power and gas expense for hedging and optimization		296,385			1,068,129			771,744			72
Fuel expense		1,105,248			1,567,504			462,256			29
Depreciation and amortization expense		121,569			131,006			9,437			7
Operating plant impairments		7			—			(7	)		—
Operating lease expense		11,432			28,792			17,360			60
Other cost of revenue		14,232			33,620			19,388			58
Total cost of revenue		1,748,789			3,042,463			1,293,674			43
Gross profit		409,590			239,127			170,463			71
(Income) from unconsolidated investments		—			(5,384	)		(5,384	)		#
Equipment, development project and other impairments		(3,462	)		460			3,922			#
Long-term service cancellation charge		—			553			553			#
Project development expense		5,153			10,399			5,246			50
Research and development expense		4,184			3,342			(842	)		(25	)
Sales, general and administrative expense		49,026			54,593			5,567			10
Income (loss) from operations		354,689			175,164			179,525			#
Interest expense		227,724			380,994			153,270			40
Interest (income)		(19,918	)		(26,640	)		(6,722	)		(25	)
Minority interest expense		7,658			10,977			3,319			30
(Income) from repurchase of various issuances of debt		—			(15,530	)		(15,530	)		#
Other (income) expense, net		(8,912	)		50,311			59,223			#
Income (loss) before reorganization items, benefit for income taxes and discontinued operations		148,137			(224,948	)		373,085			#
Reorganization items		145,273			—			(145,273	)		—
Income (loss) before provision (benefit) for income taxes and discontinued operations		2,864			(224,948	)		227,812			#
Provisions (benefit) for income taxes		1,202			17,487			16,285			93
Loss before discontinued operations		1,662			(242,435	)		244,097			#
Discontinued operations, net of tax provision of $— and $170,514		—			25,746			(25,746	)		#
Net income (loss)	$	1,662		$	(216,689	)	$	218,351			#

____________

# Variance of 100% or greater

42

Index  Definitions

Three Months Ended September30,2006, Compared to Three Months Ended September30,2005

Set forth below is a discussion of our results of operations for the three months ended September 30, 2006, as compared to the same period a year ago. Most of our Canadian and other foreign subsidiaries were deconsolidated effective December 31, 2005, as a result of the filings by the Canadian Debtors under the CCAA. Although not material to the financial statements taken as a whole, period-to-period comparisons are impacted. Accordingly, this Report principally describes the Chapter 11 cases and only describes the CCAA proceedings where they have a material effect on our operations or where such information provides necessary background information.

Total revenue decreased by 34% during the three months ended September 30, 2006, over the same period a year ago primarily due to a 75% decrease in sales of purchased power and gas for hedging and optimization. The decline in sales of purchased power and gas for hedging and optimization resulted primarily from lower electricity and natural gas prices, which thereby reduced the amount of hedging and optimization activity during the three months ended September 30, 2006, compared to the same period a year ago. Additionally, reduced availability of credit and the termination or disruption of certain customer relationships following our Chapter 11 and CCAA filings further limited our ability to conduct hedging and optimization activities. Correspondingly, purchased power and gas expense for hedging and optimization declined by 72% for similar reasons. As a result, the gross profit on these sales and purchases declined by $65.5 million period-to-period.

Electricity and steam revenue declined by approximately 12% due primarily to a 11% reduction in average electric prices before the effects of hedging, balancing and optimization. MWh generated and average baseload capacity factor were slightly lower than the same period a year ago.

Gross profit improved by $170.5 million in the three months ended September 30, 2006, primarily because realized all-in spark spread increased by $136.7 million, or 23%, even though electricity and steam revenue declined by approximately 12% and generation was 1% lower than in the same period a year ago. As a result of unseasonably high temperatures in July and August of 2006, peak spot market spark spreads were higher in our key markets, except in Texas where peak spot market spark spreads in the third quarter of 2005 were unusually strong. Also, we benefited from the termination of certain marginally priced PPAs, and our average realized gas prices in the third quarter of 2006 were approximately 33% lower than in the same quarter of 2005, which provided a benefit to us because of our short gas position on our portfolio of fixed-price electric power contracts. Additionally, depreciation and amortization expense was favorable by $9.4 million and operating lease expense was favorable by $17.4 million.

The favorable variance in depreciation and amortization expense was related primarily to a $19.6 million decrease in depreciation resulting from the $2.4 billion impairment of certain operating plants in the fourth quarter of 2005. The favorable variance was partially offset by increases of $3.4 million resulting from Freeport and Mankato power plants achieving commercial operation in the first and third quarters of 2006, respectively, and $5.3 million related to the purchase of the Geysers Assets in the first quarter of 2006.

The favorable variance in operating lease expense was primarily related to a decrease of $6.5 million resulting from the purchase of the Geysers Assets in the first quarter of 2006 and the termination of the related leases for those facilities, a decrease of $4.7 million related to the rejection of the Rumford and Tiverton leases during the second quarter of 2006, and a decrease of $3.2 million resulting from the non-recurrence of an asset retirement obligation charge related to a leased power plant in 2005.

Interest expense decreased during the three months ended September 30, 2006, over the same period a year ago primarily due to discontinuing the accrual of interest expense related to debt instruments reclassified to LSTC and the repayment of the remaining outstanding $646.1 million of our First Priority Notes in May and June 2006. This favorable variance was partially offset by less capitalized interest related to certain power plants entering commercial operations and project development activities winding down, higher interest rates on floating rate debt, and interest on borrowings under the DIP Facility.

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Index  Definitions

During the three months ended September 30, 2006, we did not repurchase any debt. However, during the comparable period in the prior year, we recorded income of $15.5 million primarily related to the repurchase of $263.5 million principal amount of senior notes.

The net other income for the three months ended September 30, 2006, was primarily due to a $6.0 million distribution received from the Androscoggin Energy LLC bankruptcy estate. During the comparable period in the prior year, we recorded a $43.9 million foreign exchange loss on intercompany loans with our Canadian and other foreign subsidiaries.

Reorganization items of $145.3 million were recorded during the three months ended September 30, 2006, while no similar costs were incurred in the same period a year ago. Reorganization items represent direct and incremental costs related to our Chapter 11 filings, such as professional fees, pre-petition liability claim adjustments and losses that are probable and can be estimated related to terminated contracts. The increase in reorganization items consisted primarily of the following:

• The U.S. Debtors rejected, repudiated or terminated certain gas transportation and power transmission contracts that they have determined no longer provide any benefit to the U.S. Debtors or their estates. We believe that any claims resulting from the repudiation, rejection or termination of these contracts will be treated as pre-petition general unsecured claims. Accordingly, we recorded a non-cash charge of $96.6 million as our current estimate of the expected allowed claims related primarily to these contracts.

• We recorded $8.5 million of additional reorganization expense related to foreign exchange rate movement for certain LSTC items denominated in foreign currencies and governed by foreign law.

• We incurred $38.9 million in professional service fees for legal, financial advisory, valuation and administrative services related to our Chapter 11 cases.

See Note 1 of the Notes to Consolidated Condensed Financial Statements for a discussion of our effective tax rate.

During the three months ended September 30, 2005, discontinued operations activity primarily consisted of the pre-tax gain on the sale of Saltend of $26.3 million and the pre-tax gain on the sale of substantially all of our remaining oil and gas assets of $342.8 million; both dispositions closed in July 2005. Offsetting these gains is a pre-tax impairment charge of $136.8 million related to the sale of Ontelaunee, which met the discontinued operations criterion as of September 30, 2005. On a pre-tax basis, we recorded income from discontinued operations for the three months ended September 30, 2005, of $196.3 million. Our effective tax rate on discontinued operations for the three months ended September 30, 2005, however, was 86.9% due primarily to a large tax return gain on the sale of Saltend and, as a consequence, our after-tax gain from discontinued operations was only $25.7 million.

44

Index  Definitions

Comparative Table – Results of Operations for the Nine Months Ended September30, 2006

In the comparative tables below, increases in revenue/income or decreases in expense (favorable variances) are shown without brackets while decreases in revenue/income or increases in expense (unfavorable variances) are shown with brackets. Prior year amounts reflect reclassifications for discontinued operations. Amounts are shown in thousands.

	NineMonthsEndedSeptember30,
	2006			2005			$ Change			% Change
	(unaudited)
Revenue:
Electricity and steam revenue	$	4,070,045		$	4,625,078		$	(555,033	)		(12	)%
Sales of purchased power and gas for hedging and optimization		891,092			2,767,604			(1,876,512	)		(68	)
Mark-to-market activities, net		88,151			40,197			47,954			#
Other revenue		56,657			93,349			(36,692	)		(39	)
Total revenue		5,105,945			7,526,228			(2,420,283	)		(32	)
Cost of revenue:
Plant operating expense		519,877			555,433			35,556			6
Royalty expense		18,411			28,348			9,937			35
Transmission purchase expense		56,218			63,770			7,552			12
Purchased power and gas expense for hedging and optimization		857,484			2,583,802			1,726,318			67
Fuel expense		2,473,657			3,336,248			862,591			26
Depreciation and amortization expense		350,642			371,340			20,698			6
Operating plant impairments		52,507			—			(52,507	)		—
Operating lease expense		53,030			79,097			26,067			33
Other cost of revenue		53,433			106,865			53,432			50
Total cost of revenue		4,435,259			7,124,903			2,689,644			38
Gross profit		670,686			401,325			269,361			67
(Income) from unconsolidated investments		—			(14,644	)		(14,644	)		#
Equipment, development project and other impairments		64,169			47,356			(16,813	)		36
Long-term service cancellation charge		—			34,445			34,445			#
Project development expense		13,249			24,972			11,723			47
Research and development expense		11,178			15,502			4,324			28
Sales, general and administrative expense		147,349			176,318			28,969			16
Income (loss) from operations		434,741			117,376			317,365			#
Interest expense		819,576			1,027,382			207,806			20
Interest (income)		(59,442	)		(57,417	)		2,025			4
Minority interest expense		10,325			31,763			21,438			67
(Income) loss from repurchase of various issuances of debt		18,131			(166,456	)		(184,587	)		#
Other (income) expense, net		(10,766	)		71,446			82,212			#
Loss before reorganization items, benefit for income taxes, discontinued operations and cumulative effect of a change in accounting principle		(343,083	)		(789,342	)		446,259			57
Reorganization items		1,098,594			—			(1,098,594	)		—
Loss before benefit for income taxes, discontinued operations and cumulative effect of a change in accounting principle		(1,441,677	)		(789,342	)		(652,335	)		(83	)
(Benefit) for income taxes		(35,632	)		(167,866	)		(132,234	)		(79	)
Loss before discontinued operations and cumulative effect of a change in accounting principle		(1,406,045	)		(621,476	)		(784,569	)		#
Discontinued operations, net of tax benefit of $— and $137,629		—			(62,403	)		62,403			#
Cumulative effect of a change in accounting principle, net of tax provision of $312, and $—		505			—			505			—
Net loss	$	(1,405,540	)	$	(683,879	)	$	(721,661	)		#

____________

# Variance of 100% or greater

45

Index  Definitions

Nine Months Ended September30,2006, Compared to Nine Months Ended September30,2005

Set forth below is a discussion of our results of operations for the nine months ended September 30, 2006, as compared to the same period a year ago. Most of our Canadian and other foreign subsidiaries were deconsolidated effective December 31, 2005, as a result of the filings by the Canadian Debtors under the CCAA. Although not material to the financial statements taken as a whole, period-to-period comparisons are impacted. Accordingly, this Report principally describes the Chapter 11 cases and only describes the CCAA proceedings where they have a material effect on our operations or where such information provides necessary background information.

Total revenue decreased by 32% during the nine months ended September 30, 2006, over the same period a year ago primarily due to a 68% decrease in sales of purchased power and gas for hedging and optimization. The decline in sales of purchased power and gas for hedging and optimization resulted primarily from lower electricity and natural gas prices which thereby reduced the amount of hedging and optimization activity during the nine months ended September 30, 2006, compared to the same period a year ago. Additionally, reduced availability of credit and the termination or disruption of certain customer relationships following our Chapter 11 and CCAA filings further limited our ability to conduct hedging and optimization activities. Correspondingly, purchased power and gas expense for hedging and optimization declined by 67% for similar reasons. As a result, the gross profit on these sales and purchases declined by $150.2 million period-to-period.

Electricity and steam revenue declined by approximately 12% due primarily to an 8% reduction in MWh generated and a 4% reduction in average electric prices before the effects of hedging, balancing and optimization. The decrease in generation reflected soft demand in the first quarter of 2006 as a result of strong hydroelectric production in the Northwest and mild weather in general in most of our markets. Also, the average baseload capacity factor declined to 39.2% from 45.9% in the same period a year ago as our average baseload capacity increased by 8% or 1,863 MW as new plants achieved commercial operations.

Gross profit improved by $269.4 million in the nine months ended September 30, 2006, primarily because realized all-in spark spread increased by $139.8 million, or 9%, even though electricity and steam revenue declined by approximately 12% and generation was 8% lower than in the prior year period. As a result of unseasonably high temperatures in July and August 2006, average spot market spark spreads were at or near five year highs in our key markets, except in Texas, where spot market spark spreads in the first nine months of 2005 were unusually strong and in the Northwest due to strong hydroelectric generation in the first half of 2006. Also, we benefited from the termination of certain marginally priced PPAs, and our average realized gas prices during the nine months ended September 30, 2006, were approximately 22% lower than in the same period of 2005, which provided a benefit to us because of our short gas position on our portfolio of fixed-price electric power contracts. Additionally, depreciation and amortization expense was favorable by $20.7 million; operating lease expense was favorable by $26.1 million; other revenue, net of other cost of revenue, was favorable by $16.7 million; and the non-generation related component of net mark-to-market activities was favorable by $63.1 million. These favorable variances were partially offset by an unfavorable variance of $52.5 million related to operating plant impairments in 2006.

The non-generation related component of net mark-to-market activities was favorable for the nine months ended September 30, 2006, compared to the same period a year ago primarily due to the impact of lower gas prices on our short mark-to-market gas position.

The favorable variance in depreciation and amortization expense was driven by a $62.2 million decrease in depreciation resulting from the $2.4 billion impairment of certain operating plants in the fourth quarter of 2005. The favorable variance was partially offset by increases of $22.4 million resulting from Freeport and Mankato power plants achieving commercial operation in the first and third quarters of 2006, respectively, as well as the Fox Energy Center phase I, Pastoria and Metcalf power plants achieving commercial operations in the second quarter of 2005, and Fox Energy Center Phase II in the first quarter of 2006. Additional increases included $12.9 million related to the purchase of the Geysers Assets in the first quarter of 2006, and $6.1 million resulting from a reduction in a power plant’s useful life.

The favorable variance in operating lease expense was due to a decrease of $17.4 million resulting from the purchase of the Geysers Assets in the first quarter of 2006 and the termination of the related leases for those facilities, a decrease of

46

Index  Definitions

$4.7 million related to the rejection of the Rumford and Tiverton leases during the second quarter of 2006 and a decrease of $3.2 million resulting from the non-recurrence of an asset retirement obligation charge related to a leased power plant in 2005.

The favorable variance in other revenue, net of other cost of revenue was due to the non-recurrence of prior period transaction costs of $20.3 million associated with a derivative contract at our Deer Park facility, partially offset by an $8.4 million decrease in net profit resulting from the deconsolidation of TTS as of the Petition Date.

The unfavorable variance in operating plant impairments was due to a $49.7 million non-cash impairment charge related to the Fox Energy Center for which a near-term sale was deemed likely in the first quarter of 2006, and a $2.8 million charge related to leasehold improvement costs on a power plant for which a near-term disposal was deemed likely in the second quarter of 2006. No operating plant impairments were recorded during the nine months ended September 30, 2005; however, we did record $2.4 billion in operating plant impairments during the fourth quarter of 2005.

During the nine months ended September 30, 2006, we recorded equipment, development project, and other impairment charges of $64.2 million related primarily to certain turbine-generator equipment not assigned to projects which are included in other assets in our Consolidated Condensed Balance Sheet. During the second quarter of 2006, we determined that a near-term sale of this equipment is likely and recorded an impairment charge to write down the net book value to estimated market prices. The $47.4 million charge in the comparable period in 2005 related to impairments on the Lone Oak, Towantic, Sherry and Hillabee development projects. We recorded additional equipment, development project, and other impairment charges of $2.1 billion during the fourth quarter of 2005.

The favorable variance of $29.0 million in sales, general and administrative expense was primarily related to the overall reduction in workforce and related benefit expenses. In addition, a significant portion of the consulting and professional fees incurred during the nine months ended September 30, 2006, have been directly related to our Chapter 11 cases, and therefore, are included in reorganization items in our Consolidated Condensed Statements of Operations.

Interest expense decreased during the nine months ended September 30, 2006 over the same period a year ago primarily due to discontinuing the accrual of interest expense related to debt instruments reclassified to LSTC, other than certain debt classified as LSTC on which interest was accrued in accordance with U.S. Bankruptcy Court orders, primarily the Second Priority Debt on which we continued to pay interest through June 30, 2006, pursuant to the Cash Collateral Order. The favorable variance was also due to the repayment of the remaining outstanding $646.1 million of our First Priority Notes in May and June 2006. These favorable variances were partially offset by less capitalized interest related to certain power plants entering commercial operations and project development activities winding down, the effect of prior year interest expense reclassified to discontinued operations, higher interest rates on floating rate debt, and interest on borrowings under the DIP Facility in the current period.

The favorable variance in minority interest expense was due to the deconsolidation of our Canadian and other foreign subsidiaries in December 2005, leaving Acadia as our only subsidiary with minority interest ownership.

During the nine months ended September 30, 2006, we recognized a loss of $18.1 on the repurchase of the First Priority Notes. During the comparable period in the prior year, we recorded an aggregate gain of $166.5 million primarily related to the repurchase of $823.8 million principal amount of senior notes.

The favorable variance of $82.2 million in other income and expense was primarily due to a $6.0 million distribution received from the Androscoggin Energy LLC bankruptcy estate, and gains of $5.7 million related to the sale of emission reduction credits and allowances during the nine months ended September 30, 2006. During the comparable period in the prior year, we recorded an $18.3 million foreign exchange loss on intercompany loans with our Canadian and other foreign subsidiaries. Also included in the nine months ended September 30, 2005, were $16.6 million of expenses related to letter of credit fees and $18.5 million related to the sale of the investment in Grays Ferry in June 2005.

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Reorganization items of $1,098.6 million were recorded during the nine months ended September 30, 2006, while no similar costs were incurred in the same period a year ago. Reorganization items represent direct and incremental costs related to our Chapter 11 filings, such as professional fees, pre-petition liability claim adjustments and losses that are probable and can be estimated related to terminated contracts. The increase in reorganization items consisted primarily of the following:

• On January 16, 2006, CES-Canada repudiated its tolling agreement with Calgary Energy Centre. Calpine Corporation had guaranteed CES-Canada’s performance under the tolling agreement. We recorded a non-cash charge of $232.5 million, which represented the estimated out-of-money value of the contract to CES-Canada on the repudiation date and the expected allowed claim from Calgary Energy Centre to Calpine Corporation under the guarantee.

• We closed the transaction for the rejection of certain of our leases related to the Rumford and Tiverton power plants resulting in a non-cash charge of $234.6 million which includes our current estimate of the expected allowed claim related to the lease rejections, the write-off of prepaid lease expense and certain fees and expenses related to the transaction.

• The U.S. Debtors rejected, repudiated or terminated certain gas transportation and power transmission contracts that they have determined no longer provide any benefit to the U.S. Debtors or their estates. We believe that any claims resulting from the repudiation, rejection, or termination of these contracts will be treated as pre-petition general unsecured claims. Accordingly, we recorded a non-cash charge of $405.4 million as our current estimate of the expected allowed claims related primarily to these contracts.

• We recorded $51.9 million of additional reorganization expense related to foreign exchange rate movement for certain LSTC items denominated in foreign currencies and governed by foreign law.

• We incurred $106.9 million in professional service fees for legal, financial advisory, valuation and administrative services related to our Chapter 11 cases.

• We incurred $34.8 million in origination fees and expenses related to our DIP Facility.

See Note 1 of the Notes to Consolidated Condensed Financial Statements for a discussion of our effective tax rate.

During the nine months ended September 30, 2005, discontinued operations activity primarily consisted of the pre-tax gain on the sale of Saltend of $23.7 million and the pre-tax gain on the sale of substantially all of our remaining oil and gas assets of $340.2 million; both dispositions closed in July 2005. Offsetting these gains are two pre-tax impairment charges of $106.2 million and $136.8 million, related to the sale of Morris and the sale of Ontelaunee, respectively; Ontelaunee met the discontinued operations criterion as of September 30, 2005, under SFAS No. 144 and was written down to the estimated sales price, less transaction costs. On a pre-tax basis, we recorded income from discontinued operations for the nine months ended September 30, 2005, of $75.2 million. However, our effective tax-rate on discontinued operations for the nine months ended September 30, 2005, was 183.0% due primarily to a large tax return gain on the sale of Saltend and, as a consequence, we recognized an after-tax loss from discontinued operations of $62.4 million.

Performance Metrics

In understanding our business, we believe that certain non-GAAP operating performance metrics are particularly important. These are described below:

• MWh generated.  We generate power that we sell to third parties. These sales are recorded as E&S revenue. The volume in MWh is a direct indicator of our level of electricity generation activity.

• Average availability and average baseload capacity factor.  Availability represents the percent of total hours during the period that our plants were available to run after taking into account the downtime associated with both

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scheduled and unscheduled outages. The baseload capacity factor is calculated by dividing (a) total MWh generated by our power plants (excluding peakers) by the product of multiplying (b) the weighted average MW in operation during the period by (c) the total hours in the period. The average baseload capacity factor is thus a measure of total actual generation as a percent of total potential generation. If we elect not to generate during periods when electricity pricing is too low or gas prices too high to operate profitably, the baseload capacity factor will reflect that decision as well as both scheduled and unscheduled outages due to maintenance and repair requirements.

• Average Heat Rate for gas-fired fleet of power plants expressed in Btus of fuel consumed per KWh generated.  We calculate the average Heat Rate for our gas-fired power plants (excluding peakers) by dividing (a) fuel consumed in Btu by (b) KWh generated. The resultant Heat Rate is a measure of fuel efficiency, so the lower the Heat Rate, the lower our cost of generation. We also calculate a “steam-adjusted” Heat Rate, in which we adjust the fuel consumption in Btu down by the equivalent heat content in steam or other thermal energy exported to a third party, such as to steam hosts for our cogeneration facilities.

• Average all-in realized electric price expressed in dollars per MWh generated.  Our risk management and optimization activities are integral to our power generation business and directly impact our total realized revenues from generation. Accordingly, we calculate the all-in realized electric price per MWh generated by dividing (a) adjusted E&S revenue, which includes capacity revenues, energy revenues, thermal revenues, the spread on sales of purchased electricity for hedging, balancing, and optimization activity and generating revenue recorded in mark-to-market activities, net, by (b) total generated MWh in the period.

• Average cost of natural gas expressed in dollars per MMBtu of fuel consumed.  Our risk management and optimization activities related to fuel procurement directly impact our total fuel expense. The fuel costs for our gas-fired power plants are a function of the price we pay for fuel purchased and the results of the fuel hedging, balancing, and optimization activities by CES. Accordingly, we calculate the cost of natural gas per MMBtu of fuel consumed in our power plants by dividing (a) adjusted fuel expense, which includes the cost of fuel consumed by our plants (adding back cost of inter-company gas pipeline costs, which is eliminated in consolidation), the spread on sales of purchased gas for hedging, balancing, and optimization activity, and fuel expense related to generation recorded in mark-to-market activities, net by (b) the heat content in millions of Btu of the fuel we consumed in our power plants for the period.

• Average spark spread expressed in dollars per MWh generated.  Our risk management activities focus on managing the spark spread for our portfolio of power plants, the spread between the sales price for electricity generated and the cost of fuel. We calculate the spark spread per MWh generated by subtracting (a) adjusted fuel expense from (b) adjusted E&S revenue and dividing the difference by (c) total generated MWh in the period.

• Average plant operating expense per MWh.  To assess trends in electric power plant operating expense or POX per MWh, we divide POX by actual MWh.

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The table below shows the operating performance metrics for continuing operations discussed above.

	ThreeMonthsEnded September30,						NineMonthsEnded September30,
	2006			2005			2006			2005
	(inthousandsexcepthoursinperiod,percentages, Heat Rate, price and cost information)
Operating Performance Metrics:
MWh generated		28,385			28,709			62,826			68,240
Average availability		95.8	%		96.5	%		92.6	%		91.7	%
Average baseload capacity factor:
Average total MW in operation		26,900			26,126			26,942			25,079
Less: Average MW of pure peakers		2,965			2,965			2,965			2,965
Average baseload MW in operation		23,935			23,161			23,977			22,114
Hours in the period		2,208			2,208			6,552			6,552
Potential baseload generation (MWh)		52,849			51,139			157,097			144,891
Actual total generation (MWh)		28,385			28,709			62,826			68,240
Less: Actual pure peakers’ generation (MWh)		866			1,069			1,230			1,668
Actual baseload generation (MWh)		27,519			27,640			61,596			66,572
Average baseload capacity factor		52.1	%		54.0	%		39.2	%		45.9	%
Average Heat Rate for gas-fired power plants (excluding peakers)(Btu’s/KWh):
Not steam adjusted		7,999			8,050			8,372			8,346
Steam adjusted		7,213			7,171			7,235			7,202
Average all-in realized electric price:
Electricity and steam revenue	$	1,842,575		$	2,096,323		$	4,070,045		$	4,625,078
Spread on sales of purchased power for hedging and optimization		(32,372	)		69,503			28,461			233,427
Revenue related to power generation in mark-to-market activity, net		56,413			82,583			142,585			157,096
Adjusted electricity and steam revenue	$	1,866,616		$	2,248,409		$	4,241,091		$	5,015,601
MWh generated		28,385			28,709			62,826			68,240
Average all-in realized electric price per MWh	$	65.76		$	78.32		$	67.51		$	73.50
Average cost of natural gas:
Fuel expense	$	1,105,248		$	1,567,504		$	2,473,657		$	3,336,248
Fuel cost elimination		3,132			1,803			9,158			6,738
Spread on sales of purchased gas for hedging and optimization		(8,920	)		27,501			(5,148	)		49,625
Fuel expense related to power generation in mark-to-market activity, net		35,112			56,301			111,409			110,790
Adjusted fuel expense	$	1,134,572		$	1,653,109		$	2,589,076		$	3,503,401
MMBtu of fuel consumed by generating plants		195,181			189,321			426,027			451,480
Average cost of natural gas per MMBtu	$	5.81		$	8.73		$	6.08		$	7.76
MWh generated		28,385			28,709			62,826			68,240
Average cost of adjusted fuel expense per MWh	$	39.97		$	57.58		$	41.21		$	51.34
Average spark spread:
Adjusted electricity and steam revenue	$	1,866,616		$	2,248,409		$	4,241,090		$	5,015,601
Less: Adjusted fuel expense		1,134,572		$	1,653,109		$	2,589,076		$	3,503,401
Spark spread	$	732,044		$	595,300		$	1,652,014		$	1,512,200
MWh generated		28,385			28,709			62,826			68,240
Average spark spread per MWh	$	25.79		$	20.74		$	26.30		$	22.16
Average plant operating expense (POX) per actual MWh:
Plant operating expense (POX)	$	174,552		$	180,336		$	519,877		$	555,433
POX per actual MWh	$	6.15		$	6.28		$	8.27		$	8.14

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Liquidity and Capital Resources

Currently, the Calpine Debtors continue to conduct business in the ordinary course as debtors-in-possession under the protection of the Bankruptcy Courts while a plan or plans of reorganization are developed. Accordingly, the matters described in this section may be significantly affected by our Chapter 11 cases and CCAA proceedings, and by the risks and other factors described in “Forward-Looking Statements,” including the risk factors included in Item 1A. “Risk Factors” included in our 2005 Form 10-K.

Ultimately, whether we will have sufficient liquidity from cash flow from operations, borrowings available under our DIP Facility, and proceeds from asset sales sufficient to fund our operations, including anticipated capital expenditures and working capital requirements, as well as to satisfy our current obligations under our outstanding indebtedness while we remain in Chapter 11 will depend, to some extent, on whether our business plan is successful, including whether we are able to realize expected cost savings from implementing that plan, as well as the other factors noted in “Forward-Looking Statements” including the risk factors included in Item 1A. “Risk Factors” included in our 2005 Form 10-K.

As a result of our Chapter 11 filings and the other matters described herein, including the uncertainties related to the fact that we have not yet had time to complete and have approved a plan of reorganization, there is substantial doubt about our ability to continue as a going concern. Our ability to continue as a going concern, including our ability to meet our ongoing operational obligations, is dependent upon, among other things: (i) our ability to maintain adequate cash on hand; (ii) our ability to generate cash from operations; (iii) the cost, duration and outcome of the restructuring process; (iv) our ability to comply with our DIP Facility agreement and the adequate assurance provisions of the Cash Collateral Order and (v) our ability to achieve profitability following a restructuring. These challenges are in addition to those operational and competitive challenges faced by us in connection with our business. In conjunction with our advisors, we are working to design and implement strategies to ensure that we maintain adequate liquidity and will be able to continue as a going concern. However, there can be no assurance as to the success of such efforts.

Chapter11 Cases and Financing Activities

Our business is capital intensive. Our ability to successfully reorganize and emerge from Chapter 11 protection, while continuing to operate our current fleet of power plants, including completing our remaining plants under construction and maintaining our relationships with vendors, suppliers, customers and others with whom we conduct or seek to conduct business, is dependent on the continued availability of capital on attractive terms. As described below, we have entered into, and obtained U.S. Bankruptcy Court approval of, a $2.0 billion DIP Facility, which we believe will be sufficient to support our operations for the anticipated duration of our Chapter 11 cases. In addition, we have obtained U.S. Bankruptcy Court approval of several other matters that we believe are important to maintaining our ability to operate in the ordinary course during our Chapter 11 cases, including (i) our cash management program (as described under “Cash Management” below), (ii) payments to our employees, vendors and suppliers necessary in order to keep our facilities operational and (iii) procedures for the rejection of certain leases and executory contracts. In order to improve our liquidity position, we also expect to continue our efforts to reduce overhead and discontinue activities without compelling profit potential, particularly in the near term. In addition, development activities will continue to be further reduced, and we expect that certain power plants or other of our assets will be sold or that the agreements relating to certain of our facilities will be restructured, and that commercial operations may be suspended at certain of our power plants during our reorganization effort. See “Rejection of Executory Contracts and Unexpired Leases” and “Asset Sales” below for further details.

In general, we paid current interest on our First Priority Notes until they were repurchased, and we pay current interest on other debt of the Calpine Debtors that has been determined to be fully secured, made periodic cash interest payments pursuant to an order of the U.S. Bankruptcy Court through June 30, 2006, to the holders of Second Priority Debt of the Calpine Debtors and make payments of interest or principal, as applicable, on the debt of our subsidiaries that have not filed for protection under Chapter 11 nor are subject to the CCAA proceedings. The Cash Collateral Order provides that the holders of the Second Priority Debt must seek further orders from the U.S. Bankruptcy Court for any further interest to be paid. We do not generally pay interest or make other debt service payments on the debt of the Calpine Debtors classified as LSTC other than pursuant to applicable U.S. Bankruptcy Court orders (for example, we paid current interest on the Second

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Priority Debt until June 30, 2006, as indicated above). As a result, in the three and nine months ended September 30, 2006, our actual interest payments to unrelated parties were less by $192.3 million and $352.3 million, respectively, compared to contractually specified interest payments (at non-default rates). Total annual contractual interest (at non-default rates) related to debt classified as LSTC is expected to be approximately $650 million for 2006.

We have initiated a comprehensive program designed to stabilize, improve and strengthen our power generation business and our financial health by reducing activities and curtailing expenditures in certain non-core areas and business units. As part of this program, we have begun to implement staff reductions of approximately 1,100 positions, or over one third of our pre-petition workforce, which is expected to be completed by the end of 2007. We expect that the staff reductions, together with non-core office closures and reductions in controllable overhead costs, will reduce annual operating costs by approximately $150 to $180 million, significantly improving our financial and liquidity positions. We estimate severance costs for the workforce reduction to be in the range of approximately $26 to $29 million.

We currently obtain cash from our general operations, borrowings under credit facilities, including the DIP Facility described below, sale or partial sale of certain assets, and project financings or refinancings. In the past, we have also obtained cash from issuances of debt, equity, trust preferred securities and convertible debentures and contingent convertible notes; proceeds from sale/leaseback transactions; and contract monetizations, and we or our subsidiaries may in the future complete similar transactions. We utilize this cash to fund our operations, service or prepay debt obligations, fund acquisitions, develop and construct power generation facilities, finance capital expenditures, support our hedging, balancing and optimization activities, and meet our other cash and liquidity needs. We reinvest any cash from operations into our business or use it to reduce debt, rather than to pay cash dividends.

DIP Facility.  On January 26, 2006, the U.S. Bankruptcy Court entered a final order approving the $2.0 billion DIP Facility and removing its previously imposed limitation on our ability to borrow thereunder. The DIP Facility, which will remain in place until the earlier of an effective plan of reorganization or December 20, 2007, is comprised of a $1.0 billion revolving credit facility priced at LIBOR plus 225 basis points or base rate plus 125 basis points, a $400 million first-priority term loan priced at LIBOR plus 225 basis points or base rate plus 125 basis points and a $600 million second-priority term loan priced at LIBOR plus 400 basis points or base rate plus 300 basis points. The DIP Facility is secured by first priority liens on all of the unencumbered assets of the U.S. Debtors, including the Geysers Assets, and junior liens on all of their encumbered assets. The proceeds of borrowings and letters of credit issued under the DIP Facility’s revolving credit facility will be used, among other things, for working capital and other general corporate purposes.

The DIP Facility was amended on May 3, 2006, to, among other things, provide us with extensions of time to provide certain financial information to the DIP Facility lenders, including financial statements for the year ended December 31, 2005, and for the quarter ended March 31, 2006. Also in May 2006, the DIP Facility lenders consented to the use of borrowings under the DIP Facility to repay a portion of the First Priority Notes in accordance with the orders of the U.S. Bankruptcy Court. The DIP Facility was further amended on September 25, 2006, to increase the portion of the revolving credit facility that may be used for letters of credit to $375 million from $300 million (to allow for $75 million to be issued on behalf of Non-Debtors), grant the administrative agents the authority to extend the time to deliver financial statements, permit guarantees in connection with certain letters of credit, permit investments in Calpine Greenfield Commercial Trust solely to finance the Greenfield LP in an amount not to exceed $45 million, and permit the establishment of a separate account to hold funds constituting “restricted cash” for the benefit of certain project lessors.

In July 2006, the DIP Facility lenders consented to the assignment of certain PPAs by Broad River Energy, LLC, our subsidiary that leases the Broad River facility pursuant to a leveraged lease, to the owner-lessors of such facility in connection with a settlement agreement with the owner-lessors. The DIP Facility lenders also consented to Broad River’s granting to the owner-lessors a temporary security interest in the same PPAs until FERC approves the assignment. The July 2006 consent was conditioned upon the U.S. Bankruptcy Court’s approval of the settlement agreement with the owner-lessors, and the U.S. Bankruptcy Court approved the settlement agreement on June 27, 2006, and FERC approved the assignment of the PPAs on August 11, 2006.

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As of September 30, 2006, there was $997.4 million outstanding under the term loan facilities, nothing outstanding under the revolving loan facility, and $11.7 million of letters of credit were issued against the revolving credit facility. In May 2006 and June 2006, a portion of the funds drawn under the term loan facilities, together with approximately $409 million of restricted cash, plus accrued interest, were used to repay the remaining outstanding $646.1 million of our First Priority Notes.

Cash Management.  We have received U.S. Bankruptcy Court approval to continue to manage our cash in accordance with our pre-existing intercompany cash management system during the pendency of the Chapter 11 cases. This program allows us to maintain our existing bank and other investment accounts and to continue to manage our cash on an integrated basis through Calpine Corporation. Such cash management systems are subject to the requirements of the DIP Facility, Cash Collateral Order and the 345(b) Waiver Order. Pursuant to the cash management system, and in accordance with our cash collateral requirements in connection with the DIP Facility and relevant U.S. Bankruptcy Court orders, intercompany transfers are generally recorded as intercompany loans. Upon the closing of the DIP Facility, the cash balances of the U.S. Debtors (each of whom is a participant in the cash management system) became subject to security interests in favor of the DIP Facility lenders. The DIP Facility provides that all unrestricted cash of the U.S. Debtors and certain other subsidiaries exceeding a $25 million threshold be maintained in a concentration account at Deutsche Bank Trust Company Americas, one of the DIP Facility agents. In addition, the DIP Facility provides that all unrestricted cash of the U.S. Debtors and certain other subsidiaries, including amounts below the $25 million threshold, be maintained in a concentration account at Deutsche Bank Trust Company Americas, if the agents so elect, upon 90 days prior written notice of the DIP Facility agents.

Rejection of Executory Contracts and Unexpired Leases.  On December 21, 2005, we filed a motion with the U.S. Bankruptcy Court to reject eight PPAs and to enjoin FERC from asserting jurisdiction over the rejections. The U.S. Bankruptcy Court issued a temporary restraining order against FERC and set the matter for a hearing on January 5, 2006. Under most of the PPAs sought to be rejected, we are obligated to sell power at prices that are significantly lower than currently prevailing market prices. On December 29, 2005, certain counterparties to the various PPAs filed an action in the SDNY Court arguing that the U.S. Bankruptcy Court did not have jurisdiction over the dispute. On January 5, 2006, the SDNY Court entered an order that had the effect of transferring our motion seeking to reject the eight PPAs and our related request for an injunction against FERC to the SDNY Court from the U.S. Bankruptcy Court. Earlier, however, on December 19, 2005, CDWR, a counterparty to one of the eight PPAs, had filed a complaint with FERC seeking to obtain injunctive relief to prevent us from rejecting our PPA with CDWR and contending that FERC had exclusive jurisdiction over the matter. On January 3, 2006, FERC determined that it did not have exclusive jurisdiction, and that the matter could be heard by the U.S. Bankruptcy Court. However, despite the FERC ruling, on January 27, 2006, the SDNY Court determined that FERC had jurisdiction over whether the contracts could be rejected. We appealed the SDNY Court’s decision to the United States Court of Appeals for the Second Circuit. The appeal was heard on April 10, 2006 and we have not yet received a decision. We can not determine at this time whether the SDNY Court, the U.S. Bankruptcy Court or FERC will ultimately determine whether we may reject any or all of the eight PPAs, or when such determination will be made. In the meantime, three of the PPAs have been terminated by the applicable counterparties, and three of the PPAs are the subject of negotiated settlements. We continue to perform under the PPAs that remain in effect subject to any modifications agreed to by the parties. We can not presently determine the ultimate outcome of the pending court proceedings nor the market factors that will need to be considered in valuing the rejected contracts and therefore are unable to estimate the expected allowed claims related to these PPAs.

During the course of the Chapter 11 cases, the U.S. Debtors have determined that certain gas transportation and power transmission contracts no longer provide any benefit to the U.S. Debtors or their estates. In certain instances, the U.S. Debtors have given notice to counterparties to these contracts that the U.S. Debtors will no longer accept or pay for service under such contracts. We believe that any claims resulting from the repudiation, rejection, or termination of these contracts will be treated as pre-petition general unsecured claims. Accordingly, we recorded non-cash charges of $96.6 million and $405.4 million for the three and nine months ended September 30, 2006, respectively, as our current estimate of the expected allowed claims related primarily to these contracts. These charges are reported as reorganization items in our Consolidated Condensed Statements of Operations and are included in liabilities subject to compromise in the Consolidated Condensed Balance Sheet at September 30, 2006.

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Cash Flow Activities — The following table summarizes our cash flow activities for the periods indicated (in thousands):

	NineMonthsEndedSeptember30,
	2006			2005
Beginning cash and cash equivalents	$	785,637		$	718,023
Net cash provided by (used in):
Operating activities		166,746			(407,973	)
Investing activities		(46,193	)		822,689
Financing activities		100,237			(308,971	)
Effect of exchange rate changes on cash and cash equivalents, including discontinued operations cash		—			741
Net increase in cash and cash equivalents including discontinued operations cash		220,790			106,486
Change in discontinued operations cash classified as assets held for sale		(17,452	)		18,627
Net increase in cash and cash equivalents	$	203,338		$	125,113
Ending cash and cash equivalents	$	988,975		$	843,136

Cash flows from operating activities have been primarily impacted by improved operating performance, changes in commodity prices, seasonality, the impact of our restructuring activities and fluctuations in our working capital items. Cash flows from operating activities for the nine months ended September 30, 2006, resulted in net inflows of $166.7 million as compared to net outflows of $408.0 million in the same period in 2005. The increase in cash flows from operating activities is primarily driven by the improvement in gross profit, net of non-cash adjustments primarily for depreciation and amortization, to $1,105.6 million in 2006 as compared to $789.7 million in 2005. Also contributing to the increase in cash flows from operating activities were net inflows resulting from a decrease in margin deposits, gas and power prepayment balances and letters of credit supporting commodity transactions of $191.6 million due to the settlement of contracts and a decrease in commodity prices during the nine months ended September 30, 2006, as compared to net outflows of $89.2 million for the same period in 2005 resulting from higher commodity prices during that period. Uses of cash included interest payments of $772.5 million for the nine months ended September 30, 2006, as compared to $962.9 million for the same period in 2005 resulting from the discontinuation of interest payments on debt classified as LSTC, other than certain debt for which interest was paid pursuant to U.S. Bankruptcy Court orders. Partially offsetting these increases in cash flows from operating activities was cash paid for reorganization items, primarily professional fees, of $77.8 million during the nine months ended September 30, 2006, and changes in working capital items, primarily accounts receivable and accounts payable, liabilities subject to compromise and accrued expenses that generated net outflows of $83.5 million during the nine months ended September 30, 2006, as compared to net inflows of $210.8 million for the same period in 2005.

Cash flows from investing activities have been primarily impacted by activities scaled back or undertaken as a result of our Chapter 11 restructuring, such as the curtailment of most of our development and construction activities, and the disposition of certain plants which are considered non-strategic. Although we closed on the sale of fewer assets during the nine months ended September 30, 2006, than the comparable period in the prior year, we have closed on the sale of certain non-strategic assets during the fourth quarter of 2006. Cash flows from investing activities for the nine months ended September 30, 2006, resulted in net outflows of $46.2 million, as compared to net inflows of $822.7 million for the same period in 2005. The decrease in cash flows from investing activities was largely the result of proceeds from asset sales in 2005 of $1,861.0 million from the sale of our natural gas assets, Saltend facility and certain other power projects as compared to $38.0 million from the sale of our interest in Valladolid in 2006. Also contributing to the decrease in cash flows from investing activities was the purchase of the Geysers Assets from the owner lessor in 2006 which used $266.8 million in cash and contributions of $31.0 million to our investment in Greenfield Energy Centre. Cash flow from investing activities also decreased due to net outflows of $95.4 million from derivatives not designated as hedges during the nine months ended September 30, 2006, as compared to net inflows of $45.8 million for the same period in 2005. Partially offsetting these decreases in cash flows from investing activities is the reduction in capital expenditures, including capitalized interest, for the completion of our power facilities from $675.7 million in 2005 to $159.3 million in 2006 as a result of the reduction of our development and construction activities since the Petition Date and a reduction (inflow) in restricted cash of $442.0 million

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for the nine months ended September 30, 2006, as compared to a net increase (outflow) of $559.9 million for the same period in 2005. Upon the sale of our natural gas assets to Rosetta in July 2005, $401.7 million was deposited into a sale proceeds account pursuant to the indentures governing the First Priority Notes resulting in an increase in our restricted cash balance. We applied this restricted cash, plus accrued interest thereon, in 2006 to repurchase the remaining outstanding First Priority Notes. This use of these proceeds is the subject of a lawsuit as described in Note 12 of the Notes to Consolidated Condensed Financial Statements.

Our primary source of cash flows from financing activities is borrowings under our DIP Facility, and to a lesser extent borrowings under our project financings. Our primary uses of cash in financing activities are repayments of borrowings under the DIP Facility and other debt repayments, other than for debt classified as liabilities subject to compromise. Cash flows from financing activities for the nine months ended September 30, 2006, resulted in net inflows of $100.2 million, as compared to net outflows of $309.0 million for the same period in 2005. Sources of cash during the nine months ended September 30, 2006, were borrowings under the DIP Facility of $1,150.0 million and project borrowings of $121.1 million used primarily to fund construction activities at the Freeport and Mankato power plants. During the same period in 2005, we received proceeds of $650.0 million from the issuance of convertible senior notes, $621.0 million from project borrowings, $565.0 million from the issuance of redeemable preferred shares for Calpine Jersey II, Metcalf and CCFCP, and $290.6 million from a prepaid commodity derivative contract at our Deer Park facility. Uses of cash during the nine months ended September 30, 2006 were repayments of $646.1 million for the First Priority Notes, $177.6 million for the DIP Facility, $109.0 million for project borrowings and $173.6 million for notes payable and other lines of credit. During the same period in 2005, we made repayments of $821.3 million for senior notes, $517.5 million for convertible debentures, $176.8 million for project borrowings and $808.8 million for notes payable and lines of credit. In addition, we paid financing fees of $34.4 million in 2006, primarily related to the DIP Facility, as compared to $89.3 million in 2005.

Negative Working Capital — At September 30, 2006, we had negative working capital of $1.9 billion which is primarily due to defaults under certain of our indentures and other financing instruments requiring us to record approximately $3.2 billion of debt as current that otherwise would have been recorded as non-current. Generally, we are seeking waivers or other resolutions with respect to the defaults in the case of Non-Debtor entities. With respect to the Calpine Debtor entities, such obligations may have been accelerated due to such defaults, but generally, all actions to enforce or otherwise effect repayment of liabilities preceding the Petition Date are stayed in accordance with the Bankruptcy Code or orders of the Canadian Court, as applicable, while the Calpine Debtors continue their business operations as debtors-in-possession.

Letter of Credit Facilities — At September 30, 2006, and December 31, 2005, we had $246.9 million and $370.3 million, respectively, in letters of credit outstanding under various credit facilities to support our risk management and other operational and construction activities.

Commodity Margin Deposits and Other Credit Support — As of September 30, 2006, and December 31, 2005, to support commodity transactions, we had margin deposits with third parties of $194.9 million and $287.5 million, respectively; we had gas and power prepayment balances of $89.8 million and $103.2 million, respectively; and had letters of credit outstanding of $2.5 million and $88.1 million, respectively, which are included in the letter of credit facilities discussed above. Counterparties had deposited with us $6.9 million and $27.0 million as margin deposits at September 30, 2006, and December 31, 2005, respectively. We use margin deposits, prepayments and letters of credit as credit support for commodity procurement and risk management activities. Future cash collateral requirements may increase based on the extent of our involvement in standard contracts and movements in commodity prices and also based on our credit ratings and general perception of creditworthiness in this market. While we believe that we have adequate liquidity to support our operations at this time, it is difficult to predict future developments and the amount of credit support that we may need to provide as part of our business operations.

Asset Sales — On March 3, 2006, pursuant to the Cash Collateral Order, we, together with the Committees agreed, in consultation with the indenture trustee for our First Priority Notes, on the designation of nine projects that, absent the consent of such Committees or unless ordered by the U.S. Bankruptcy Court, may not receive funding, other than certain limited amounts that were agreed to by us and the committees in consultation with the First Priority Notes trustee. On May 17, 2006,

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an additional five projects were added to this list. The 14 designated projects are: Acadia Energy Center, Aries Energy Center, Clear Lake Power Plant, Dighton Power Plant, Fox Energy Center, Pryor Power Plant, Newark Power Plant, Parlin Power Plant, Pine Bluff Energy Center, Hog Bayou Energy Center, Rumford Power Plant, Santa Rosa Energy Center, Texas City Power Plant, and Tiverton Power Plant. In accordance with the Cash Collateral Order, it is possible that additional power plants will be added (or certain of the listed plants may be removed) as designated projects.

During or after the nine months ended September 30, 2006, we have taken the following actions with respect to our designated projects:

• On June 23, 2006, we completed the transaction for the rejection of the Rumford and Tiverton leases and the transition of those power plants to a receiver of certain assets of the owner-lessor resulting in a non-cash charge of $234.6 million;

• On September 22, 2006, we entered into an asset purchase agreement with Aquila, Inc. to sell substantially all of the assets related to the Aries project, a 590-MW natural gas-fired facility located in Pleasant Hill, Missouri, for approximately $159 million, subject to competing offers in an auction process approved by the U.S. Bankruptcy Court on October 12, 2006;

• On October 1, 2006, we completed the sale of the Dighton Power Plant, a 170-MW natural gas-fired facility located in Dighton, Massachusetts to BG North America, LLC for approximately $90 million after completing an auction process in the U.S. Bankruptcy Court;

• On October 11, 2006, we completed the sale of our leasehold interest in the Fox Energy Center, a 560-MW natural gas-fired facility located in Kaukauna, Wisconsin, for $16.3 million in cash and the extinguishment of financing obligations of $352.3 million, plus accrued interest.

We have not yet determined what actions we will take with respect to the other power plants; however, it is possible that we could seek to sell our interests in those facilities or, as applicable, reject the related leases. Such actions could result in additional impairment charges that could be material to our financial condition and results of operations in any given period.

In addition to the actions taken with respect to our designated projects, the following activities have also taken place during or after the nine months ended September 30, 2006:

• On April 18, 2006, we completed the sale of our 45% indirect equity interest in the 525-MW Valladolid project to the two remaining partners in the project, Mitsui and Chubu, for $42.9 million, less a 10% holdback and transaction fees. Under the terms of the purchase and sale agreement, we received cash proceeds of $38.6 million at closing. The 10% holdback, plus interest, will be returned to us in one year’s time. We eliminated $87.8 million of non-recourse unconsolidated project debt, representing our 45% share of the total project debt of approximately $195.0 million. In addition, funds held in escrow for credit support of $9.4 million were released to us. We recorded an impairment charge of $41.3 million for our investment in the project during the year ended December 31, 2005; accordingly, no material gain or loss was recognized on this sale.

• On October 2, 2006, we completed the sale of a partial ownership interest in Russell City Energy Company, LLC, a proposed 600-MW natural gas-fired facility to be built in Hayward, California, to ASC after completing an auction process in the U.S. Bankruptcy Court. As part of the transaction, we received approval from the U.S. Bankruptcy Court to transfer the Russell City project assets, which the parties have agreed are valued at approximately $81 million, to a newly formed entity in which we have a 65% ownership interest and ASC has a 35% ownership interest. In exchange for its 35% ownership interest, ASC has agreed to provide approximately $44 million of capital funding and to post an approximately $37 million letter of credit as required under a PPA with PG&E related to the Russell City project. We have the right to reacquire ASC’s 35% interest during the period beginning on the second anniversary and ending on the fifth anniversary of commercial operations of the

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facility. Exercise of the buyout right requires 180 days prior written notice to ASC and payment of an amount necessary to yield a stipulated pre-tax internal rate of return to ASC, calculated using assumptions specified in the transaction agreements.

• We have identified for potential sale 15 turbines, comprising 14 combustion turbines and one steam turbine. The generating capacities of the turbines range from approximately 45 MW to approximately 180 MW. The U.S. Bankruptcy Court approved our sale of one of the combustion turbines for $16.0 million on October 12, 2006, and on October 25, 2006, approved bidding procedures for the sale of four additional combustion turbines for which the outstanding bid is $48.0 million. The sale hearing for the four turbines is currently scheduled for November 15, 2006.

• On November 3, 2006, we entered into an asset purchase agreement with Puget Sound Energy to sell substantially all of the assets of the Goldendale Energy Center, a 271-MW natural gas-fired combined-cycle power plant located in Goldendale, Washington, for approximately $100 million, plus the assumption by Puget Sound Energy of certain liabilities. The sale is subject to U.S. Bankruptcy Court approval of an auction process in which qualified bidders can make competing offers for the project. Closing of the transaction is subject to certain additional conditions including receipt of any required regulatory approvals.

Debt, Lease and Indenture Covenant Compliance — See Note 7 of the Notes to Consolidated Condensed Financial Statements for compliance information.

Unrestricted Subsidiaries — The information in this paragraph is required to be provided under the terms of the Second Priority Secured Debt Instruments. We have designated certain of our subsidiaries as “unrestricted subsidiaries” under the Second Priority Secured Debt Instruments. A subsidiary with “unrestricted” status thereunder generally is not required to comply with the covenants contained therein that are applicable to “restricted subsidiaries.” The Company has designated Calpine Gilroy 1, Inc., Calpine Gilroy 2, Inc. and Calpine Gilroy Cogen, L.P. as “unrestricted subsidiaries” for purposes of the Second Priority Secured Debt Instruments.

The following table sets forth selected balance sheet information of Calpine Corporation and restricted subsidiaries and of such unrestricted subsidiaries at September 30, 2006, and selected income statement information for the nine months ended September 30, 2006 (in thousands):

	Calpine Corporation andRestricted Subsidiaries			Unrestricted Subsidiaries			Eliminations			Total
Assets	$	19,037,875		$	348,570		$	(158,731	)	$	19,227,714
Liabilities not subject to compromise	$	10,533,565		$	200,090		$	—		$	10,733,655
Liabilities subject to compromise	$	15,039,363		$	28,625		$	(28,375	)	$	15,039,613
Total revenue		5,103,890			8,567			(6,512	)		5,105,945
Total cost of revenue		(4,431,156	)		(13,770	)		9,667			(4,435,259	)
Equipment, development project and other impairments		(64,169	)		—			—			(64,169	)
Interest income		52,553			6,889			—			59,442
Interest (expense)		(810,511	)		(9,065	)		—			(819,576	)
Reorganization items		(1,098,593	)		(1	)		—			(1,098,594	)
Other		(153,844	)		515			—			(153,329	)
Net income (loss)	$	(1,401,830	)	$	(6,865	)	$	3,155		$	(1,405,540	)

Special Purpose Subsidiaries — Pursuant to applicable transaction agreements, we have established certain of our entities separate from Calpine and our other subsidiaries. At September 30, 2006, these entities included: Rocky Mountain Energy Center, LLC, Riverside Energy Center, LLC, Calpine Riverside Holdings, LLC, Calpine Energy Management, L.P., CES GP, LLC, PCF, PCF III, Calpine Northbrook Energy Marketing, LLC, CNEM Holdings, LLC, GEC, Calpine Gilroy

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Cogen, L.P., Calpine Gilroy 1, Inc., Calpine King City Cogen, LLC, Calpine Securities Company, L.P. (a parent company of Calpine King City Cogen, LLC), Calpine King City, LLC (an indirect parent company of Calpine Securities Company, L.P.), Calpine Fox Holdings, LLC, Calpine Fox LLC, Calpine Deer Park Partner, LLC, Calpine Deer Park, LLC, Deer Park Energy Center Limited Partnership, CCFC Preferred Holdings, LLC and Metcalf Energy Center, LLC.

Summary of Key Activities for the Three Months Ended September30,2006

Asset Sales:

Date	Description
7/26/06	U.S. Bankruptcy Court approves sale of the 560-MW Fox Energy Center, located in Kaukauna, Wisconsin, for a cash payment of $16.3 million and the extinguishment of financing obligations of $352.3 million, plus accrued interest
9/13/06	U.S. Bankruptcy Court approves sale of the 170-MW Dighton Power Plant, located in Dighton, Massachusetts, to BG North America, LLC for approximately $90 million
9/21/06	U.S. Bankruptcy Court approves sale of 35% equity interest in Russell City Energy Company, LLC to ASC for approximately $44 million of capital funding and the posting of a letter of credit for approximately $37 million
9/22/06	Enter into an asset purchase agreement to sell substantially all of the assets related to the 590-MW Aries Project, located in Pleasant Hill, Missouri, to Aquila, Inc. for approximately $159 million
9/28/06	Complete the sale of our Netherlands-based gas turbine manufacturing deconsolidated subsidiary, TTS, for a contract price of Euro 18.5 million, or approximately US$23.5 million

Power Plant Development and Construction:

Date	Project	Description
7/17/06	Mankato Power Plant	Commercial Operation

California Power Market

The volatility in the California power market from mid-2000 through mid-2001 produced significant unanticipated results. The unresolved issues arising in that market, where 42 of our 93 power plants are located, could adversely affect our performance. See Note 15 of the Notes to Consolidated Condensed Financial Statements for a further discussion.

Recent Regulatory Developments

EPAct 2005.  On October 20, 2006, FERC issued a final rule to implement a provision from EPAct 2005 that provides for termination of an electric utility’s obligation to enter into new power purchase contracts with a QF if FERC makes specific findings about the QF’s access to competitive markets. The order establishes a rebuttable presumption that any utility located in MISO, PJM, New England, New York or ERCOT will be relieved from the must-buy requirement with respect to QFs larger than 20 MW. With respect to other markets, and with respect to all QFs 20 MW or smaller, the utility bears the burden of showing that it qualifies for relief from the must-buy requirement. Any electric utility seeking relief from the must-buy requirements, regardless of location, must apply to FERC for relief. If the must-buy requirement is terminated in an electric utility’s service territory, QFs, state agencies, or others may later petition for reinstatement of the requirement if circumstances change. The final rule goes into effect January 2, 2007. We cannot predict at this time what impact this rule will have on our business.

Market Developments.  On September 21, 2006, FERC issued an order approving the CAISO’s Market Redesign and Technology Upgrade, or MRTU, proposal. The MRTU is a comprehensive redesign of all CAISO operations slated to go into effect November 2007. Under MRTU, the CAISO will run a new integrated day-ahead market for energy and ancillary services as well as a real-time market and an hour-ahead scheduling protocol. Energy prices will be affected and new market power mitigation rules will be implemented. Given the comprehensiveness of the market design, with features that may prove

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to be both positive and negative for energy sellers, we cannot predict at this time what impact MRTU, as approved by FERC, will have on our business.

In addition, the Public Utility Commission of Texas recently adopted rules that will transition the ERCOT power region from a zonal to a nodal market not later than January 1, 2009 (nodal pricing will also be a feature of MRTU). The primary features of a nodal market include a centralized, day-ahead market for energy, nodal transmission congestion management model that results in locational marginal pricing at each generation location, financial congestion hedging instruments and centralized day-ahead commitment process. Given the long lead time to implementation of nodal pricing under the MRTU and in ERCOT, which may include market rule changes not known at this time, we cannot predict the impact on our business.

Climate Change.  Following the February 2005 ratification by numerous countries of the Kyoto Protocol, which requires 35 developed countries to reduce greenhouse gas emissions by approximately 5% between 2008 and 2012, there has been increased attention to climate change in the United States. In 2005, the United States Senate adopted a “sense of the Senate” resolution recommending that the United States Congress enact a comprehensive and effective national program of mandatory, market-based limits and incentives on emissions of greenhouse gases. Although standards have not been developed at the national level, several states are developing state-specific or regional legislative initiatives to reduce greenhouse gas emissions. For example, in California, AB 32 and SB 1368 were signed into law in September 2006. AB 32 creates a statewide cap on greenhouse gas emissions and requires that the state return to 1990 emission levels by 2020; implementation is slated to begin by January 1, 2010. SB 1368 requires the CPUC and the California Energy Commission to develop and adopt by regulation a greenhouse gas emissions performance standard for long-term procurement of electricity by all load-serving entities in the state by mid-2007. Also, beginning in 2009, our facilities in Maine and New York will be subject to the Regional Greenhouse Gas Initiative, which is an agreement between seven northeastern states to stabilize carbon dioxide emissions from power plants at current levels from 2009 to the start of 2015, followed by a 10% reduction in emissions by 2019. The participating states are currently establishing the carbon dioxide allocation process. Because all of these initiatives are in the early stages of implementation, and because it is not possible to determine if and when laws or regulations may be developed at the national level, it is not possible to determine the collective impact climate change initiatives may have on our business.

Financial Market Risks

As we are primarily focused on the generation of electricity using gas-fired turbines, our natural physical commodity position is “short” fuel (i.e., natural gas consumer) and “long” power (i.e., electricity seller). To manage forward exposure to price fluctuation in these and (to a lesser extent) other commodities, we enter into derivative commodity instruments.

The change in fair value of outstanding commodity derivative instruments from January 1, 2006, through September 30, 2006, is summarized in the table below (in thousands):

Fair value of contracts outstanding at January 1, 2006	$	(439,814	)
(Gains) losses recognized or otherwise settled during the period		149,850
Fair value attributable to new contracts		1,063
Changes in fair value attributable to price movements		47,321
Terminated derivatives		9,624
Fair value of contracts outstanding at September 30, 2006(1)	$	(231,956	)

____________

(1) Net commodity derivative liabilities reported in Note 9 of the Notes to Consolidated Condensed Financial Statements.

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The fair value of outstanding derivative commodity instruments at September 30, 2006, based on price source and the period during which the instruments will mature, are summarized in the table below (in thousands):

Fair Value Source	2006			2007-2008			2009-2010			After2010		Total
Prices actively quoted	$	(30,201	)	$	2,292		$	—		$	—	$	(27,909	)
Prices provided by other external sources		(3,055	)		(108,946	)		(70,361	)		—		(182,362	)
Prices based on models and other valuation methods		—			(8,972	)		(12,713	)		—		(21,685	)
Total fair value	$	(33,256	)	$	(115,626	)	$	(83,074	)	$	—	$	(231,956	)

Our risk managers maintain fair value price information derived from various sources in our risk management systems. The propriety of that information is validated by our risk control group. Prices actively quoted include validation with prices sourced from commodities exchanges (e.g., New York Mercantile Exchange). Prices provided by other external sources include quotes from commodity brokers and electronic trading platforms. Prices based on models and other valuation methods are validated using quantitative methods.

The counterparty credit quality associated with the fair value of outstanding derivative commodity instruments at September 30, 2006, and the period during which the instruments will mature are summarized in the table below (in thousands):

Credit Quality (BasedonStandard& Poor’sRatingsasof September30,2006)	2006			2007-2008			2009-2010			After2010		Total
Investment grade	$	(34,911	)	$	(115,202	)	$	(83,074	)	$	—	$	(233,187	)
Non-investment grade		(1,338	)		(424	)		—			—		(1,762	)
No external ratings		2,993			—			—			—		2,993
Total fair value	$	(33,256	)	$	(115,626	)	$	(83,074	)	$	—	$	(231,956	)

The fair value of outstanding derivative commodity instruments and the fair value that would be expected after a ten percent adverse price change are shown in the table below (in thousands):

	FairValue			Fair Value After 10%Adverse PriceChange
At September 30, 2006:
Electricity	$	(209,155	)	$	(330,491	)
Natural gas		(22,801	)		(42,932	)
Total	$	(231,956	)	$	(373,423	)

Derivative commodity instruments included in the table are those included in Note 9 of the Notes to Consolidated Condensed Financial Statements. The fair value of derivative commodity instruments included in the table is based on present value adjusted quoted market prices of comparable contracts. The fair value of electricity derivative commodity instruments after a 10% adverse price change includes the effect of increased power prices versus our derivative forward commitments. Conversely, the fair value of the natural gas derivatives after a 10% adverse price change reflects a general decline in gas prices versus our derivative forward commitments. Derivative commodity instruments offset the price risk exposure of our physical assets. None of the offsetting physical positions are included in the table above.

Price changes were calculated by assuming an across-the-board ten percent adverse price change regardless of term or historical relationship between the contract price of an instrument and the underlying commodity price. In the event of an actual ten percent change in prices, the fair value of our derivative portfolio would typically change by more than ten percent

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for earlier forward months and less than ten percent for later forward months because of the higher volatilities in the near term and the effects of discounting expected future cash flows.

Interest Rate Swaps — From time to time, we use interest rate swap agreements to mitigate our exposure to interest rate fluctuations associated with certain of our debt instruments and to adjust the mix between fixed and floating rate debt in our capital structure to desired levels. We do not use interest rate swap agreements for speculative or trading purposes. The following tables summarize the fair market values of our existing interest rate swap agreements as of September 30, 2006 (dollars in thousands):

Variable to Fixed Interest Rate Swaps

Maturity Date	Notional Principal Amount		WeightedAverage Interest Rate (Pay)		WeightedAverage Interest Rate (Receive)		FairMarket Value
2007	$	53,241		4.5%		3-month US$LIBOR	$	778
2007		282,179		4.5%		3-month US$LIBOR		3,943
2009		36,769		4.4%		3-month US$LIBOR		586
2009		184,483		4.4%		3-month US$LIBOR		2,938
2009		50,000		4.8%		3-month US$LIBOR		267
2011		50,300		4.9%		3-month US$LIBOR		278
2011		43,000		4.8%		3-month US$LIBOR		296
2011		21,500		4.8%		3-month US$LIBOR		148
2011		25,150		4.9%		3-month US$LIBOR		139
2011		25,150		4.9%		3-month US$LIBOR		139
2011		21,500		4.8%		3-month US$LIBOR		148
2011		25,150		4.9%		3-month US$LIBOR		139
2011		21,500		4.8%		3-month US$LIBOR		148
2012		92,673		6.5%		3-month US$LIBOR		(4,760	)
	$	932,595					$	5,187

Certain of our interest rate swaps were designated as cash flow hedges of debt instruments that became subject to compromise as a result of our Chapter 11 filings beginning on the Petition Date. Consequently, such interest rate swaps no longer were effective hedges and we began to recognize changes in their fair value through earnings rather than through OCI.

The fair value of outstanding interest rate swaps and the fair value that would be expected after a one percent (100 basis points) adverse interest rate change are shown in the table below (in thousands). Given our net variable to fixed portfolio position, a 100 basis point decrease would adversely impact our portfolio as follows:

Net Fair Value as of September30,2006	Fair Value After a 1.0% (100BasisPoints)Adverse Interest Rate Change
$5,187	$	(21,819	)

Variable Rate Debt Financing — We have used debt financing to meet the significant capital requirements needed to fund our growth. Certain debt instruments related to our non-debtor entities and debt instruments not considered subject to compromise at September 30, 2006, may affect us adversely because of changes in market conditions. Our variable rate financings are indexed to base rates, generally LIBOR, as shown below. Significant LIBOR increases could have a negative impact on our future interest expense.

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The following table summarizes our variable-rate debt, by repayment year, exposed to interest rate risk as of September 30, 2006. All outstanding balances and fair market values are shown net of applicable premium or discount, if any (in thousands):

	October- December 2006		2007		2008		2009		2010		Thereafter		FairValue Sept.30, 2006
3-month US$LIBOR weighted average interest rate basis(3)
Riverside Energy Center project financing	$	—	$	3,685	$	3,685	$	3,685	$	3,685	$	336,868	$	351,608
Rocky Mountain Energy Center project financing		—		2,649		2,649		2,649		2,649		232,176		242,772
Total of 3-month US$LIBOR rate debt		—		6,334		6,334		6,334		6,334		569,044		594,380
1-month US$LIBOR interest rate basis (3)
Freeport Energy Center, LP project financing		—		3,398		3,123		2,761		3,005		207,629		219,916
Mankato Energy Center, LLC project financing		—		3,107		3,205		2,754		2,545		199,903		211,514
Total of 1-month US$LIBOR interest rate		—		6,505		6,328		5,515		5,550		407,532		431,430
(1)(3)
Metcalf Energy Center, LLC preferred interest		—		—		—		—		155,000		—		155,000
Third Priority Secured Floating Rate Notes Due 2011 (CalGen)		—		—		—		—		—		680,000		727,600
Second Priority Senior Secured Floating Rate Notes Due 2011 (CCFC)		—		—		—		—		—		410,267		410,267
CCFC Preferred Holdings, LLC preferred interest		—		—		—		—		—		300,000		300,000
Total of variable rate debt as defined at (1) below		—		—		—		—		155,000		1,390,267		1,592,867
(2)(3)
Blue Spruce Energy Center project financing		938		3,750		3,750		3,750		3,750		44,645		60,583
Total of variable rate debt as defined at (2) below		938		3,750		3,750		3,750		3,750		44,645		60,583
(4)(3)
First Priority Secured Floating Rate Notes Due 2009 (CalGen)		—		1,175		2,350		231,475		—		—		239,700
First Priority Secured Institutional Term Loans Due 2009 (CalGen)		—		3,000		6,000		591,000		—		—		600,000
First Priority Senior Secured Institutional Term Loan Due 2009 (CCFC)		—		3,208		3,208		365,189		—		—		371,605
Second Priority Secured Institutional Floating Rate Notes Due 2010 (CalGen)		—		—		3,200		6,400		624,839		—		668,800
Second Priority Secured Term Loans Due 2010 (CalGen)		—		—		500		1,000		97,631		—		99,131
Metcalf Energy Center, LLC project financing		—		—		—		—		100,000		—		100,000
DIP First Priority Term Loan		875		396,500		—		—		—		—		397,375
DIP Second Priority Term Loan		—		600,000		—		—		—		—		600,000
Total of variable rate debt as defined at (4) below		875		1,003,883		15,258		1,195,064		822,470		—		3,076,611
(5)(4)
Contra Costa		—		168		179		190		202		1,217		1,956
Total of variable rate debt as defined at (5) below		—		168		179		190		202		1,217		1,956

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	October- December 2006		2007		2008		2009		2010		Thereafter		FairValue Sept.30, 2006
(6)(3)
First Priority Secured Revolving Loan		—		112,258		—		—		—		—		112,258
Total of variable rate debt as defined at (6) below		—		112,258		—		—		—		—		112,258
Grand total variable-rate debt instruments	$	1,813	$	1,132,898	$	31,849	$	1,210,853	$	993,306	$	2,412,705	$	5,870,085

____________

(1) British Bankers Association LIBOR Rate for deposit in U.S. dollars for a period of six months.

(2) British Bankers Association LIBOR Rate for deposit in U.S. dollars for a period of three months.

(3) Actual interest rates include a spread over the basis amount.

(4) Choice of 1-month US$LIBOR, 2-month US$LIBOR, 3-month US$LIBOR, 6-month US$LIBOR, 12-month US$LIBOR or a base rate.

(5) Bankers Acceptance Rate.

(6) Choice of 1-month US$LIBOR, 2-month US$LIBOR, 3-month US$LIBOR, 6-month US$LIBOR or a base rate.

Recent Accounting Pronouncements

See Note 1 of the Notes to Consolidated Condensed Financial Statements for a discussion of recent accounting pronouncements.

Item 3.Quantitative and Qualitative Disclosures About Market Risk.

See “Financial Market Risks” in Item 2.

Item 4.Controls and Procedures.

Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

As of December 31, 2005, management identified a material weakness related to the controls over accounting for income taxes that was discussed in Item 9A. of our 2005 Form 10-K. During 2006, we have taken steps necessary to begin the remediation of this material weakness.

Our senior management, including our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q. Because the process of remediating the aforementioned material weakness is not complete, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures are not effective. We continue to perform additional analysis and post-closing procedures to ensure our consolidated financial statements are prepared and presented in accordance with GAAP. Accordingly, management believes that the financial statements included in this Report fairly present in all material respects our financial condition, results of operations and cash flows for the periods presented. The certificates required by this item are filed as Exhibits 31.1 and 31.2 to this Form 10-Q.

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Status of Remediation of the Material Weakness

As of the third quarter of 2006, we have taken steps necessary to improve our internal controls relating to the preparation and review of interim and annual income tax provisions, specifically related to the timely reconciliation of the underlying data being provided by the accounting department to the tax department to ensure the accuracy and validity of such information for purposes of our tax calculations, principally relating to the book and tax basis of our property, plant and equipment.

We will continue to monitor the effectiveness of the tax controls and procedures and will make any additional changes that management deems appropriate. The performance and testing of these controls has commenced and will continue throughout the balance of the year. Following the completion of testing, management will evaluate whether this material weakness has been successfully remediated.

Changes in Internal Control Over Financial Reporting

During the third quarter of 2006, there were no significant changes in our internal control over financial reporting that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II — OTHER INFORMATION

Item 1.Legal Proceedings.

See Note 12 of the Notes to Consolidated Condensed Financial Statements for a description of our legal proceedings.

Item 3.Defaults Upon Senior Securities.

See Note 7 of the Notes to Consolidated Condensed Financial Statements for a description of defaults under our indebtedness, as well as our Current Report on Form 8-K filed on December 23, 2005.

See also Note 8 of the Notes to Consolidated Condensed Financial Statements for our liabilities subject to compromise, which sets forth the amounts of our indebtedness classified as LSTC. We are no longer paying current interest on any LSTC other than pursuant to applicable U.S. Bankruptcy Court orders (for example, pursuant to an order of the U.S. Bankruptcy Court, we paid current interest on the Second Priority Debt until June 30, 2006). That order provides that the Second Priority Debt must seek further orders from the U.S. Bankruptcy Court for any further interest to be paid. We continue to make current payments of interest and, if applicable, principal on all debt of Non-U.S. Debtor entities, including debt under which there are defaults.

Item 6.Exhibits.

The following exhibits are filed herewith unless otherwise indicated:

EXHIBIT INDEX

Exhibit
Number	Description
3.1.1	Amended and Restated Certificate of Incorporation of the Company, as amended through June 2, 2004 (incorporated by reference to Exhibit 3.1 to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 2004, filed with the SEC on August 9, 2004).
3.1.2	Amendment to Amended and Restated Certificate of Incorporation of the Company, dated June 20, 2005 (incorporated by reference to Exhibit 3.1.2 to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 2005, filed with the SEC on August 9, 2005).
3.2	Amended and Restated By-laws of the Company (incorporated by reference to Exhibit 3.1.8 to Calpine Corporation’s Annual Report on Form 10-K dated December 31, 2001, filed with the SEC on March 29, 2002).
4.1.1	Indenture, dated as of August 14, 2003, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee, including form of Notes (incorporated by reference to Exhibit 4.4 to Calpine Corporation’s Quarterly Report on Form 10-Q dated September 30, 2003, filed with the SEC on November 13, 2003).
4.1.2	Supplemental Indenture, dated as of September 18, 2003, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee (incorporated by reference to Exhibit 4.5 to Calpine Corporation’s Quarterly Report on Form 10-Q dated September 30, 2003, filed with the SEC on November 13, 2003).

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Index  Definitions

Exhibit
Number	Description
4.1.3	Second Supplemental Indenture, dated as of January 14, 2004, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee (incorporated by reference to Exhibit 4.14.3 to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2003, filed with the SEC on March 25, 2004).
4.1.4	Third Supplemental Indenture, dated as of March 5, 2004, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee (incorporated by reference to Exhibit 4.14.4 to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2003, filed with the SEC on March 25, 2004).
4.1.5	Fourth Supplemental Indenture, dated as of March 15, 2006, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee (incorporated by reference to Exhibit 4.13.5 to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on May 19, 2006).
4.1.6	Fifth Supplemental Indenture, dated as of August 25, 2006, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee.(*)
4.1.7	Waiver Agreement, dated as of March 15, 2006, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee (incorporated by reference to Exhibit 4.13.6 to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on May 19, 2006).
4.1.8	Waiver Agreement, dated as of June 9, 2006, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee (incorporated by reference to Exhibit 4.1.7 to Calpine Corporation’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006, filed with the SEC on July 3, 2006).
4.1.9	Amendment to Waiver Agreement, dated as of August 4, 2006, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee (incorporated by reference to Exhibit 4.1.8 to Calpine Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, filed with the SEC on August 14, 2006).
4.1.10	Second Amendment to Waiver Agreement, dated as of August 11, 2006, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee (incorporated by reference to Exhibit 4.1.9 to Calpine Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, filed with the SEC on August 14, 2006).

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Index  Definitions

Exhibit
Number	Description
4.2.1	Second Amended and Restated Limited Liability Company Operating Agreement of CCFC Preferred Holdings, LLC, dated as of October 14, 2005, containing terms of its 6-Year Redeemable Preferred Shares Due 2011 (incorporated by reference to Exhibit 4.21.1 to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on May 19, 2006).
4.2.2	Consent, Acknowledgment and Amendment, dated as of March 15, 2006, among Calpine CCFC Holdings, Inc. and the Redeemable Preferred Members party thereto (incorporated by reference to Exhibit 4.21.2 to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on May 19, 2006).
4.2.3	Amendment to Second Amended and Restated Limited Liability Company Operating Agreement of CCFC Preferred Holdings, LLC, dated as of October 24, 2006, among Calpine CCFC Holdings, Inc., in its capacity as Common Member, and the Redeemable Preferred Members party thereto.(*)
10.1	DIP Financing Agreements.
10.1.1.1	$2,000,000,000 Amended & Restated Revolving Credit, Term Loan and Guarantee Agreement, dated as of February 23, 2006, among the Company, as borrower, the subsidiaries of the Company named therein, as guarantors, the Lenders from time to time party thereto, Credit Suisse Securities (USA) LLC and Deutsche Bank Trust Company Americas, as Joint Syndication Agents, Deutsche Bank Securities Inc. and Credit Suisse Securities (USA) LLC, as Joint Lead Arrangers and Joint Bookrunners, and Credit Suisse and Deutsche Bank Trust Company Americas, as Joint Administrative Agents (incorporated by reference to Exhibit 10.1.1.1 to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on May 19, 2006).
10.1.1.2	First Consent, Waiver and Amendment, dated as of May 3, 2006, to and under the Amended and Restated Revolving Credit, Term Loan and Guarantee Agreement, dated as of February 23, 2006, among Calpine Corporation, as borrower, its subsidiaries named therein, as guarantors, the Lenders party thereto, Deutsche Bank Trust Company Americas, as administrative agent for the First Priority Lenders, Credit Suisse, Cayman Islands Branch, as administrative agent for the Second Priority Term Lenders (incorporated by reference to Exhibit 10.1.1.2 to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on May 19, 2006).
10.1.1.3	Consent, dated as of June 28, 2006, under the Amended and Restated Revolving Credit, Term Loan and Guarantee Agreement, dated as of February 23, 2006, among Calpine Corporation, as borrower, its subsidiaries named therein, as guarantors, the Lenders party thereto, Deutsche Bank Trust Company Americas, as administrative agent for the First Priority Lenders, Credit Suisse, Cayman Islands Branch, as administrative agent for the Second Priority Term Lenders (incorporated by reference to Exhibit 10.2.1.3 to Calpine Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, filed with the SEC on August 14, 2006).

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Index  Definitions

Exhibit
Number	Description
10.1.1.4	Second Amendment, dated as of September 25, 2006, to the Amended and Restated Revolving Credit, Term Loan and Guarantee Agreement, dated as of February 23, 2006, among Calpine Corporation, as borrower, its subsidiaries named therein, as guarantors, the Lenders party thereto, Deutsche Bank Trust Company Americas, as administrative agent for the First Priority Lenders, and Credit Suisse, Cayman Islands Branch, as administrative agent for the Second Priority Term Lenders.(*)
10.1.1.5	Letter Agreement, dated as of October 18, 2006, relating to the Amended and Restated Revolving Credit, Term Loan and Guarantee Agreement, dated as of February 23, 2006, among Calpine Corporation, as borrower, its subsidiaries named therein, as guarantors, the Lenders party thereto, Deutsche Bank Trust Company Americas, as administrative agent for the First Priority Lenders, and Credit Suisse, Cayman Islands Branch, as administrative agent for the Second Priority Term Lenders.(*)
10.2	Financing and Term Loan Agreements.
10.2.1.3	Amendment No. 2 to the Credit and Guarantee Agreement, dated as of January 13, 2004, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger (incorporated by reference to Exhibit 10.2.2.3 to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2003, filed with the SEC on March 25, 2004).
10.2.1.4	Amendment No. 3 to the Credit and Guarantee Agreement, dated as of March 5, 2004, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger (incorporated by reference to Exhibit 10.2.2.4 to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2003, filed with the SEC on March 25, 2004).
10.2.1.5	Amendment No. 4 to the Credit and Guarantee Agreement, dated as of March 15, 2006, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger (incorporated by reference to Exhibit 10.2.6.5 to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on May 19, 2006).
10.2.1.6	Amendment No. 5 to the Credit and Guarantee Agreement, dated as of August 25, 2006, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(*)

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Index  Definitions

Exhibit
Number	Description
10.2.1.7	Waiver Agreement, dated as of March 15, 2006 among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger (incorporated by reference to Exhibit 10.2.6.6 to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on May 19, 2006).
10.2.1.8	Waiver Agreement, dated as of June 9, 2006, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger (incorporated by reference to Exhibit 10.2.1.7 to Calpine Corporation’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006, filed with the SEC on July 3, 2006).
10.2.1.9	Amendment to Waiver Agreement, dated as of August 4, 2006, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger (incorporated by reference to Exhibit 10.2.1.8 to Calpine Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, filed with the SEC on August 14, 2006).
10.2.1.10	Second Amendment to Waiver Agreement, dated as of August 11, 2006, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger (incorporated by reference to Exhibit 10.2.1.9 to Calpine Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, filed with the SEC on August 14, 2006).
10.5.15	Summary of Calpine Corporation Incentive Program (management contract or compensatory plan or arrangement).(*)
31.1	Certification of the Chief Executive Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(*)
31.2	Certification of the Chief Financial Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(*)
32.1	Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.(*)

____________

(*) Filed herewith.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

CALPINE CORPORATION

	By:	/s/ LISA DONAHUE
		Lisa Donahue
		Chief Financial Officer
Date:  November 9, 2006
	By:	/s/ CHARLES B. CLARK, JR.
		Charles B. Clark, Jr.
		Senior Vice President,
		Corporate Controller and
		Chief Accounting Officer
Date:  November 9, 2006

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Index  Definitions

The following exhibits are filed herewith unless otherwise indicated:

EXHIBIT INDEX

Exhibit
Number	Description
3.1.1	Amended and Restated Certificate of Incorporation of the Company, as amended through June 2, 2004 (incorporated by reference to Exhibit 3.1 to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 2004, filed with the SEC on August 9, 2004).
3.1.2	Amendment to Amended and Restated Certificate of Incorporation of the Company, dated June 20, 2005 (incorporated by reference to Exhibit 3.1.2 to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 2005, filed with the SEC on August 9, 2005).
3.2	Amended and Restated By-laws of the Company (incorporated by reference to Exhibit 3.1.8 to Calpine Corporation’s Annual Report on Form 10-K dated December 31, 2001, filed with the SEC on March 29, 2002).
4.1.1	Indenture, dated as of August 14, 2003, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee, including form of Notes (incorporated by reference to Exhibit 4.4 to Calpine Corporation’s Quarterly Report on Form 10-Q dated September 30, 2003, filed with the SEC on November 13, 2003).
4.1.2	Supplemental Indenture, dated as of September 18, 2003, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee (incorporated by reference to Exhibit 4.5 to Calpine Corporation’s Quarterly Report on Form 10-Q dated September 30, 2003, filed with the SEC on November 13, 2003).
4.1.3	Second Supplemental Indenture, dated as of January 14, 2004, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee (incorporated by reference to Exhibit 4.14.3 to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2003, filed with the SEC on March 25, 2004).
4.1.4	Third Supplemental Indenture, dated as of March 5, 2004, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee (incorporated by reference to Exhibit 4.14.4 to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2003, filed with the SEC on March 25, 2004).
4.1.5	Fourth Supplemental Indenture, dated as of March 15, 2006, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee (incorporated by reference to Exhibit 4.13.5 to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on May 19, 2006).

71

Index  Definitions

Exhibit
Number	Description
4.1.6	Fifth Supplemental Indenture, dated as of August 25, 2006, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee.(*)
4.1.7	Waiver Agreement, dated as of March 15, 2006, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee (incorporated by reference to Exhibit 4.13.6 to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on May 19, 2006).
4.1.8	Waiver Agreement, dated as of June 9, 2006, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee (incorporated by reference to Exhibit 4.1.7 to Calpine Corporation’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006, filed with the SEC on July 3, 2006).
4.1.9	Amendment to Waiver Agreement, dated as of August 4, 2006, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee (incorporated by reference to Exhibit 4.1.8 to Calpine Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, filed with the SEC on August 14, 2006).
4.1.10	Second Amendment to Waiver Agreement, dated as of August 11, 2006, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee (incorporated by reference to Exhibit 4.1.9 to Calpine Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, filed with the SEC on August 14, 2006).
4.2.1	Second Amended and Restated Limited Liability Company Operating Agreement of CCFC Preferred Holdings, LLC, dated as of October 14, 2005, containing terms of its 6-Year Redeemable Preferred Shares Due 2011 (incorporated by reference to Exhibit 4.21.1 to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on May 19, 2006).
4.2.2	Consent, Acknowledgment and Amendment, dated as of March 15, 2006, among Calpine CCFC Holdings, Inc. and the Redeemable Preferred Members party thereto (incorporated by reference to Exhibit 4.21.2 to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on May 19, 2006).
4.2.3	Amendment to Second Amended and Restated Limited Liability Company Operating Agreement of CCFC Preferred Holdings, LLC, dated as of October 24, 2006, among Calpine CCFC Holdings, Inc., in its capacity as Common Member, and the Redeemable Preferred Members party thereto.(*)

72

Index  Definitions

Exhibit
Number	Description
10.1	DIP Financing Agreements.
10.1.1.1	$2,000,000,000 Amended & Restated Revolving Credit, Term Loan and Guarantee Agreement, dated as of February 23, 2006, among the Company, as borrower, the subsidiaries of the Company named therein, as guarantors, the Lenders from time to time party thereto, Credit Suisse Securities (USA) LLC and Deutsche Bank Trust Company Americas, as Joint Syndication Agents, Deutsche Bank Securities Inc. and Credit Suisse Securities (USA) LLC, as Joint Lead Arrangers and Joint Bookrunners, and Credit Suisse and Deutsche Bank Trust Company Americas, as Joint Administrative Agents (incorporated by reference to Exhibit 10.1.1.1 to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on May 19, 2006).
10.1.1.2	First Consent, Waiver and Amendment, dated as of May 3, 2006, to and under the Amended and Restated Revolving Credit, Term Loan and Guarantee Agreement, dated as of February 23, 2006, among Calpine Corporation, as borrower, its subsidiaries named therein, as guarantors, the Lenders party thereto, Deutsche Bank Trust Company Americas, as administrative agent for the First Priority Lenders, Credit Suisse, Cayman Islands Branch, as administrative agent for the Second Priority Term Lenders (incorporated by reference to Exhibit 10.1.1.2 to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on May 19, 2006).
10.1.1.3	Consent, dated as of June 28, 2006, under the Amended and Restated Revolving Credit, Term Loan and Guarantee Agreement, dated as of February 23, 2006, among Calpine Corporation, as borrower, its subsidiaries named therein, as guarantors, the Lenders party thereto, Deutsche Bank Trust Company Americas, as administrative agent for the First Priority Lenders, Credit Suisse, Cayman Islands Branch, as administrative agent for the Second Priority Term Lenders (incorporated by reference to Exhibit 10.2.1.3 to Calpine Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, filed with the SEC on August 14, 2006).
10.1.1.4	Second Amendment, dated as of September 25, 2006, to the Amended and Restated Revolving Credit, Term Loan and Guarantee Agreement, dated as of February 23, 2006, among Calpine Corporation, as borrower, its subsidiaries named therein, as guarantors, the Lenders party thereto, Deutsche Bank Trust Company Americas, as administrative agent for the First Priority Lenders, and Credit Suisse, Cayman Islands Branch, as administrative agent for the Second Priority Term Lenders.(*)
10.1.1.5	Letter Agreement, dated as of October 18, 2006, relating to the Amended and Restated Revolving Credit, Term Loan and Guarantee Agreement, dated as of February 23, 2006, among Calpine Corporation, as borrower, its subsidiaries named therein, as guarantors, the Lenders party thereto, Deutsche Bank Trust Company Americas, as administrative agent for the First Priority Lenders, and Credit Suisse, Cayman Islands Branch, as administrative agent for the Second Priority Term Lenders.(*)

73

Index  Definitions

Exhibit
Number	Description
10.2	Financing and Term Loan Agreements.
10.2.1.3	Amendment No. 2 to the Credit and Guarantee Agreement, dated as of January 13, 2004, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger (incorporated by reference to Exhibit 10.2.2.3 to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2003, filed with the SEC on March 25, 2004).
10.2.1.4	Amendment No. 3 to the Credit and Guarantee Agreement, dated as of March 5, 2004, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger (incorporated by reference to Exhibit 10.2.2.4 to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2003, filed with the SEC on March 25, 2004).
10.2.1.5	Amendment No. 4 to the Credit and Guarantee Agreement, dated as of March 15, 2006, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger (incorporated by reference to Exhibit 10.2.6.5 to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on May 19, 2006).
10.2.1.6	Amendment No. 5 to the Credit and Guarantee Agreement, dated as of August 25, 2006, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(*)
10.2.1.7	Waiver Agreement, dated as of March 15, 2006 among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger (incorporated by reference to Exhibit 10.2.6.6 to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on May 19, 2006).
10.2.1.8	Waiver Agreement, dated as of June 9, 2006, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger (incorporated by reference to Exhibit 10.2.1.7 to Calpine Corporation’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006, filed with the SEC on July 3, 2006).

74

Index  Definitions

Exhibit
Number	Description
10.2.1.9	Amendment to Waiver Agreement, dated as of August 4, 2006, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger (incorporated by reference to Exhibit 10.2.1.8 to Calpine Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, filed with the SEC on August 14, 2006).
10.2.1.10	Second Amendment to Waiver Agreement, dated as of August 11, 2006, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger (incorporated by reference to Exhibit 10.2.1.9 to Calpine Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, filed with the SEC on August 14, 2006).
10.5.15	Summary of Calpine Corporation Incentive Program (management contract or compensatory plan or arrangement).(*)
31.1	Certification of the Chief Executive Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(*)
31.2	Certification of the Chief Financial Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(*)
32.1	Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.(*)

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(*) Filed herewith.

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