UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_______________

Form 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~June~~September 30, 2006

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file numbers:

333-117335

333-117335-40

_______________

Calpine Generating Company, LLC

(A Delaware Limited Liability Company)

CalGen Finance Corp.

(A Delaware Corporation)

I.R.S. Employer Identification Nos.

77-0555128

20-1162632

50 West San Fernando Street, San Jose, California 95113

717 Texas Avenue, Houston, Texas 77002

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. o Yes x 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 o Accelerated filer o Non-accelerated filer x

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:

Calpine Generating Company, LLC is a single member limited liability company and has no common stock.

With respect to CalGen Finance Corp., 1,000 shares of common stock, par value $1, were outstanding as of the date hereof.

Definitions

CALPINE GENERATING COMPANY, LLC

(a wholly owned subsidiary of Calpine Corporation)

REPORT ON FORM 10-Q

For the Quarter Ended ~~June~~September 30, 2006

TABLE OF CONTENTS

INDEX
						Page
PART I — FINANCIAL INFORMATION
	Item 1.		Financial Statements
				Consolidated Condensed Balance Sheets June 30, 2006, and December 31, 2005		1
				Consolidated Condensed Balance Sheets September 30, 2006, and December 31, 2005		1
				Consolidated Condensed Statements of Operations for the Three and Six Months Ended June 30, 2006 and 2005		2
				Consolidated Condensed Statements of Operations for the Three and Six Months Ended September 30, 2006 and 2005		2
				Consolidated Condensed Statements of Cash Flows for the Six Months Ended June 30, 2006 and 2005		3
				Consolidated Condensed Statements of Cash Flows for the Six Months Ended September 30, 2006 and 2005		3
				Notes to Consolidated Condensed Financial Statements		5
			1.		Basis of Interim Presentation and Summary of Significant Accounting Policies	5
			2.		Chapter 11 Cases and Going Concern	7
			3.		Restatement	11
			4.		Property, Plant and Equipment, Net	13
			5.		Debt	14
			6.		Liabilities Subject to Compromise	16
			7.		Significant Customers	16
			8.		Related Party Transactions	17
			9.		Derivative Instruments	18
			10.		Commitments and Contingencies	18
			11.		Guarantor Subsidiaries – Supplemental Consolidating Financial Statements	21
	Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			30
				Overview		30
				Restatement		32
				Results of Operations		33
				Liquidity and Capital Resources		36
				Performance Metrics		42
				Financial Market Risks		45
				Recent Accounting Pronouncements		47
				Recent Regulatory Developments		47
	Item 3.		Quantitative and Qualitative Disclosures About Market Risk			48
	Item 4.		Controls and Procedures			48
PART II — OTHER INFORMATION
		Item 1.	Legal Proceedings			50
		Item 3.	Defaults Upon Senior Securities			50
		Item 6.	Exhibits			50
Signatures						52

Index

DEFINITIONS

As used in this Report the abbreviations contained herein have the meanings set forth below. Additionally, the terms, the “Company,” “CalGen,” “we,” “us” and “our” refer to Calpine Generating Company, LLC and its subsidiaries, unless the context clearly indicates otherwise. Unless 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 the filing of this Report.

ABBREVIATION		DEFINITION
1933 Act		Securities Act of 1933, as amended
1934 Act		Securities Exchange Act of 1934, as amended
2004 Refinancing		Refinancing of the Construction Facility, consummated on March 23, 2004, in which CalGen issued the Notes and Term Loans and entered into the Revolving Credit Facility
2005 Form 10-K		Annual Report of CalGen on Form 10-K for the year ended December 31, 2005, filed with the SEC on September 29, 2006
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
Bankruptcy Code		United States Bankruptcy Code
Bankruptcy Court		United States Bankruptcy Court for the Southern District of New York
Btu		British thermal units
CAISO		California Independent System Operator
CalGen Debtors		CalGen and each of its subsidiaries that filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court
CalGen Holdings		Calpine CalGen Holdings, Inc.
CalGen Secured Debt		$235,000,000 First Priority Secured Floating Rate Notes Due 2009, issued by CalGen and CalGen Finance; $600,000,000 First Priority Secured Institutional Term Loans Due 2009, issued by CalGen; the $200,000,000 Revolving Credit Facility; $640,000,000 Second Priority Secured Floating Rate Notes Due 2010, issued by CalGen and CalGen Finance; $100,000,000 Second Priority Secured Term Loans Due 2010, issued by CalGen; $680,000,000 Third Priority Secured Floating Rate Notes Due 2011 issued by CalGen and CalGen Finance; and $150,000,000 11.5% Third Priority Secured Notes Due 2011, issued by CalGen and CalGen Finance.
Calpine or Parent		Calpine Corporation
CASCI		Calpine Administrative Services Company, Inc.
Cash Collateral Order		Second Amended Final Order of the Bankruptcy Court Authorizing Use of Cash Collateral and Granting Adequate Protection, dated February 24, 2006, as modified by orders entered by the Bankruptcy Court on June 21, 2006, July 12, 2006, October 25, 2006, ~~November 15, 2006,~~ December 20, 2006, December 28, 2006, and January 18, 2007

Index

ABBREVIATION		DEFINITION

CCFC II		Calpine Construction Finance Company II, LLC, which was renamed Calpine Generating Company, LLC (referred to herein as CalGen) in connection with the 2004 Refinancing

CES		Calpine Energy Services, L.P.

Chapter 11		Chapter 11 of the Bankruptcy Code

Construction Facility		$2.5 billion Credit Agreement, dated as of October 16, 2000, among CCFC II, as borrower, the lenders from time to time party thereto, The Bank of Nova Scotia, as lead arranger, co-syndication agent and bookrunner, Credit Suisse First Boston, acting through its New York Branch, as lead arranger and administrative agent, Banc of America Securities LLC, and ING (U.S.) Capital LLC, as arrangers and co-syndication agents, Bayerische Landesbank Girozentrale, as arranger, co-documentation agent and LC bank, and CIBC World Markets Corp., Dresdner Kleinword Benson North America Services LLC, and TD Securities (USA) Inc., as arrangers and co-documentation agents

COSCI		Calpine Operating Services Company, Inc.

Debtors		Calpine Corporation and each of its subsidiaries, including the CalGen Debtors, that have filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court

Decatur		Decatur Energy Center, LLC

DIP Facility		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

EITF		Emerging Issues Task Force

ERCOT		Electric Reliability Council of Texas

FASB		Financial Accounting Standards Board

FERC		Federal Energy Regulatory Commission

FIN 45		FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others—an Interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34”

iii

Index

ABBREVIATION		DEFINITION

FIN 46		FASB Interpretation No. 46, “Consolidation of Variable Interest Entities, an interpretation of ARB 51”

FIN 46-R		FIN 46 (revised December 31, 2003)

Fixed Price Agreement		WECC Fixed Price Gas Sale and Power Purchase Agreement, dated as of March 23, 2004, among CES, CalGen, Delta Energy Center, LLC and Los Medanos Energy Center, LLC

GAAP		Accounting principles generally accepted in the United States of America

Heat Rate		A measure of the amount of fuel required to produce a unit of electricity

Index Based Agreement		Index Based Gas Sale and Power Purchase Agreement, dated as of March 23, 2004, among CES, CalGen and the subsidiaries of CalGen party thereto

Index Hedge		ISDA Master Agreement, Schedule and Confirmation, dated as of March 12, 2004, between CalGen and MSCG, guaranteed by Morgan Stanley pursuant to the Guaranty, dated as of March 12, 2004, of Morgan Stanley in favor of MSCG

KW		Kilowatt(s)

KWh		Kilowatt hour(s)

LIBOR		London Inter-Bank Offered Rate

LSTC		Liabilities subject to compromise

LTSA		Long term service agreement

Maintenance Agreement		Master Maintenance Services Agreement, dated as of March 23, 2004, among CalGen, the subsidiaries of CalGen party thereto and COSCI

MMBtu		Million British thermal units

Morgan Stanley		Morgan Stanley & Co. Incorporated

MSCG		Morgan Stanley Capital Group, Inc.

MW		Megawatt(s)

MWh		Megawatt hour(s)

NESCO		National Energy Systems Company

NOL(s)		Net operating loss(es)

Notes		First Priority Secured Floating Rate Notes due 2009, Second Priority Secured Floating Rate Notes due 2010, Third Priority Secured Floating Rate Notes due 2011 and Third Priority Secured Notes due 2011 in the amounts of $235 million, $640 million, $680 million and $150 million, respectively

O&M		Operations and maintenance

O&M Agreement		Master Operation and Maintenance Agreement, dated as of March 23, 2004, among CalGen, its subsidiaries party thereto and COSCI

Index

ABBREVIATION		DEFINITION

Panda		Panda Energy International, Inc. and certain related parties, including PLC II, LLC

Petition Date		December 20, 2005

PG&E		Pacific Gas and Electric Company

POX		Plant operating expense

Revolving Credit Facility		Amended and Restated Credit Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, as borrower, the Guarantors party thereto from time to time, the Lenders party thereto from time to time, The Bank of Nova Scotia, as administrative agent, LC Bank, lead arranger and sole bookrunner, and Bayerische Landesbank Cayman Islands Branch, Credit Lyonnais New York Branch, ING Capital LLC, Toronto Dominion (Texas) Inc. and Union Bank of California, N.A., as arrangers and co-syndication agents, with respect to $200,000,000 First Priority Secured Revolving Loans

RMR		Reliability-Must-Run

SAB		Staff Accounting Bulletin

SEC		United States Securities and Exchange Commission

SFAS		Statement of Financial Accounting Standards

SGA		Sales, General and Administrative

Solutia		Solutia, Inc.

SOP 90-7		Statement of Position 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code”

Subsidiary Guarantors		Each of the following subsidiaries of CalGen: CalGen Expansion Company, LLC, Baytown Energy Center, LP, Calpine Baytown Energy Center GP, LLC, Calpine Baytown Energy Center LP, LLC, Baytown Power GP, LLC, Baytown Power, LP, Carville Energy LLC, Channel Energy Center, LP, Calpine Channel Energy Center GP, LLC, Calpine Channel Energy Center LP, LLC, Channel Power GP, LLC, Channel Power, LP, Columbia Energy LLC, Corpus Christi Cogeneration LP, Nueces Bay Energy LLC, Calpine Northbrook Southcoast Investors, LLC, Calpine Corpus Christi Energy GP, LLC, Calpine Corpus Christi Energy, LP, Decatur Energy Center, LLC, Delta Energy Center, LLC, CalGen Project Equipment Finance Company Two, LLC, Freestone Power Generation LP, Calpine Freestone, LLC, CPN Freestone, LLC, Calpine Freestone Energy GP, LLC, Calpine Freestone Energy, LP, Calpine Power Equipment LP, Los Medanos Energy Center, LLC, CalGen Project Equipment Finance Company One, LLC, Morgan Energy Center, LLC, Pastoria Energy Facility L.L.C., Calpine Pastoria Holdings, LLC, Calpine Oneta Power, L.P. , Calpine Oneta Power I, LLC, Calpine Oneta Power II, LLC, Zion Energy LLC, CalGen Project Equipment Finance Company Three LLC, CalGen Equipment Finance Holdings, LLC and CalGen Equipment Finance Company, LLC

Index

ABBREVIATION		DEFINITION

Term Loans		First Priority Secured Term Loans due 2009 and Second Priority Secured Term Loans due 2010 in the amounts of $600 million and $100 million, respectively

VIEs		Variable Interest Entities

Water Agreement		Raw Water Service Agreement, dated April 12, 2000 among Contra Costa Water District, Calpine Construction Finance Company, L.P. and Delta Energy Center, LLC

Working Capital Facility		Working Capital Facility Agreement, dated as of March 23, 2004, among CalGen, as borrower, CalGen Holdings, as lender, and, for the limited purpose set forth therein, Calpine, as guarantor, with respect to $750 million of unsecured subordinated revolving loans

Index Definitions

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

CALPINE GENERATING COMPANY, LLC

(a wholly owned subsidiary of Calpine Corporation)

(Debtor-in-Possession)

CONSOLIDATED CONDENSED BALANCE SHEETS

~~June~~September 30, 2006 and December 31, 2005

(Unaudited)

	June 30,		December 31,
	September 30,		December 31,
	2006		2005
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	~~205~~378,~~511~~394	$	143,456
Restricted cash, current		57		55
Accounts receivable, net of allowance of $6,692 and $4,649		40,399		70,614
Accounts receivable, net of allowance of $5,284 and $4,649		39,349		70,614
Accounts receivable – related party, net of allowance of $102,816 and $102,816		2127,~~317~~505		5,455
Notes receivable, current portion		~~424~~402		436
Inventories		2122,~~117~~547		20,396
Current derivative assets		1714,~~202~~093		16,380
Deferred tax asset		5,560		5,055
Prepaid and other current assets		3025,~~685~~332		19,481
Total current assets		~~342~~513,~~272~~239		281,328
Property, plant and equipment, net		4,~~974~~933,~~952~~533		5,053,715
Notes receivable, net of current portion		18,~~760~~646		18,977
Restricted cash, net of current portion		95		95
Deferred financing costs, net		3331,~~878~~139		40,043
Long-term derivative assets		—		8,178
Other assets		5855,~~906~~612		31,719
Total assets	$	5,~~428~~552,~~863~~264	$	5,434,055
LIABILITIES & MEMBER’S EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	82101,~~687~~869	$	101,105
Notes payable, current		~~279~~168		171
Priority notes, term loans and other financings, current		2,510,~~365~~827		2,437,982
Accrued interest payable		6699,~~370~~448		61,401
Other current liabilities		~~219~~115		1,839
Total current liabilities		2,~~659~~712,~~920~~427		2,602,498
Notes payable, net of current portion		1,~~838~~790		1,943
Deferred tax liability		8590,~~577~~747		73,130
Deferred revenue		911,~~997~~003		8,770
Other liabilities		26,~~748~~437		17,478
Total liabilities not subject to compromise		2,~~784~~842,~~080~~404		2,703,819
Liabilities subject to compromise		16,~~610~~735		25,592
Commitments and contingencies (see Note 10)
Member’s equity		2,~~628~~693,~~173~~125		2,704,644
Total liabilities and member’s equity	$	5,~~428~~552,~~863~~264	$	5,434,055

The accompanying notes are an integral part of these

Consolidated Condensed Financial Statements.

Index Definitions

CALPINE GENERATING COMPANY, LLC

(a wholly owned subsidiary of Calpine Corporation)

(Debtor-in-Possession)

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

For the Three and ~~Six~~Nine Months ~~Ended~~ended ~~June~~September 30, 2006 and 2005

(Unaudited)

	Three Months Ended						~~Six~~Nine Months Ended
	June 30,						June 30,
	September 30,						September 30,
	2006			2005 ~~(Restated)~~			2006			2005 ~~(Restated)~~
				(Restated)						(Restated)
	(In thousands)
Revenue:
Electricity and steam revenue – related party	$	~~473~~697,~~285~~185		$	~~362~~813,~~015~~715		$	~~833~~1,~~313~~530,498		$	~~707~~1,~~341~~521,056
Electricity and steam revenue – third party		~~107~~114,~~379~~164			~~127~~139,~~150~~765			~~231~~345,~~722~~886			~~240~~379,~~189~~954
Total electricity and steam revenue		~~580~~811,~~664~~349			~~489~~953,~~165~~480			1,~~065~~876,~~035~~384			~~947~~1,~~530~~901,010
Mark-to-market activity, net		(3,~~227~~109)	)		(~~179~~490	)		(710,~~356~~465	)		(7,~~464~~954	)
Other revenue		21,~~300~~211			~~448~~824			56,~~090~~301			12,~~648~~472
Total revenue		~~579~~809,~~737~~451			~~489~~953,~~434~~814			1,~~062~~872,~~769~~220			~~941~~1,~~714~~895,528
Cost of revenue
Plant operating expense		4961,~~069~~899			7146,~~553~~737			88150,~~561~~460			~~115~~161,~~027~~764
Fuel expense		~~419~~558,~~629~~244			~~332~~672,~~742~~133			~~798~~1,~~465~~356,709			~~667~~1,~~297~~339,430
Purchased power expense		~~3,648~~428			~~2,895~~269			12,~~472~~900			7,~~313~~582
Depreciation and amortization expense		3742,~~683~~480			4348,~~725~~022			78121,~~836~~316			84132,~~368~~390
Total cost of revenue		~~510~~663,~~029~~051			~~450~~767,~~915~~161			~~978~~1,~~334~~641,385			~~874~~1,~~005~~641,166
Gross profit		69146,~~708~~400			38186,~~519~~653			84230,~~435~~835			67254,~~709~~362
Long-term service agreement cancellation charge		—1,500			~~23,864~~––			—1,500			23,~~864~~860
Sales, general and administrative expense		62,~~695~~792			34,~~519~~115			911,~~031~~823			610,~~770~~889
Other operating expense		—			1,500			—			—
Income from operations		142,108			182,538			217,512			219,613
Income from operations		63,013			9,636			75,404			37,075
Interest expense		73,370			61,358			215,631			167,415
Interest expense – third party		73,354			55,308			142,261			106,057
Interest (income)		(4,290	)		(1,582	)		(9,021	)		(2,979	)
Interest (income)		(2,457	)		(608	)		(4,731	)		(1,397	)
Other expense (income), net		178			599			47			1,822
Other expense (income), net		(78	)		610			(131	)		1,223
Income before reorganization items and income taxes		72,850			122,163			10,855			53,355
Loss before reorganization items and income taxes		(7,806	)		(45,674	)		(61,995	)		(68,808	)
Reorganization items		4,111			—			5,664			—
Reorganization items		1,553			—			1,553			—
Income before income taxes		68,739			122,163			5,191			53,355
Loss before income taxes		(9,359	)		(45,674	)		(63,548	)		(68,808	)
Income tax expense		5,287			46,788			17,463			20,435
Income tax expense (benefit)		6,889			(17,493	)		12,176			(26,353	)
Net income (loss)	$	63,452		$	75,375		$	(12,272	)	$	32,920
Net loss	$	(16,248	)	$	(28,181	)	$	(75,724	)	$	(42,455	)

The accompanying notes are an integral part of these

Consolidated Condensed Financial Statements.

Index Definitions

CALPINE GENERATING COMPANY, LLC

(a wholly owned subsidiary of Calpine Corporation)

(Debtor-in-Possession)

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

For the ~~Six~~Nine Months Ended ~~June~~September 30, 2006 and 2005

(Unaudited)

	Six Months Ended
	Nine Months Ended
	June 30,
	September 30,
	2006			2005 ~~(Restated)~~
				(Restated)
	(In thousands)
Cash flows from operating activities:
Net loss	$	(75,724	)	$	(42,455	)
Net income (loss)	$	(12,272	)	$	32,920
Adjustments to reconcile net loss to net cash provided by operating activities:
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation and amortization		85131,~~926~~607			90141,~~535~~889
Deferred income taxes		1117,~~942~~112			~~(26~~20,~~353~~435	)
Change in derivative asset		7,356			7,464
Change in derivative assets		10,465			7,954
Loss on sale of assets		1,290			—
Long-term service agreement cancellation charge		—1,500			23,~~864~~860
Change in operating assets and liabilities:
Accounts receivable		3031,~~215~~265			(637,~~178~~250	)
Accounts receivable – related party		(1521,~~648~~836	)		(4886,~~156~~603	)
Other current assets		(1411,~~033~~766	)		~~135~~(2,635	)
Other assets		35,~~260~~906			54,~~657~~052
Accounts payable and accrued liabilities		1232,~~946~~150			30,~~478~~221
Accrued interest payable		438,~~969~~047			530,~~790~~070
Other accrued liabilities		10,~~309~~619			24,~~961~~570
Net cash provided by operating activities		62234,~~808~~087			43169,~~742~~483
Cash flows from investing activities:
Increase in restricted cash		(2	)		(~~162~~153	)
Payment of deferred transmission credits		(2,765	)		(500	)
Receipts from notes receivable		365			—
Proceeds from deferred transmission credits		4,458			659
Payment of deferred transmission credits		(2,765	)		(1,481	)
Purchases of property, plant and equipment		(2,641	)		(67,630	)
Proceeds from deferred transmission credits		6,886			3,357
Receipts from notes receivable		197			—
Purchases of property, plant and equipment		(3,477	)		(76,623	)
Net cash used in investing activities		(753	)		(67,633	)
Net cash provided by (used in) investing activities		1,007			(74,900	)
Cash flows from financing activities:
Repayment on notes payable		—(156	)		(166	)
Net cash used in financing activities		—(156	)		(166	)
Net increase (decrease) in cash and cash equivalents		62,055			(24,057	)
Net increase in cash and cash equivalents		234,938			94,417
Cash and cash equivalents, beginning of period		143,456			64,538
Cash and cash equivalents, end of period	$	~~205~~378,~~511~~394		$	40158,~~481~~955

The accompanying notes are an integral part of these

Consolidated Condensed Financial Statements.

Index Definitions

CALPINE GENERATING COMPANY, LLC

(a wholly owned subsidiary of Calpine Corporation)

(Debtor-in-Possession)

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS –– (Continued)

For the ~~Six~~Nine Months Ended ~~June~~September 30, 2006 and 2005

(Unaudited)

	Six Months Ended
	Nine Months Ended
	June 30,
	September 30,
	2006		2005 ~~(Restated)~~
			(Restated)
	(In thousands)
Supplemental cash flow information:				—
Cash paid during the period for:
Interest, net of amounts capitalized	$	~~129~~167,~~453~~738	$	93132,~~425~~434
Reorganization items included in operating activities	$	~~699~~2,613	$	—
Non-cash transactions:
Capital expenditures included in accounts payable	$	—	$	10,814
Long term service agreement cancellation costs contributed by parent	$	1,500	$	30,900
Long term service agreement cancellation costs contributed by parent	$	—	$	30,900
Acquisition of property, plant and equipment through affiliate transfer	$	703	$	7,196
Borrowings under revolving credit facility due from affiliate	$	41,458	$	—
Borrowings under revolving credit facility issued as deposits	$	30,000	$	—

The accompanying notes are an integral part of these

Consolidated Condensed Financial Statements.

Index Definitions

CALPINE GENERATION COMPANY, LLC

(a wholly owned subsidiary of Calpine CalGen Holdings, Inc.)

(Debtor-in-Possession)

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

~~June~~September 30, 2006

(Unaudited)

1. Basis of Interim Presentation and Summary of Significant Accounting Policies

Basis of Interim Presentation

Our accompanying unaudited interim Consolidated Condensed Financial Statements have been prepared by us pursuant to the rules and regulations of 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 (which were all of a normal, recurring nature, except as described in Note 3). Certain information and footnote 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 Consolidated Condensed Financial Statements should be read in conjunction with our audited Consolidated Financial Statements for the year ended December 31, 2005, included in our 2005 Form 10-K. Certain prior period financial information has been restated as set forth in Note 3. The results for interim periods are not necessarily indicative of the results for the entire year.

The accompanying Consolidated Condensed Financial Statements reflect all costs of doing business, including those incurred by Calpine on our behalf. CalGen’s Consolidated Condensed Financial Statements for all periods reflect an allocation of charges for Calpine’s common expenditures. Such charges have been made in accordance with SAB No. 55, “Allocation of Expenses and Related Disclosure in Financial Statements of Subsidiaries, Divisions or Lesser Business Components of Another Entity.” Costs that are clearly identifiable as being applicable to us have been allocated to us and are reimbursed to Calpine. The most significant costs included in this category include costs incurred during the construction phase of the facilities when salaries and other costs are charged directly to the related construction project. Costs of centralized departments that serve all business segments have been allocated, where such charges would be material, using relevant allocation measures, primarily the base labor of CalGen as a percentage of the consolidated base labor of Calpine. The most significant costs in this category include salary and benefits of certain employees, legal and other professional fees, information technology costs and facilities costs, including office rent. Calpine corporate costs that relate to other business segments of Calpine have not been allocated to us. Charges for Calpine’s common general and administrative expenses that have been allocated to us by Calpine have been recorded as contributions from our Parent.

Summary of Significant Accounting Policies

Use of Estimates in Preparation of Financial Statements — The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during the reporting period. Actual results could differ from those estimates. The most significant estimates with regard to these financial statements relate to useful lives of the assets and related depreciation, salvage value assumptions, deferred income taxes, tax valuation allowance, fair value calculations of derivative instruments, capitalization of interest, allowance for doubtful accounts, impairment assessments, the outcome of pending litigation, the allocation of Calpine’s shared expenditures and the ability of CalGen to recover the carrying value of the facilities.

Restricted Cash — We are required to maintain cash balances that are restricted by terms and provisions governing our debt and regulatory provisions to which we or our subsidiaries are subject. These amounts are held by depository banks in order to comply with our contractual provisions and required reserves for environmental payments. Funds that can be used to satisfy obligations due during the next twelve months are classified as current restricted cash, with the remainder classified

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as non-current restricted cash. The carrying value approximates fair value due to the short-term maturities of these balances. Such cash is excluded from cash and cash equivalents in the Consolidated Condensed Balance Sheet and Statement of Cash Flows.

Reclassifications — We have reclassified $~~0.8 million and $~~5.5 million in sales of purchased power for the ~~three~~nine ~~and six~~ months ended ~~June~~September 30, 2005, ~~respectively,~~ to Electricity and steam revenue – third party to conform to current year presentation with no effect to total revenues or net income (loss).

Reorganization Items — Reorganization items represent the direct and incremental costs of being in Chapter 11, such as legal fees and financial advisory and consulting fees. The table below lists the significant items recognized within this category for the three and ~~six~~nine months ended ~~June~~September 30, 2006 (in thousands).

	Three Months Ended June 30, 2006		Six Months Ended June 30, 2006
	Three Months Ended September 30, 2006		Nine Months Ended September 30, 2006
Legal fees	$	1,~~020~~256	$	12,~~020~~276
Financial advisory and consulting fees		~~533~~2,855		~~533~~3,388
Total reorganization items	$	14,~~553~~111	$	15,~~553~~664

Provision (Benefit) for Income Taxes — We are a single member limited liability company that has been treated as a taxable entity for financial reporting purposes. Our results of operations are included in the consolidated tax return of Calpine. For all periods presented, we accounted for income taxes using the separate return method. For the three ~~and six~~ months ended ~~June~~September 30, 2006 and 2005, the effective tax rate was ~~(73~~7.6)7% and 38.3%, respectively~~, and (19~~.~~2)%~~ ~~and~~For ~~38.3%,~~the ~~respectively.~~nine Asmonths inended ~~the prior year~~September 30, ~~our~~2006 ~~history~~and of2005, ~~operating~~the ~~losses~~effective ~~precludes~~tax ~~recognition~~rate ofwas ~~future~~336.4% ~~benefit~~and ~~from the current period’s loss~~38.3%, ~~Future income is only considered to the extent of the future reversal of taxable book-tax differences~~respectively. The tax provision for the three and ~~six~~nine months ended ~~June~~September 30, 2006, and total tax expense expected for the full year ended December 31, 2006, arise from expected net increases in the deferred tax liability as a result of property differences between our financial statements and our tax return.

During the fourth quarter of 2005, Calpine and many of its subsidiaries, including CalGen filed for Chapter 11 protection and recorded significant reorganization 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 cases. The Bankruptcy Court has entered an order that places certain limitations on trading of Calpine’s common stock or certain securities, including options, convertible into Calpine’s common stock during the pendency of the Chapter 11 cases. In addition, the Bankruptcy Court has entered ana similar order, on an interim basis only, that establishes certain notice and sell-down procedures for trading in claims against the Debtors’ estates and has scheduled a hearing for February 7, 2007, to consider a final order with respect to the claims trading procedures. 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 ~~assurance~~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.

SFAS No. 109 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 should be recorded on a portion of our deferred tax assets that were not offset by deferred tax liabilities.

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Chapter 11, we concluded that valuation allowances should be recorded on a portion of our deferred tax assets that were not offset by deferred tax liabilities.

Recent Accounting Pronouncements

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 FASB Statement 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 consolidated 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 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 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. Chapter 11 Cases and Going Concern

Since the Petition Date, Calpine Corporation and 273 of its wholly owned subsidiaries in the U.S., including CalGen and its subsidiaries, have filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Chapter 11 cases are being jointly administered for procedural purposes only by the Bankruptcy Court under the case captioned In re Calpine Corporation et al., Case No. 05-60200 (BRL). The Debtors, including the CalGen 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 Court. Generally, while a plan or plans of reorganization or arrangement are developed, all actions to enforce or otherwise effect repayment of liabilities preceding the Petition Date as well as all pending

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under the protection of the Bankruptcy Court. Generally, while a plan or plans of reorganization or arrangement are developed, all actions to enforce or otherwise effect repayment of liabilities preceding the Petition Date as well as all pending litigation against the CalGen Debtors are stayed while the CalGen Debtors continue their business operations as debtors-in-possession.

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~~December 116, 2006, the Bankruptcy Court granted Calpine’s application for an extension of the period during which the Debtors have the exclusive right to file a ~~reorganization~~ plan or plans ~~from April 20, 2006, to December 31, 2006, and granted the Debtors the exclusive right until March 31, 2007, to solicit acceptances~~ of ~~such plan or plans. On December 6, 2006, the Bankruptcy Court approved a further extension of the period during which the Debtors have the exclusive right to file a plan or plans of~~ reorganization to June 20, 2007, and the deadline by which the Debtors have the exclusive right to solicit acceptances to August 20, 2007. However, the Bankruptcy Court has the power to terminate these periods prior to June 20, 2007, and August 20, 2007, respectively, and we can make no assurance that the Bankruptcy Court will not do so.

We are largely dependent upon the plans and actions taken by Calpine, through its Chapter 11 restructuring, to develop, implement and approve a plan of reorganization that will strengthen and improve our financial health and permit us to emerge from Chapter 11. Four of our power plants are identified for possible sale by Calpine. They are the Carville, Columbia, Decatur and Goldendale facilities. CES, a wholly owned subsidiary of Calpine and a Debtor, currently is our primary customer. CES purchases the majority of the electricity produced by our facilities, and supplies the majority of the natural gas needed to operate our facilities, under the Fixed Price and Index Based Agreements. Should CES reject the Fixed Price or Index Based Agreements, or both, in the Chapter 11 cases, it could have a material adverse impact on our ability to continue to operate as a going concern. If CES were to reject either or both of the agreements, we plan to continue to sell power to CES under another contract or identify other potential customers and enter into alternative arrangements. COSCI, which is a Debtor and a wholly owned direct subsidiary of Calpine, acts as our primary operator for our plants under the Maintenance Agreement and the O&M Agreement. Should COSCI reject the Maintenance Agreement or the O&M Agreement, or both, we would seek similar operating agreements from COSCI or other providers. There is no assurance that we can negotiate other arrangements related to the above on acceptable terms.

At this time, it is not possible to accurately predict the effects of the Chapter 11 reorganization process on the business of the CalGen Debtors or if and when some or all of the CalGen Debtors may emerge from Chapter 11. The prospects for our future results depend on the timely and successful development, confirmation and implementation of a plan or plans of reorganization of the CalGen Debtors, which plan or plans may cover some or all of the other Debtors. There can be no assurance that a successful plan or plans of reorganization will be proposed by the CalGen Debtors, supported by the CalGen Debtors’ creditors or confirmed by the 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 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 CalGen and the other CalGen 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 receive little or no payment with respect to their claims. If claims of any of the CalGen Debtors’ creditors will not be compromised, it is possible that such creditors will not have the right to vote on any such plan or plans. Whether or not a plan or plans or reorganization are approved, it is possible that the assets of any one or more of the CalGen Debtors may be liquidated.

As a result of our Chapter 11 cases 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, including the restructuring of Calpine and the other Debtors; (iv) our ability to comply with our debt agreements, including the DIP Facility, and the adequate assurance provisions of the Cash Collateral Order; (v) the ability of Calpine to continue to meet the DIP Facility requirements; and (vi) our ability to achieve profitability following a restructuring. Additionally, because of our significant relationships with Calpine, CES and COSCI, we are also dependent upon those entities to continue to operate as a going concern. These challenges are in addition to those operational and competitive challenges faced by us in connection with our business. In conjunction with Calpine and our advisors, we are working to design and implement strategies to ensure

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DIP Facility requirements; and (vi) our ability to achieve profitability following a restructuring. Additionally, because of our significant relationships with Calpine, CES and COSCI, we are also dependent upon those entities to continue to operate as a going concern. These challenges are in addition to those operational and competitive challenges faced by us in connection with our business. In conjunction with Calpine and 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.

Significant Pending Matters and Recent Developments — On January 26, 2006, the Bankruptcy Court entered a final order approving Calpine’s DIP Facility and removing its previously imposed limitation on Calpine’s ability to borrow thereunder. See Note 5. for further information regarding the DIP Facility. In addition, the Bankruptcy Court approved cash collateral and adequate assurance stipulations in connection with the approval of the DIP Facility, which has allowed Calpine’s, as well as our own, business activities to continue to function. We have also sought and obtained 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, and maintain our insurance programs, which has allowed us to continue to operate the existing business in the ordinary course. In addition, the Bankruptcy Court has approved certain trading notification and transfer procedures designed to allow Calpine to restrict trading in its common stock (and related securities) and, on an interim basis only, trading in its claims which could negatively impact our accrued 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.

On January 26, 2006, the Bankruptcy Court entered a final order approving Calpine’s DIP Facility and removing its previously imposed limitation on Calpine’s ability to borrow thereunder. See Note 5. for further information regarding the DIP Facility. In addition, the Bankruptcy Court approved cash collateral and adequate assurance stipulations in connection with the approval of the DIP Facility, which has allowed Calpine’s, as well as our own, business activities to continue to function. We have also sought and obtained 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, and maintain our insurance programs, which has allowed us to continue to operate the existing business in the ordinary course. In addition, the Bankruptcy Court has approved certain trading notification and transfer procedures designed to allow Calpine to restrict trading in its common stock (and related securities) and, currently on an interim basis only, trading in its claims, which could negatively impact our accrued 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.

Pursuant to the cash management system, and in accordance with our cash collateral requirements in connection with the DIP Facility and relevant Bankruptcy Court orders including the Cash Collateral Order, intercompany transfers are generally recorded as intercompany loans. On December 20, 2006, the Bankruptcy Court approved an order (as modified by the Bankruptcy Court’s order entered on January 18, 2007) modifying the Cash Collateral Order, pursuant to which the collateral agent for our Notes and Term Loans transferred $259.6 million in excess cash to Calpine in the form of an intercompany loan. In addition, pursuant to the order, the collateral agent will honor all future requests for intercompany loan transfers within three days of receipt of the request, provided that the Debtors are in compliance with their adequate protection obligations under the Cash Collateral Order and certain specified provisions of the indentures governing the Notes. As adequate protection to holders of the Notes, the Term Loan lenders and the lenders under the Revolving Credit Agreement, we shall have a first priority lien upon the excess cash flow transferred to the extent such funds remain in a separate account maintained by Calpine. In addition, we shall have an allowed claim in the amount of the excess cash flow transferred against each of the Debtors and a junior lien upon all assets of each of the Debtors, with the exception of certain Debtors as set forth in the December 20, 2006, and January 18, 2007, orders.

The Bankruptcy Court had established August 1, 2006, as the bar date for filing proofs of claim against the CalGen Debtors’ estates. Under certain limited circumstances, some creditors may be permitted to file claims after the applicable bar dates. Differences between amounts recorded by the 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. The Debtors have begun the claims review process, and have filed claims objections (and expect that additional claims objections will be filed) with the Bankruptcy Court pursuant to which the Debtors 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 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 Bankruptcy Court and certain other conditions. Parties to executory contracts or unexpired leases rejected or deemed rejected by a CalGen Debtor may file proofs of claim against that CalGen 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 determine with certainty the magnitude of these potential claims at this time, but to the extent a potential claim is probable and estimable, we record our estimate of the allowed claim

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or unexpired leases rejected or deemed rejected by a CalGen Debtor may file proofs of claim against that CalGen 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 determine with certainty the magnitude of these potential claims at ~~this time, but to~~ the ~~extent a potential claim is probable and estimable, we record our estimate of the allowed claim at the~~ time of rejection or upon Bankruptcy Court approval, depending ~~upon~~on the facts and circumstances. The most significant of these contract rejections that were pending or occurred during the ~~six~~nine months ending ~~June~~September 30, 2006, or thereafter through the date of this filing ~~include~~includes the following:

• On September 12, 2006, we filed with the Bankruptcy Court a notice of rejection of a transportation contract between Columbia Energy LLC, a CalGen Debtor, and South Carolina Pipeline Corporation. The contract, which is scheduled to expire on November 30, 2023, was for transportation capacity on an intrastate pipeline that exceeded the Columbia facility’s requirements. On September 25, 2006, South Carolina Pipeline Corporation filed certain objections to the rejection notice, which were ultimately resolved by the parties, and, on October 25, 2006, the Bankruptcy Court entered the parties’ stipulation settling this matter. Under the stipulation, the effective date of rejection is October 25, 2006, and South Carolina Pipeline Corporation must file its claim for rejection damages by December 22, 2006. South Carolina Pipeline Corporation filed a proof of claim December 21, 2006, for rejection damages comprising $5.3,300,000 ~~million~~ in secured claims and $160.3,283,593 ~~million~~ in unsecured claims. It is not certain at this time whether some or all of these claims will ultimately be allowed.

•

On October 20, 2006, Columbia Energy LLC entered into a stipulation settling Southern Natural Gas Company’s administrative expense claim relating to a firm transportation natural gas pipeline contract between the parties. Under the stipulation, Columbia agreed to pay $2.4 million for actual post-petition utilization of the contract. Columbia ceased using the contract on June 24, 2006, and Southern Natural Gas Company has agreed to waive any right to seek payment of an administrative expense claim for the period after Columbia ceased using the contract. Southern Natural Gas Company has also agreed not to oppose any motion to reject the contract. The Bankruptcy Court approved the stipulation on November 8, 2006.

In addition, we had until July 18, 2006, to assume unexpired non-residential real property leases. Absent the consent of the applicable counterparty, such leases not assumed by that date are deemed rejected. Accordingly, 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 Bankruptcy Court approved our motion to extend the time for us to assume leases between Debtor-lessees and any affiliated lessors until the confirmation of a plan of reorganization of the applicable Debtor-lessee. Without an extension of time to assume, leases between CalGen Debtors and their affiliates would also have been deemed rejected if not assumed by July 18, 2006. The most significant of these matters that were pending or occurred during the ~~six~~nine months ending ~~June~~September 30, 2006, or thereafter through the date of this filing include the following:

•

On October 12, 2006, the Bankruptcy Court approved our motion to assume five agreements relating to operation of the Channel Energy Center, a 531-MW gas-fired combined cycle cogeneration plant located near Houston, Texas. The five agreements assumed are (i) the Amended and Restated Ground Lease and Easement Agreement, (ii) the Operating Lease Agreement, (iii) the Development, Construction, Operation and Maintenance Agreement, (iv) the Facility Services Agreement and (v) the Energy Services Agreement, all of which are between Channel Energy Center LP and Lyondell-CITGO Refining L.P.

•

On December 6, 2006, the Bankruptcy Court approved the Debtors’ motion to assume the facility site lease and energy services agreement underlying our Corpus Christi facility, a 437-MW gas-fired combined cycle cogeneration plant located near Corpus Christi, Texas, and approved a settlement agreement and amendments to the facility site lease and energy services agreement with CITGO Refining and Chemicals Company L.P., the counterparty to the facility site lease and energy services agreement, pursuant to which certain disputes under those agreements have been resolved.

•

On January 31, 2007, the Bankruptcy Court approved our motion to assume certain leases and executory contracts relating to operation of the Baytown facility, a 753-MW natural gas-fired combined cycle cogeneration plant located near Baytown, Texas. The agreements include (i) the Ground Lease and Easement, (ii) the Services Agreement, and (iii) numerous other agreements that facilitate the operation and maintenance of the Baytown facility and the use of certain real property rights appurtenant thereto.

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•Asset OnSale ~~January~~— ~~19,~~We ~~2007,~~are wealso ~~filed~~required ato ~~motion~~obtain ~~with the~~ Bankruptcy Court toapproval ~~assume~~of ~~certain~~sales ~~leases and executory contracts relating to operation~~ of ~~the Baytown facility~~assets, asubject ~~753-MW~~to ~~natural~~certain ~~gas-fired~~exceptions ~~combined~~including ~~cycle~~with ~~cogeneration~~respect ~~plant~~to ~~located~~de ~~near~~minimis ~~Baytown, Texas~~assets. ~~The~~Such ~~agreements~~sales weare ~~seek~~subject toin ~~assume~~certain ~~include~~cases ~~(i)~~to ~~the~~Bankruptcy ~~Ground~~Court-approved ~~Lease~~auction ~~and~~procedures. ~~Easement,~~The ~~(ii)~~most ~~the~~significant ~~Services~~of ~~Agreement,~~these ~~and~~matters ~~(iii)~~that ~~numerous~~were ~~other~~pending ~~agreements~~or ~~that~~occurred ~~facilitate~~during the ~~operation~~nine ~~and~~months ~~maintenance~~ended ofSeptember 30, ~~the~~2006, ~~Baytown~~or ~~facility~~thereafter ~~and~~through the ~~use~~date of ~~certain~~this ~~real~~filing ~~property~~includes ~~rights appurtenant thereto. Hearing on~~ the ~~motion is currently scheduled for January 31, 2007, before the Bankruptcy Court.~~following:

We are also required to obtain Bankruptcy Court approval of sales of assets, subject to certain exceptions including with respect to de minimis assets. Such sales are subject in certain cases to Bankruptcy Court-approved auction procedures. The most significant of these matters that were pending or occurred during the six months ended June 30, 2006, or thereafter through the date of this filing include the following:

•

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. On December 6, 2006, the Bankruptcy Court approved an auction process in which qualifying bidders can make competing offers on the transaction. The sale hearing is currently scheduled for February 7, 2007, before the Bankruptcy Court. 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 the ~~six~~nine months ended ~~June~~September 30, 2006, or thereafter through the date of this filing include the following:

•

On December 6, 2006, the Bankruptcy Court entered an interim order establishing the effective date for notice and sell-down procedures for trading in claims against the Debtors’ estates and scheduling a hearing on February 7, 2007, to approve an order establishing notice and sell-down procedures for trading in claims against the Debtors’ estates. The notice and sell-down procedures will allow the Debtors to identify substantial claim holders and to require certain claim holders who purchase claims after entry of the interim order to sell down a portion of those claims, if necessary, to protect the Debtors’ ability to utilize their accumulated net operating losses and other tax attributes. Pursuant to the interim order, potential purchasers of claims against the Debtors are deemed notified that, to the extent a final order is approved, they may be subject to a required sell-down of any claims purchased after December 6, 2006, pursuant to the terms of the final order. The Bankruptcy Court previously approved certain trading notification and transfer procedures designed to allow Calpine Corporation to restrict trading in its common stock (and related securities) which could negatively impact the Debtors’ accumulated net operating losses and other tax attributes.

• On January 26, 2007, Calpine filed a motion for an order authorizing the Debtors to obtain a $5.0 billion replacement debtor-in-possession financing facility to refinance the existing $2.0 billion DIP Facility and repay the approximately $2.516 billion of CalGen Secured Debt. The proposed refinancing is intended to replace the higher interest-rate DIP Facility and CalGen Secured Debt with lower interest-rate debt, resulting in potential savings in interest expense and in savings to audit fees and compliance costs ~~related~~relating to existing CalGen Secured Debt. To effectuate the proposed repayment of the CalGen Secured Debt, the motion also asks the Bankruptcy Court to allow the Debtors’ limited objection to the claims filed by the holders of the CalGen Secured Debt and to determine the value of those claims. A hearing on the motion is currently scheduled before the Bankruptcy Court on February 27, 2007.

3. Restatement

Our Consolidated Condensed Financial Statements for the three months and ~~six~~nine months ended ~~June~~September 30, 2005, were restated in this Report to correct certain errors identified in connection with preparing our December 31, 2005, financial statements as described in our 2005 Form 10-K and below.

Income taxes — We determined that deferred tax liabilities should have been allocated to us related to certain plant assets contributed by Calpine to us via the transfer of Calpine’s equity ownership interest therein. These assets had been acquired by Calpine in a transaction that resulted in a step-up in the book basis of the assets to the purchase price values but for which a step-up of the tax basis of the assets is not allowed. The resultant deferred tax liabilities totaling $175.1 million should have been pushed down to our books when Calpine transferred the assets to us to account for the difference in the book and tax basis of the assets. Instead, we initially recorded amounts related to these deferred tax liabilities as subordinated debt owed to Calpine, which was later converted to equity invested in us by Calpine at the time of the 2004 Refinancing,

Index Definitions

Income taxes — We determined that deferred tax liabilities should have been allocated to us related to certain plant assets contributed by Calpine to us via the transfer of Calpine’s equity ownership interest therein. These assets had been acquired by Calpine in a transaction that resulted in a step-up in the book basis of the assets to the purchase price values but for which a step-up of the tax basis of the assets is not allowed. The resultant deferred tax liabilities totaling $175.1 million should have been pushed down to our books when Calpine transferred the assets to us to account for the difference in the book and tax basis of the assets. Instead, we initially recorded amounts related to these deferred tax liabilities as subordinated debt owed to Calpine, which was later converted to equity invested in us by Calpine at the time of the 2004 Refinancing, consummated on March 23, 2004, of our $2.5 billion construction credit agreement. As a result of these errors, changes in deferred tax liabilities were not reflected in the periodic income tax provision from 2000 through 2004 and valuation allowances were established against deferred tax assets associated with net operating losses that would not have been necessary had the full amount of deferred tax liabilities been taken into account. Amounts reported for net deferred income tax liabilities was understated by $350.76 million as of ~~June~~September 30, 2005, and net ~~loss~~income was overstated for income tax ~~benefits~~expense not recognized in the amount of $1746.58 million ~~for the three months ended June 30, 2005~~ and $2620.4 million for the ~~six~~three months and nine months ended ~~June~~September 30, 2005, respectively. Accordingly, we restated our Consolidated Condensed Statement of Operations for the three months and nine months ended September 30, 2005, and our Consolidated Condensed Statement of Cash Flows for the ~~three~~nine months ~~and six months~~ ended ~~June~~September 30, 2005, to correct this error.

Fuel expense — We determined through our intercompany reconciliation procedures that we overpaid CES by $47.9 million and $18.6 million for fuel expenses during the three months ~~ended June 30, 2005~~ and ~~$10.7~~nine ~~million during the six~~ months ended ~~June~~September 30, 2005, respectively. The error was the result of failure to deduct fuel quantities provided directly to our Channel and Corpus Christi facilities by unrelated parties (the steam hosts) when calculating CES’ net payment to us for power generated net of fuel cost. We include all fuel quantities used by the plant in our calculation of fuel cost netted with power sales to CES unless the fuel quantities are provided by unrelated parties. Failure to deduct these quantities from our calculation of fuel cost resulted in a lower net payment received from CES and a corresponding overstatement of fuel expense. Accordingly, we restated fuel expenses by recording a reduction of $47.69 million and $1018.76 million in fuel expense for the three months and ~~six~~nine months ended ~~June~~September 30, 2005, respectively.

Deferred transmission credits — We determined that we incorrectly classified $01.5 million in payments made for point-to-–point deferred transmission credits and $03.74 million in reimbursement in payments received for point-to-–point deferred transmission credits in our Consolidated Condensed Statement of Cash Flows for the ~~six~~nine months ended ~~June~~September 30, 2005. The amounts were previously included in cash flows from operating activities within changes in prepaid assets (in changes in operating assets and liabilities). We have determined that these pre-payments made, and receipt of payments, for transmission rights had more of the characteristics of investing cash flows than operating cash flows due to their nature and longer term and therefore should have been included in cash flows from investing activities. We restated our Consolidated Condensed Statements of Cash Flows for the ~~six~~nine months ended ~~June~~September 30, 2005, to properly classify such amounts.

Other operating (income) expense –– In connection with the preparation of our 2005 Form 10-K, we determined that other out-of-period adjustments between the three months ended March 31, 2005 and the three months ended June 30, 2005, previously identified but deemed to be immaterial both individually and in the aggregate in prior periods, should be corrected. Accordingly, we restated herein our Consolidated Condensed Statement of Operations for the three months ended June 30, 2005 in the amount of $(1.5) million to correct such errors.

Index Definitions

The following tables reflect the originally reported and restated amounts for the three and ~~six~~nine months ended ~~June~~September 30, 2005 (in thousands):

	Three Months Ended						~~Six~~Nine Months Ended
	June 30, 2005						June 30, 2005
	September 30, 2005						September 30, 2005
	As Previously Reported			Restated			As Previously Reported			Restated
	(In thousands)
Consolidated Condensed Statement of Operations:
Fuel expense	$	~~337~~680,~~310~~004		$	~~332~~672,~~742~~113		$	~~678~~1,~~035~~358,039		$	~~667~~1,~~297~~339,430
Total cost of revenue		~~455~~775,~~483~~032			~~450~~767,~~915~~161			~~884~~1,~~743~~659,775			~~874~~1,~~005~~641,166
Gross profit		33178,~~951~~782			38186,~~519~~653			56235,~~971~~753			67254,~~709~~362
Other operating (income) expense		––			1,500			––			––
Income from operations		174,667			182,538			201,004			219,613
Income from operations		6,568			9,636			26,337			37,075
Income tax expense (benefit)		—			46,788			—			20,435
Income tax expense (benefit)		—			(17,493	)		—			(26,353	)
Net income	$	114,292		$	75,375		$	34,746		$	32,920
Net loss	$	(48,742	)	$	(28,181	)	$	(79,546	)	$	(42,455	)

	Six Months Ended
	Nine Months Ended
	June 30, 2005
	September 30, 2005
	As previously reported			Restated
	As Previously Reported			Restated
	(In thousands)
Consolidated Condensed Statement of Cash Flows:
Deferred income tax	$	—		$	(2620,~~353~~435	)
Accounts receivable – related party	$	(3767,~~418~~994	)	$	(4886,~~156~~603	)
Other assets	$	5,~~816~~928		$	54,~~657~~052
Cash provided by operating activities	$	43171,~~901~~359		$	43169,~~742~~483
Payments of deferred transmission credit	$	—		$	(~~500~~1,481	)
Proceeds from deferred transmission credit	$	—		$	~~659~~3,357
Cash used in investing activities	$	(67,792	)	$	(67,633	)
Cash used in Investing Activities	$	(76,776	)	$	(74,900	)

4. Property, Plant and Equipment, Net

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

	June 30, 2006			December 31, 2005
	September 30, 2006			December 31, 2005
Buildings, machinery and equipment	$	5,564,~~594~~904		$	5,563,844
Less: Accumulated depreciation and amortization		(~~597~~639,~~496~~225	)		(517,983	)
		4,967,098			5,045,861
		4,925,679			5,045,861
Land		7,854			7,854
Property, plant and equipment, net	$	4,~~974~~933,~~952~~533		$	5,053,715

Total depreciation and amortization expense for the three and ~~six~~nine months ended ~~June~~September 30, 2006 and 2005 was $3742.75 million and $4348.70 million, respectively, and $78121.83 million and $84132.4 million, respectively.

Impairment Evaluation — All long-lived assets, such as property, plant and equipment, are reviewed for impairment whenever there is an indication of a potential reduction in fair value. Factors that could trigger an impairment include likelihood of sale at a loss, significant underperformance relative to historical or projected future operating results, significant changes in how we use the acquired assets in our overall business strategy and significant negative industry or economic trends.

Index Definitions

in how we use the acquired assets in our overall business strategy and significant negative industry or economic trends.

The determination of whether impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. The significant assumptions used in our undiscounted future cash flow estimates include the future supply and demand relationships for electricity and natural gas and the expected pricing for those commodities as well as the resultant spark spreads in the various regions where we generate electricity. If an impairment has occurred, the amount of the impairment loss recognized would be determined by estimating the fair value of the assets and recording a loss to the extent that the fair value was less than the book value.

Our assessment regarding the existence of impairment factors is based on market conditions, operational performance and legal factors related to our projects. Our review of factors present and the resulting appropriate carrying value of long-lived assets are subject to judgments and estimates that management is required to make. No impairment charge was recorded during the three and ~~six~~nine months ended ~~June~~September 30, 2006 and 2005. However, we recorded impairment charges of $1.2 billion related to four of our power plants in the three months ended December 31, 2005. Future events could cause us to conclude that additional impairment indicators exist and that additional long-lived assets might be impaired.

5. Debt

DIP Facility

In connection with its Chapter 11 cases, Calpine, as a borrower, entered into the $2 billion DIP Facility, which is guaranteed by all of the other Debtors, including the CalGen Debtors. On January 26, 2006, the Bankruptcy Court entered a final order approving the DIP Facility. 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 Debtors 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 and restated on February 23, 2006, and further amended on May 3, 2006, September 25, 2006, and most recently December 20, 2006, to, among other things, (i) implement various provisions of the December 20, 2006, Bankruptcy Court order amending the Cash Collateral Order, including allowing for certain liens in favor of us, (ii) allow adequate protection payments to holders of Calpine’s second priority debt totaling approximately $466 million for 2006 and 2007 and (iii) eliminating the provision that reduces the DIP revolver commitment from $1 billion to $750 million based on certain asset sale mechanics.

As of ~~June~~September 30, 2006, there was $~~998~~997.34 million outstanding under the DIP Facility term loan facilities, nothing outstanding under the DIP Facility revolving facility and $11.7 million of letters of credit had been issued against the revolving facility. As of December 31, 2006, there was $996.5 million outstanding under the DIP Facility term loan facilities, nothing outstanding under the DIP Facility revolving facility and $82.5 million of letters of credit had been issued against the revolving facility. In accordance with FIN 45, we do not record a liability related to the guarantees because each guarantee is a subsidiary’s guarantee of the debt owed to a third party by its parent.

Notes and Term Loans

The $2.4 billion of Notes and Term Loans were issued in connection with the 2004 Refinancing in several tranches and, except for the 11.50% Third Priority Secured Notes Due 2011, carry a floating interest rate based on LIBOR plus a spread as detailed below. The Third Priority Secured Notes Due 2011 carry a fixed interest rate of 11.50%.

Index Definitions

Face Amount		Description	Interest Rate	Carrying Amount at ~~June~~September 30, 2006
(In millions)				(In millions)
$	235.0	First Priority Secured Floating Rate Notes Due 2009	LIBOR plus 375 basis points(1)	$	235.0
	640.0	Second Priority Secured Floating Rate Notes Due 2010	LIBOR plus 575 basis points(2)		634.04
	680.0	Third Priority Secured Floating Rate Notes Due 2011	LIBOR plus 900 basis points		680.0
	150.0	Third Priority Secured Notes Due 2011	11.50%		150.0
	600.0	First Priority Secured Term Loans Due 2009	LIBOR plus 375 basis points(1)		600.0
	100.0	Second Priority Secured Term Loans ~~due~~Due 2010	LIBOR plus 575 basis points(2)		99.12
		Revolving Credit Facility	Base (8%) plus 250 basis points, or LIBOR plus 350 basis points		112.3
$	2,405.0			$	2,510.49

____________

(1)	The Company may also elect a Base Rate plus 275 basis points.

(2)	The Company may also elect a Base Rate plus 475 basis points.

The stated interest rate of the First Priority Secured Term Loans and First Priority Secured Floating Rate Notes was 89.8608% at ~~June~~September 30, 2006, and 8.04% at December 31, 2005. The stated interest rate of the Second Priority Secured Term Loans and Second Priority Secured Floating Rate Notes was 1011.8608% at ~~June~~September 30, 2006, and 10.04% at December 31, 2005. The stated interest rate of the Third Priority Secured Floating Rate Notes was 14.12% at ~~June~~September 30, 2006, and ~~13.22% at~~ December 31, 2005. The stated interest rate of the Revolving Credit Facility was 10.5080% at ~~June~~September 30, 2006, and 7.89% at December 31, 2005.

Other Financings

In connection with the 2004 Refinancing, the Company entered into an agreement with a group of banks led by The Bank of Nova Scotia for the $200.0 million Revolving Credit Facility. This three-year facility is available for specified working capital purposes and for letters of credit. All amounts outstanding under the Revolving Credit Facility will bear interest at either (i) the Base Rate plus 250 basis points, or (ii) at LIBOR plus 350 basis points, in each case as defined in the Revolving Credit Facility. At ~~June~~September 30, 2006, and December 31, 2005, $41.90 million and $158.3 million in letters of credit were issued and outstanding. These letters of credit were primarily issued to support fuel purchases and other operational activities. In addition, there was $112.3 million and $40.8 million in outstanding borrowings under the Revolving Credit Facility at ~~June~~September 30, 2006, and December 31, 2005, respectively. Of the total borrowings outstanding at ~~June~~September 30, 2006, under the Revolving Credit Facility, $82.3 million were drawn on CalGen letters of credit by third parties to pay for pre-petition gas purchases made by CES. We have recorded a receivable from CES for the amounts drawn, as they should be reimbursed by CES; however, these balances are included in our allowance for doubtful accounts. An additional $30.0 million in borrowings under the Revolving Credit Facility related to letters of credit was drawn on April 1, 2006, as a deposit with Wisconsin Electric Power Company in lieu of renewing the letter of credit with them. Total borrowings from letter of credit drawings related to the Revolving Credit Facility were approximately $112.3 million at ~~June~~September 30, 2006, and at December 31, 2006.

In connection with a Water Agreement entered into with Contra Costa Water District for raw water service through April 2015, the Delta and Los Medanos facilities issued a promissory note valued at $3.5 million for the service connection fee. Payments are due annually, on April 1 of each year. The interest rate charged is based on the average rate for the preceding calendar year for the Local Agency Investment Fund plus 2.5%. Obligations under the note are split 70% Delta and

Index Definitions

30% Los Medanos per the terms of the Water Agreement. At ~~each of June~~September 30, 2006, and December 31, 2005, the balance of the note was $2.0 million and $2.1 million, respectively.

We filed for reorganization pursuant to Chapter 11 of the Bankruptcy Code in December 2005 as discussed in Note 2. In accordance with SOP 90-7, we continue to accrue and recognize interest expense on debt that is considered to be fully secured (i.e. the value of the underlying collateral is in excess of the principal amount of debt). Consequently, the Notes, the Term Loans and borrowings under the Revolving Credit Facility are not deemed to be subject to compromise.

Covenant Compliance

Due to our Chapter 11 cases and the Company’s failure to comply with certain other financial covenants under the Notes, the Term Loans and the Revolving Credit Facility as a result of such filings, we are in default on most of our debt obligations (other than our obligations under the DIP Facility). Except as otherwise may be determined by the Bankruptcy Court, the automatic stay protection afforded by the Chapter 11 cases prevents any action from being taken against any of the CalGen Debtors with regard to any of the defaults under the pre-petition debt obligations. However, as a result of our Chapter 11 filing, our entire outstanding debt balance under the Notes, Term Loans and Revolving Credit Facility as of ~~June~~September 30, 2006, in the amount of $2.5 billion was classified as current liabilities.

Pursuant to the DIP Facility, we are subject to a number of affirmative and restrictive covenants, reporting requirements and financial covenants. As of ~~June~~September 30, and December 31, 2006, we were in compliance with the DIP Facility covenants.

6. Liabilities Subject to Compromise

Liabilities subject to compromise include unsecured liabilities incurred prior to the petition date and under-secured liabilities, including secured liabilities as to which there is uncertainty as to whether the value of the collateral securing such liabilities is less than, equals or exceeds such liabilities. The amounts of the various categories of liabilities that are subject to compromise are set forth below. These amounts represent our estimates of known or potential pre-petition claims that are likely to be resolved in connection with the Chapter 11 cases. Such claims remain subject to future adjustments. Adjustments may result from negotiations, actions of the Bankruptcy Court, rejection of executory contracts and unexpired leases, the determination as to the value of any collateral securing claims, proofs of claim or other events. There can be no assurance that the fair value of the assets of the CalGen Debtors will be found to exceed the fair value of their liabilities. This could result in claims being paid at less than 100% of their face value and our equity held by Calpine could be diluted or eliminated entirely.

The amounts of liabilities subject to compromise at ~~June~~September 30, 2006 ~~and December 31~~, ~~2005~~ consisted of the following (in thousands):

	June 30, 2006		December 31, 2005
	September 30,		December 31,
		(In thousands)
	2006		2005
Pre-petition accounts payable	$	9,408	$	10,073
	(In thousands)
Accrued liabilities		7,202		15,519
Pre-petition accounts payable	$	11,037	$	10,073
Total liabilities subject to compromise	$	16,610	$	25,592
Accrued liabilities		5,698		15,519
Total liabilities subject to compromise	$	16,735	$	25,592

7. Significant Customers

In addition to third-party agreements, each of our facilities entered into the Index Based Agreement with CES. The Delta and Los Medanos facilities also entered into the Fixed Price Agreement with CES. Under these agreements, CES purchases substantially all of the output for each facility (subject to certain exceptions for direct sales to third parties) and sells or delivers to each facility substantially all of the gas required for its operations (subject to certain exceptions for gas ~~purchases from third parties). CES is a significant customer and our revenues from sales to CES were as follows (in thousands):~~

Index Definitions

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Revenue:
CES	$	473,285	$	362,015	$	833,313	$	707,341

purchases from third parties). CES is a significant customer and our revenues from sales to CES were as follows (in thousands):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2006		2005		2006		2005
Revenue:
CES	$	697,185	$	813,715	$	1,530,498	$	1,521,056

CES prepares statements for the power CES purchases during the period net of the gas CES sells to the facilities during the period. CES provides substantially all of the fuel used by the facilities, including fuel consumed to produce power and related products for third parties. While usually in a net receivable position, we could be in a net payable or receivable position at the end of any given period, depending on the fuel consumption used to generate power sold to third-party customers during the applicable period.

Accounts receivable due from CES and other related parties at ~~June~~September 30, 2006, and December 31, 2005, were as follows (in thousands):

	June 30,			December 31,
	September 30,			December 31,
	2006			2005
	(In thousands)
Receivables:
CES	$	~~158~~155,~~221~~639		$	136,219
Net receivable (payable) from affiliates under netting agreement		(3526,~~806~~389	)		(28,448	)
Net receivable from affiliates under netting agreement		~~122~~129,~~415~~250			107,771
Other affiliates		1,~~718~~071			500
Less allowance for doubtful accounts		(102,816	)		(102,816	)
Net accounts receivable – related party	$	2127,~~317~~505		$	5,455

8. Related Party Transactions

Concurrently with the closing of the 2004 Refinancing on March 23, 2004, we entered into various agreements with Calpine affiliates. Under these agreements, the facilities sell power and purchase gas from CES, and other Calpine affiliates provide O&M, major maintenance and administrative services. The agreements between us and CES provide for the netting of payment obligations due and owing to each other, and the related party balances among and between Calpine and its affiliates are netted for presentation purposes in our Consolidated Condensed Financial Statements.

From time to time, we may buy or sell parts, supplies or other inventory items, such as replacement turbine parts, from or to a Calpine affiliate. The parts are transferred at historical cost basis for accounting purposes and settled through cash payments at fair value as required under the Notes and Term Loans. Any differences between the historical cost basis and fair value are recorded as contributions (distributions) of equity.

CalGen is a party to a number of transactions involving intrastate natural gas pipelines in Texas whereby CalGen purchases gas from a third-party, sells the gas to CES at the same price, and then repurchases the gas from CES at the contract price.

Since we terminated certain LTSAs in June 2005, services previously provided under those agreements are now performed by COSCI, a Calpine affiliate, under the Maintenance Agreement.

The net related-party balances as of ~~June~~September 30, 2006, and December 31, 2005, are reflected in the accompanying Consolidated Condensed Balance Sheets and the related-party transactions for the three months and ~~six~~nine months ended ~~June~~September 30, 2006 and 2005, are reflected in the accompanying Consolidated Condensed Statements of Operations.

Index Definitions

9. Derivative Instruments

To manage forward exposure to price fluctuations, we entered into a three-year Index Hedge with MSCG. The Index Hedge provides for semi-annual payments to us if the aggregate spark spread amount calculated under the Index Hedge for any six-month period during the term of the Index Hedge is less than $50.0 million. The semi-annual payment dates are March 31 and September 30, beginning September 30, 2004. Based on the aggregate spark spread calculation, no payment was made to the Company under the Index Hedge for the ~~six~~three and nine months ended ~~June~~September 30, 2006 and 2005. We paid $45.0 million for the Index Hedge at the time of the closing of the 2004 Refinancing. The amount paid includes a value of $38.3 million over the estimated exercise value of the Index Hedge calculated based on our internally developed models. We recorded the valuation difference as a component of derivative assets. In accordance with EITF Issue No. 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” the valuation difference is accounted for as a deferred amount and amortized to income over the term of the Index Hedge. The ~~amount~~amounts amortized (realized expense) for the three and ~~six~~nine months ended ~~June~~September 30, 2006, were $32.09 million and $69.43 million, respectively. The Index Hedge qualifies as a derivative under SFAS No. 133 but does not meet hedge accounting requirements and, therefore, changes in the value are recognized in the Consolidated Condensed Statement of Operations as an unrealized gain or loss. There were unrealized losses from such changes in value of $0.32 million and $1.01 million for the three ~~months~~ and ~~six~~nine months ended ~~June~~September 30, 2006, respectively.

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

	June 30, 2006
	September 30, 2006
Current derivative assets	$	1714,~~202~~093
Long-term derivative assets		—
Total derivative assets	$	1714,~~202~~093

The table below reflects the impact of CalGen’s derivative instruments on its pre-tax earnings from mark-to-market activity of derivatives for the three and six month periods ended ~~June~~September 30, 2006 and 2005, respectively (in thousands):

	Three Months Ended						~~Six~~Nine Months Ended
	June 30,						June 30,
	September 30,						September 30,
	2006			2005			2006			2005
Unrealized mark-to-market loss	$	(~~268~~150	)	$	(49360	)	$	(~~996~~1,146	)	$	(12,~~723~~083	)
Realized mark-to-market loss		(2,959	)		(130	)		(69,~~360~~319	)		(5,~~741~~871	)
Total mark-to-market activity, net	$	(3,~~227~~109	)	$	(~~179~~490	)	$	(710,~~356)~~465	)	$	(7,~~464~~954	)

10. Commitments and Contingencies

Commitments

In addition to the Notes, Term Loans and other financings, we have LTSAs, various operating leases, O&M agreements, and other commitments. Operating leases primarily consist of land leases for certain of the facilities’ sites.

The LTSAs provide for parts and services related to the performance of scheduled maintenance on combustion turbines at the facilities. The terms of the agreements generally cover the period from commercial operation of the project through the twelfth scheduled outage for each combustion turbine. In some agreements, the term is the earlier of sixteen years or twelve scheduled outages. Maintenance schedules and payment schedules under the LTSAs are based on estimates of when maintenance will occur on the various turbines based on the number of hours the turbines operate. The actual timing of maintenance may vary based on actual operating hours and starts versus estimated hours and starts due to operational and performance considerations. LTSAs are in place at the Baytown, Channel, Decatur, ~~Delta~~ and ~~Morgan~~Delta plants.

Index Definitions

Guarantees

In connection with its Chapter 11 cases, Calpine entered into the $2 billion DIP Facility, which was amended and restated as of February 23, 2006. Calpine is the borrower under the DIP Facility, which is guaranteed by all of the other Debtors, including the CalGen Debtors. The DIP Facility will remain in place until the earlier of an effective Calpine plan of reorganization or December 20, 2007. As of ~~June~~September 30, 2006, there was $~~998~~997.34 million outstanding under the DIP Facility term loan facilities, nothing outstanding under the DIP Facility revolving facility, and $11.7 million inof letters of credit had been issued against the revolving facility. As of December 31, 2006, there was $996.5 million outstanding under the DIP Facility term loan facilities, nothing outstanding under the DIP Facility revolving facility and $82.5 million of letters of credit had been issued against the revolving facility. We do not record a liability related to the guarantees because each is a subsidiary’s guarantee of the debt owed to a third party by its parent.

Litigation

As discussed above, the CalGen Debtors filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. As of the Petition Date, most pending litigation (including some of the actions described below) is stayed and, subject to certain exceptions, absent further order of the Bankruptcy Court no party may take any action to recover on pre-petition claims against the CalGen Debtors. One exception to this stay of litigation is actions or proceedings by a governmental agency to enforce its police or regulatory power. The claims asserted in litigation and proceedings to which the stay applies may be fully and finally resolved in connection with the administration of the Chapter 11 cases and, to the extent not resolved, will need to be addressed in the context of any plan or plans of reorganization. At this time, it is not possible to predict the outcome of the Chapter 11 cases or their effect on our business or outstanding legal proceedings.

We are party to various litigation matters arising out of the normal course of business. In the case of all known contingencies, we accrue a liability when the loss is probable and the amount is reasonably estimable. 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 may potentially be material to our financial position, results of operations or cash flows in the period settled. As we learn new facts concerning contingencies, we reassess our position with respect to accrued liabilities and other potential exposures. At present, we do not expect that the outcome of these proceedings will have a material adverse effect on our financial position, results of operations or cash flows.

Estate of Jones, et al. v. Calpine. On June 11, 2003, the Estate of Darrell Jones and the Estate of Cynthia Jones filed a complaint against Calpine in the United States District Court for the Western District of Washington. Calpine purchased Goldendale Energy, Inc., a Washington corporation, from Darrell Jones of NESCO. The agreement provided, among other things, that upon “Substantial Completion” of the Goldendale facility, Calpine would pay Mr. Jones (i) $6.0 million and (ii) $18.0 million less $0.2 million per day for each day that elapsed between July 1, 2002, and the date of substantial completion. Substantial completion of the Goldendale facility occurred in September 2004 and the daily reduction in the payment amount has reduced the $18.0 million payment to zero. The complaint alleged that by not achieving substantial completion by July 1, 2002, Calpine breached its contract with Mr. Jones, violated a duty of good faith and fair dealing, and caused an inequitable forfeiture. On July 28, 2003, Calpine filed a motion to dismiss the complaint for failure to state a claim upon which relief can be granted. The court granted Calpine’s motion to dismiss the complaint on March 10, 2004. Plaintiffs filed a motion for reconsideration of the decision, which was denied. Thereafter, Calpine filed a motion to recover attorneys’ fees from NESCO, which was granted at a reduced amount. Calpine held back $100,000 of the $6.0 million payment to the estates (which has been remitted) to ensure payment of the fees. Plaintiffs appealed. Both parties filed briefs with the appellate court and oral argument was heard on October 17, 2005. The matter was automatically stayed on December 20, 2005. In January, plaintiffs’ filed a motion for relief from stay. On February 21, 2006, the Bankruptcy Court approved the parties’ stipulation lifting the stay for the limited purpose of allowing the appellate court to issue its decision. On March 22, 2006, the appellate court reversed the lower court’s decision and remanded the case to the trial court. The automatic stay prevents further action until lifted.

Index Definitions

Solutia Bankruptcy. Solutia (Decatur’s steam host) and certain of its subsidiaries filed for bankruptcy on December 17, 2003. Effective May 27, 2004, Solutia rejected certain cogeneration agreements relating to the sale of steam and supply of electricity and entered into a term sheet with Decatur confirming the agreement of the parties with respect to property rights going forward. By this term sheet, Decatur has secured all necessary rights to continue operating the plant. The parties entered into an amended and restated agreement setting forth their respective rights and obligations going forward pursuant to the term sheet. The bankruptcy court overseeing Solutia’s bankruptcy cases approved this agreement on June 30, 2004. On November 19, 2004, Decatur and its affiliates filed proofs of claim with the bankruptcy court in Solutia’s bankruptcy cases totaling approximately $383 million. Solutia has formally objected to Decatur’s and its affiliate’s claims. At a hearing on October 19, 2005, the bankruptcy judge overseeing Solutia’s bankruptcy cases ordered the parties to resolve the damage claims by arbitration in accordance with the dispute resolution provisions of the rejected contracts. A panel of three arbitrators has been selected pursuant to applicable arbitration rules. This panel will determine the value of the claims submitted by Decatur and its affiliate. The panel has scheduled the arbitration hearing for August 2007. If the panel enters an award in favor of Decatur and its affiliate, they will not be entitled to immediate payment in cash. Rather, the award will entitle Decatur and its affiliate to an allowed unsecured claim in Solutia’s bankruptcy ~~cases~~case which will be paid on the same terms and conditions as allowed claims of other unsecured creditors of Solutia. Accordingly, it is possible that Decatur and its affiliate will be entitled only to a partial payment of any award, and that such payment will be made in compensation other than cash. It is also possible that Solutia will make no distributions to unsecured creditors and that Decatur and its affiliate will receive nothing on account of their claim.

Panda Energy International, Inc., et al. v. Calpine, et al. On November 5, 2003, Panda filed suit against Calpine and certain of its affiliates in the United States District Court for the Northern District of Texas, alleging, among other things, that defendants breached duties of care and loyalty allegedly owed to Panda by failing to correctly construct and operate the Oneta Energy Center, which Calpine acquired from Panda, in accordance with Panda’s original plans. Panda alleges that it is entitled to a portion of the profits from Oneta Energy Center and that the defendants’ actions have reduced the profits from Oneta Energy Center 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 has not proceeded as the action has been stayed due to the Chapter 11 cases. There has been no activity since the Petition Date.

Delta RMR Proceeding. Through our subsidiary Delta Energy Center, LLC, we are party to a recurring, yearly RMR contract with the CAISO originally entered into in 2003 and renewed for calendar years 2004, 2005 and 2006. The Delta RMR contract was not renewed for calendar year 2007. 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 the this settlement, the parties agreed to interim RMR ~~rates~~ 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 Delta RMR ~~Settlement~~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

Index Definitions

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, Delta, and certain other Calpine entities executed a Settlement and Release of Claims Agreement with the CAISO, the California Electricity Oversight Board and PG&E resolving the claims under the Delta RMR Proceeding. The Settlement and Release of Claims Agreement 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 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 against the Debtors amounting to more than $330 million. Pursuant to the Settlement and Release of Claims Agreement, such claims are required to be withdrawn by PG&E and CAISO within five business days after the Settlement and Release of Claims is approved by FERC and, to the extent necessary, the Bankruptcy Court and the California Public Utilities Commission. On November 15, ~~2006,~~ the Bankruptcy Court granted the Debtor’s motion for approval of the release of the claims pursuant to the Settlement and Release of Claims Agreement. On December 28, 2006, FERC conditionally approved the Settlement and Release of Claims Agreement, subject to the conditions set forth therein, as modified by FERC. On January 12, 2007, the signing parties filed an amendment, which adopted FERC’s conditions. The Settlement and Release Agreement is not effective until the remaining conditions precedent have either been satisfied or waived, including the condition precedent that a California Public Utilities Commission order approving certain agreements between PG&E and certain Calpine subsidiaries is final and non-appealable.

See Note 2 for a description of our Chapter 11 cases.

In addition, we are involved in various other claims and legal actions arising out of the normal course of our business. We do not expect that the outcome of these proceedings will have a material adverse effect on our financial position, results of operations, or cash flows.

11. Guarantor Subsidiaries - Supplemental Consolidating Financial Statements

The Notes and Term Loans issued in connection with the 2004 Refinancing were secured by substantially all of our assets and the assets of the Subsidiary Guarantors. In addition, CalGen Holdings’ membership interest in CalGen and CalGen’s membership interest in CalGen Expansion Company, LLC are pledged as collateral. CalGen Expansion Company, LLC owns, through its direct and indirect wholly owned subsidiaries, 100% of the interests in CalGen’s facilities, including Goldendale. CalGen Holdings has no assets or operations separate from its investment in CalGen. The Notes and Term Loans as discussed in Note 5, are fully and unconditionally guaranteed on a joint and several basis by the Subsidiary Guarantors. Each guarantee is a non-recourse senior secured obligation of the applicable guarantor.

Pursuant to Rule 3-10 of Regulation S-X, CalGen is required to present consolidating financial information with respect to the Subsidiary Guarantors and our subsidiaries other than the Subsidiary Guarantors. Consolidating Condensed Balance Sheets as of ~~June~~September 30, 2006, and December 31, 2005, Consolidating Condensed Statements of Operations for the three and ~~six~~nine months ended ~~June~~September 30, 2006 and 2005 and Consolidating Condensed Statements of Cash Flows for the ~~six~~nine months ended ~~June~~September 30, 2006 and 2005, are presented below.

Index Definitions

CALPINE GENERATING COMPANY, LLC

(a wholly owned subsidiary of Calpine Corporation)

(Debtor-in-Possession)

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

SUPPLEMENTAL CONSOLIDATING CONDENSED BALANCE SHEET

~~June~~September 30, 2006

(Unaudited)

(In thousands)

ASSETS	CalGen			Subsidiary Guarantors		Other Subsidiaries			Consolidating Adjustments			CalGen Consolidated
Current assets:
Cash and cash equivalents	$	~~205~~378,~~480~~367		$	2824	$	3		$	—		$	~~205~~378,~~511~~394
Restricted cash, current		—			2		55			—			57
Accounts receivable, net of allowance of $6,692		2,043			38,157		199			—			40,399
Accounts receivable, net of allowance of $5,284		2,043			37,031		275			—			39,349
Accounts receivable – related party, net of allowance of $102,816		(~~252~~486,~~421~~245	)		~~308~~487,~~679~~819		(3834,~~424~~661	)		360,~~483~~592			2127,~~317~~505
Notes receivable, current portion		—			~~424~~402		—			—			~~424~~402
Inventories		—			2021,~~049~~479		1,068			—			2122,~~117~~547
Current derivative assets		1714,~~202~~093			—		—			—			1714,~~202~~093
Deferred tax asset		—4,025			5,560		—			—(4,025	)		5,560
Prepaid and other current assets		~~896~~1,430			2822,~~849~~558		~~940~~1,344			—			3025,~~685~~332
Total current assets		(2686,~~800~~287	)		~~401~~574,~~748~~875		(3631,~~159~~916	)		356,~~483~~567			~~342~~513,~~272~~239
Property, plant and equipment, net		—			4,~~884~~844,~~754~~478		9089,~~198~~055			—			4,~~974~~933,~~952~~533
Investment in affiliates		2,~~644~~707,~~004~~887			—		—			(2,~~644~~707,~~004~~887	)		—
Notes receivable, net of current portion		—			18,~~760~~646		—			—			18,~~760~~646
Notes receivable, affiliate		2,~~542~~641,~~857~~415			—		—			(2,~~542~~641,~~857~~415	)		—
Restricted cash, net of current portion		—			—		95			—			95
Deferred financing costs, net		3331,~~878~~139			3229,~~323~~710		1,~~555~~429			(3331,~~878~~139	)		3331,~~878~~139
Other assets		30,000			3325,~~985~~522		90			~~(5,169~~—	)		5855,~~906~~612
Total assets	$	5,~~223~~324,~~939~~154		$	5,~~371~~493,~~570~~231	$	5558,~~779~~753		$	(5,~~222~~323,~~425~~874	)	$	5,~~428~~552,~~863~~264
LIABILITIES & MEMBER’S EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	1720,~~985~~754		$	6479,~~590~~402	$	~~112~~1,713		$	—		$	82101,~~687~~869
Notes payable, current		—			~~279~~168		—			—			~~279~~168
Priority notes, term loans and other financings, current		2,510,~~365~~827			2,396,~~336~~777		114,~~029~~050			(2,510,~~365~~827	)		2,510,~~365~~827
Accrued interest payable		6699,~~370~~448			6394,~~329~~885		34,~~041~~564			(6699,~~370~~449	)		6699,~~370~~448
Other current liabilities		—––			~~205~~101		14			—			~~219~~115
Total current liabilities		2,~~594~~631,~~720~~029			2,~~524~~571,~~739~~333		~~117~~120,~~196~~341			(2,~~576~~610,~~735~~276	)		2,~~659~~712,~~920~~427
Notes payable, net of current portion		—			1,~~838~~790		—			—			1,~~838~~790
Deferred tax liability		~~1,046~~––			7990,~~228~~789		65,~~989~~669			(15,~~686~~711	)		8590,~~577~~747
Deferred revenue		—			911,~~997~~003		—			—			911,~~997~~003
Other liabilities		—			26,~~748~~437		—			—			26,~~748~~437
Total liabilities not subject to compromise		2,~~595~~631,~~766~~029			2,~~642~~701,~~550~~352		~~124~~126,~~185~~010			(2,~~578~~615,~~421~~987	)		2,~~784~~842,~~080~~404
Liabilities subject to compromise		—			1516,~~995~~120		615			—			16,~~610~~735
Commitments and contingencies
Member’s equity (deficit)		2,~~628~~693,~~173~~125			2,~~713~~775,~~025~~759		(6967,~~021~~872	)		(2,~~644~~707,~~004~~887	)		2,~~628~~693,~~173~~125
Total liabilities and member’s equity	$	5,~~223~~324,~~939~~154		$	5,~~371~~493,~~570~~231	$	5558,~~779~~753		$	(5,~~222~~323,~~425~~874	)	$	5,~~428~~552,~~863~~264

Index Definitions

CALPINE GENERATING COMPANY, LLC

(a wholly owned subsidiary of Calpine Corporation)

(Debtor-in-Possession)

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

SUPPLEMENTAL CONSOLIDATING CONDENSED BALANCE SHEET

December 31, 2005

(Unaudited)

(In thousands)

ASSETS	CalGen			Subsidiary Guarantors		Other Subsidiaries			Consolidating Adjustments			CalGen Consolidated
	CalGen			Subsidiary Guarantors		Other Subsidiaries			Consolidating Adjustments			CalGen Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	143,427		$	26	$	3		$	—		$	143,456
Restricted cash, current		—			—		55			—			55
Accounts receivable, net of allowance of $4,649		—			70,480		134			—			70,614
Accounts receivable – related party, net of allowance of $102,816		(2,479	)		214,403		321			(206,790	)		5,455
Notes receivable, current portion		—			436		—			—			436
Inventories		—			19,329		1,067			—			20,396
Current derivative assets		16,380			—		—			—			16,380
Deferred tax asset		—			5,055		—			—			5,055
Prepaid and other current assets		497			18,768		216			—			19,481
Total current assets		157,825			328,497		1,796			(206,790	)		281,328
Property, plant and equipment, net		—			4,962,724		90,991			—			5,053,715
Investment in affiliates		2,725,161			—		—			(2,725,161	)		—
Notes receivable, net of current portion		—			18,977		—			—			18,977
Notes receivable, affiliate		2,459,340			—		—			(2,459,340	)		—
Restricted cash, net of current portion		—			—		95			—			95
Deferred financing costs, net		40,043			38,205		1,838			(40,043	)		40,043
Long-term derivative assets		8,178			—		—			—			8,178
Other assets		1,686			31,719		—			(1,686	)		31,719
Total assets	$	5,392,233		$	5,380,122	$	94,720		$	(5,433,020	)	$	5,434,055
LIABILITIES & MEMBER’S EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	188,206		$	67,037	$	52,652		$	(206,790	)	$	101,105
Notes payable, current		—			171		—			—			171
Priority notes, term loans and other financings, current		2,437,982			2,327,872		110,110			(2,437,982	)		2,437,982
Accrued interest payable		61,401			58,586		2,815			(61,401	)		61,401
Other current liabilities		—			1,695		144			—			1,839
Total current liabilities		2,687,589			2,455,361		165,721			(2,706,173	)		2,602,498
Notes payable, net of current portion		—			1,943		—			—			1,943
Deferred tax liability		—			69,577		5,239			(1,686	)		73,130
Deferred revenue		—			8,770		—			—			8,770
Other liabilities		—			17,478		—			—			17,478
Total liabilities not subject to compromise		2,687,589			2,553,129		170,960			(2,707,859	)		2,703,819
Liabilities subject to compromise		—			24,977		615			—			25,592
Commitments and contingencies
Member’s equity (deficit)		2,704,644			2,802,016		(76,855	)		(2,725,161	)		2,704,644
Total liabilities and member’s equity	$	5,392,233		$	5,380,122	$	94,720		$	(5,433,020	)	$	5,434,055

Index Definitions

CALPINE GENERATING COMPANY, LLC

(a wholly owned subsidiary of Calpine Corporation)

(Debtor-in-Possession)

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

SUPPLEMENTAL CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS

For the ~~three~~Three ~~months~~Months ~~ended~~Ended ~~June~~September 30, 2006

(Unaudited)

(In thousands)

	CalGen			Subsidiary Guarantors			Other Subsidiaries			Consolidating Adjustments			CalGen Consolidated
Revenue:
Electricity and steam revenue – related party	$	—		$	~~470~~668,~~029~~202		$	328,~~256~~983		$	—		$	~~473~~697,~~285~~185
Electricity and steam revenue – third party		—			~~107~~114,~~439~~087			~~(60~~77	)		—			~~107~~114,~~379~~164
Total electricity and steam revenue		—			~~577~~782,~~468~~289			329,~~196~~060			—			~~580~~811,~~664~~349
Mark-to-market activity, net		(3,~~227~~109	)		—––			—			—			(3,~~227~~109	)
Other revenue		—			21,~~300~~211			—			—			21,~~300~~211
Total revenue		(3,~~227~~109	)		~~579~~783,~~768~~500			329,~~196~~060			—			~~579~~809,~~737~~451
Cost of revenue:
Plant operating expense		––			4558,~~936~~121			3,~~133~~778			—			4961,~~069~~899
Fuel expense		—			~~418~~538,~~343~~256			119,~~286~~988			—			~~419~~558,~~629~~244
Purchased power expense		—			~~3,648~~428			—			—			~~3,648~~428
Depreciation and amortization expense		—––			3741,~~542~~493			~~141~~987			—			3742,~~683~~480
Total cost of revenue		—––			~~505~~638,~~469~~298			424,~~560~~753			—			~~510~~663,~~029~~051
Gross profit (loss)		(3,227	)		74,299			(1,364	)		—			69,708
Gross profit		(3,109	)		145,202			4,307			—			146,400
Sales, general and administrative expense		269			6,449			(23	)		—			6,695
Long-term service agreement cancellation charge		—			1,500			—			—			1,500
Income (loss) from operations		(3,496	)		67,850			(1,341	)		—			63,013
Sales, general and administrative expense		437			2,351			4			—			2,792
Interest expense – third party		73,354			70,047			3,307			(73,354	)		73,354
Income (loss) from operations		(3,546	)		141,351			4,303			—			142,108
Interest (income)		(74,979	)		(832	)		—			73,354			(2,457	)
Interest expense – third party		73,370			69,972			3,398			(73,370	)		73,370
Equity loss (income) in subsidiaries		12,211			—			—			(12,211	)		—
Interest (income)		(76,266	)		(1,394	)		—			73,370			(4,290	)
Other expense (income), net		(192	)		29			85			—			(78	)
Equity income (expense) in subsidiaries		(63,130	)		—			—			63,130			—
Income (loss) before reorganization items and income taxes		(13,890	)		(1,394	)		(4,733	)		12,211			(7,806	)
Other expense (income), net		(12	)		108			82			—			178
Reorganization items		1,553			—			—			—			1,553
Income (loss) before reorganization items and income taxes		62,492			72,665			823			(63,130	)		72,850
Income (loss) before income taxes		(15,443	)		(1,394	)		(4,733	)		12,211			(9,359	)
Reorganization items		4,111			––			—			—			4,111
Income tax expense		805			4,803			1,281			—			6,889
Income (loss) before income taxes		58,381			72,665			823			(63,130	)		68,739
Net income (loss)	$	(16,248	)	$	(6,197	)	$	(6,014	)	$	12,211		$	(16,248	)
Income tax expense (benefit)		(5,071	)		11,678			(1,320	)		—			5,287
Net income (loss)	$	63,452		$	60,987		$	2,143		$	(63,130	)	$	63,452

Index Definitions

CALPINE GENERATING COMPANY, LLC

(a wholly owned subsidiary of Calpine Corporation)

(Debtor-in-Possession)

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

SUPPLEMENTAL CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS

For the ~~six~~Nine ~~months~~Months ~~ended~~Ended ~~June~~September 30, 2006

(Unaudited)

(In thousands)

	CalGen			Subsidiary Guarantors			Other Subsidiaries			Consolidating Adjustments			CalGen Consolidated
Revenue:
Electricity and steam revenue – related party	$	—		$	~~822~~1,~~077~~490,279		$	1140,~~236~~219		$	—		$	~~833~~1,~~313~~530,498
Electricity and steam revenue – third party		—			~~231~~345,~~657~~744			65142			—			~~231~~345,~~722~~886
Total electricity and steam revenue		—			1,~~053~~836,~~734~~023			1140,~~301~~361			—			1,~~065~~876,~~035~~384
Mark-to-market activity, net		(710,~~356~~465	)		—––			—			—			(710,~~356~~465	)
Other revenue		—			56,~~090~~301			—			—			56,~~090~~301
Total revenue		(710,~~356~~465	)		1,~~058~~842,~~824~~324			1140,~~301~~361			—			1,~~062~~872,~~769~~220
Cost of revenue:
Plant operating expense		—––			82140,~~433~~554			69,~~128~~906			—			88150,~~561~~460
Fuel expense		—			~~791~~1,~~089~~329,345			727,~~376~~364			—			~~798~~1,~~465~~356,709
Purchased power expense		—			12,~~472~~900			—			—			12,~~472~~900
Depreciation and amortization expense		—––			78119,~~044~~537			~~792~~1,779			—			78121,~~836~~316
Total cost of revenue		—––			~~964~~1,~~038~~602,336			1439,~~296~~049			—			~~978~~1,~~334~~641,385
Gross profit (loss)		(710,~~356~~465	)		94239,~~786~~988			(21,~~995~~312	)		—			84230,~~435~~835
Sales, general and administrative expense		734			8,257			40			—			9,031
Long-term service agreement cancellation charge		—			1,500			—			—			1,500
Income (loss) from operations		(8,090	)		86,529			(3,035	)		—			75,404
Sales, general and administrative expense		1,171			10,608			44			—			11,823
Interest expense – third party		142,261			135,825			6,436			(142,261	)		142,261
Income (loss) from operations		(11,636	)		227,880			1,268			—			217,512
Interest (income)		(145,332	)		(1,660	)		—			142,261			(4,731	)
Interest expense – third party		215,631			205,797			9,834			(215,631	)		215,631
Equity loss (income) in subsidiaries		68,917			—			—			(68,917	)		—
Interest (income)		(221,598	)		(3,054	)		—			215,631			(9,021	)
Other expense (income), net		(811	)		510			170			—			(131	)
Equity loss (income) in subsidiaries		5,787			—			—			(5,787	)		—
Income (loss) before reorganization items and income taxes		(73,125	)		(48,146	)		(9,641	)		68,917			(61,995	)
Other expense (income), net		(823	)		618			252			—			47
Reorganization items		1,553			—			—			—			1,553
Income (loss) before reorganization items and income taxes		(10,633	)		24,519			(8,818	)		5,787			10,855
Income (loss) before income taxes		(74,678	)		(48,146	)		(9,641	)		68,917			(63,548	)
Reorganization items		5,664			––			—			—			5,664
Income tax expense		1,046			9,380			1,750			—			12,176
Income (loss) before income taxes		(16,297	)		24,519			(8,818	)		5,787			5,191
Net income (loss)	$	(75,724	)	$	(57,526	)	$	(11,391	)	$	68,917		$	(75,724	)
Income tax expense (benefit)		(4,025	)		21,058			430			—			17,463
Net income (loss)	$	(12,272	)	$	3,461		$	(9,248	)	$	5,787		$	(12,272	)

Index Definitions

CALPINE GENERATING COMPANY, LLC

(a wholly owned subsidiary of Calpine Corporation)

(Debtor-in-Possession)

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

SUPPLEMENTAL CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS

For the ~~three~~Three ~~months~~Months ~~ended~~Ended ~~June~~September 30, 2005

(Unaudited)

(Restated, in thousands)

	CalGen			Subsidiary Guarantors			Other Subsidiaries			Consolidating Adjustments			CalGen Consolidated
Revenue:
Electricity and steam revenue – related party	$	—		$	~~353~~791,~~372~~249		$	822,~~643~~466		$	—		$	~~362~~813,~~015~~715
Electricity and steam revenue – third party		—			~~127~~139,~~150~~765			—			—			~~127~~139,~~150~~765
Total electricity and steam revenue		—			~~480~~931,~~522~~014			822,~~643~~466			—			~~489~~953,~~165~~480
Mark-to-market activity, net		(~~179~~490	)		—			—			—			(~~179~~490	)
Other revenue		—			~~448~~824			—			—			~~448~~824
Total revenue		(~~179~~490	)		~~480~~931,~~970~~838			822,~~643~~466			—			~~489~~953,~~434~~814
Cost of revenue:
Plant operating expense		—			6843,~~324~~091			3,~~229~~646			—			7146,~~553~~737
Fuel expense		—			~~325~~654,~~903~~774			617,~~839~~359			—			~~332~~672,~~742~~133
Purchased power expense		—			2,895			—			—			2,895
Purchased power		—			269			—			—			269
Depreciation and amortization expense		—			4145,~~580~~915			2,~~145~~107			—			4348,~~725~~022
Total cost of revenue		—			~~438~~744,~~702~~049			1223,~~213~~112			—			~~450~~767,~~915~~161
Gross profit (loss)		(~~179~~490	)		42187,~~268~~789			(~~3,570~~646	)		—			38186,~~519~~653
Long-term service agreement cancellation charge		—			23,864			—			—			23,864
Sales, general and administrative expense		345			3,598			172			—			4,115
Sales, general and administrative expense		210			3,148			161			—			3,519
Income (loss) from operations		(835	)		184,191			(818	)		—			182,538
Other operating expense		—			1,500			—			—			1,500
Interest expense – third party		61,358			58,538			2,820			(61,358	)		61,358
Income (loss) from operations		(389	)		13,756			(3,731	)		—			9,636
Interest (income)		(62,464	)		(476	)		—			61,358			(1,582	)
Interest expense – third party		55,308			52,584			2,724			(55,308	)		55,308
Equity loss in subsidiary		(75,152	)		—			—			75,152			—
Interest (income)		(55,436	)		(480	)		—			55,308			(608	)
Other expense (income), net		(89	)		621			67			—			599
Equity loss (income) in subsidiary		28,076			—			—			(28,076	)		—
Income (loss) before income taxes		75,512			125,508			(3,705	)		(75,152	)		122,163
Other expense (income), net		(91	)		607			94			—			610
Income tax expense (benefit)		137			48,070			(1,419	)		—			46,788
Income (loss) before income taxes		(28,246	)		(38,955	)		(6,549	)		28,076			(45,674	)
Net income (loss)	$	75,375		$	77,438		$	(2,286	)	$	(75,152	)	$	75,375
Income tax benefit		(65	)		(14,920	)		(2,508	)		—			(17,493	)
Net income (loss)	$	(28,181	)	$	(24,035	)	$	(4,041	)	$	28,076		$	(28,181	)

Index Definitions

CALPINE GENERATING COMPANY, LLC

(a wholly owned subsidiary of Calpine Corporation)

(Debtor-in-Possession)

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

SUPPLEMENTAL CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS

For the ~~six~~Nine ~~months~~Months ~~ended~~Ended ~~June~~September 30, 2005

(Unaudited)

(Restated, in thousands)

	CalGen			Subsidiary Guarantors			Other Subsidiaries			Consolidating Adjustments			CalGen Consolidated
Revenue:
Electricity and steam revenue – related party	$	—		$	~~683~~1,~~250~~474,499		$	2446,~~091~~557		$	—		$	~~707~~1,~~341~~521,056
Electricity and steam revenue – third party		—			~~240~~379,~~189~~954			—			—			~~240~~379,~~189~~954
Total electricity and steam revenue		—			~~923~~1,~~439~~854,453			2446,~~091~~557			—			~~947~~1,~~530~~901,010
Mark-to-market activity, net		(7,~~464~~954	)		—			—			—			(7,~~464~~954	)
Other revenue		—			12,~~648~~472			—			—			12,~~648~~472
Total revenue		(7,~~464~~954	)		~~925~~1,~~087~~856,925			2446,~~091~~557			—			~~941~~1,~~714~~895,528
Cost of revenue:
Plant operating expense		—			~~108~~151,~~032~~123			610,~~995~~641			—			~~115~~161,~~027~~764
Fuel expense		—			~~648~~1,~~951~~303,725			1835,~~346~~705			—			~~667~~1,~~297~~339,430
Purchased power expense		—			7,313			—			—			7,313
Purchased power		—			7,582			—			—			7,582
Depreciation and amortization expense		—			80126,~~422~~337			36,~~946~~053			—			84132,~~368~~390
Total cost of revenue		—			~~844~~1,~~718~~588,767			2952,~~287~~399			—			~~874~~1,~~005~~641,166
Gross profit (loss)		(7,~~464~~954	)		80268,~~369~~158			(5,~~196~~842	)		—			67254,~~709~~362
Long-term service agreement cancellation charge		—			23,~~864~~860			—			—			23,~~864~~860
Sales, general and administrative expense		~~395~~740			69,~~046~~648			~~329~~501			—			610,~~770~~889
Income (loss) from operations		(7,859	)		50,459			(5,525	)		—			37,075
Income from operations		(8,694	)		234,650			(6,343	)		—			219,613
Interest expense – third party		~~106~~167,~~057~~415			~~100~~159,~~799~~337			58,~~258~~078			(~~106~~167,~~057~~415	)		~~106~~167,~~057~~415
Interest (income)		(~~106~~168,~~494~~958	)		(~~960~~1,436	)		—			~~106~~167,~~057~~415			(12,~~397~~979	)
Equity loss (income) in subsidiary		37,979			—			—			(37,979	)		—
Equity loss in subsidiary		(37,173	)		—			—			37,173			—
Other expense (income), net		(~~168~~257	)		1,~~207~~828			~~184~~251			—			1,~~223~~822
Income (loss) before income taxes		~~(45~~30,~~233~~279	)		~~(50~~74,~~587~~921	)		(1014,~~967~~672	)		(37,~~979~~173	)		~~(68~~53,~~808~~355	)
Income tax benefit		(2,778	)		(19,375	)		(4,200	)		—			(26,353	)
Income tax expense (benefit)		(2,641	)		28,695			(5,619	)		—			20,435
Net income (loss)	$	~~(42~~32,~~455~~920	)	$	~~(31~~46,~~212~~226	)	$	(69,~~767~~053	)	$	(37,~~979~~173	)	$	~~(42~~32,~~455~~920	)

Index Definitions

CALPINE GENERATING COMPANY, LLC

(a wholly owned subsidiary of Calpine Corporation)

(Debtor-in-Possession)

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

SUPPLEMENTAL CONSOLIDATING CONDENSED STATEMENT OF CASH FLOW

For the ~~six~~Nine ~~months~~Months ~~ended~~Ended ~~June~~September 30, 2006

(Unaudited)

(In thousands)

	CalGen			Subsidiary Guarantors			Other Subsidiaries			Consolidating Adjustments			CalGen Consolidated
Cash flows from operating activities:
Net income (loss)	$	(7512,~~724~~272	)	$	~~(57~~3,~~526~~461	)	$	(119,~~391~~248	)	$	685,~~917~~787		$	(7512,~~724~~272	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation and amortization		710,~~090~~291			84129,~~809~~355			12,~~117~~252			(710,~~090)~~291	)		85131,~~926~~607
Deferred income taxes		1(4,~~046~~025	)		920,~~146~~707			~~1,750~~430			—			1117,~~942~~112
Change in derivative assets		710,~~356~~465			—			—			—			710,~~356~~465
Loss on sale of assets		—			1,290			—			—			1,290
Equity loss on subsidiary		685,~~917~~787			—			—			(685,~~917~~787	)		—
Long-term service agreement cancellation charge		—			1,500			—			—			1,500
Change in operating assets and liabilities:
Accounts receivable		(2,043	)		32,323			(65	)		—			30,215
Accounts receivable, net of allowance		(2,043	)		33,449			(141	)		—			31,265
Accounts receivable – related party		22,630			(57,191	)		10,337			8,576			(15,648	)
Accounts receivable – related party, net of allowance		158,643			(236,082	)		5,579			50,024			(21,836	)
Other current assets		(~~399~~933	)		(129,~~909~~704	)		(~~725~~1,129	)		—			(1411,~~033~~766	)
Other assets		1,686			(15,~~819~~840	)		~~(90~~66	)		3(1,~~483~~686	)		35,~~260~~906
Accounts payable and accrued liabilities		2629,~~525~~294			~~(12~~2,~~420~~413	)		~~(1,159~~442	)		—1			1232,~~946~~150
Accrued interest payable		438,~~969~~047			436,~~743~~299			~~226~~1,749			(438,~~969~~048	)		438,~~969~~047
Other accrued liabilities		—			10,~~309~~619			—			—			10,~~309~~619
Net cash provided by operating activities		62234,~~053~~940			~~755~~(853	)		—––			—			62234,~~808~~087
Cash flows from investing activities:
Increase in restricted cash		—			(2	)		—			—			(2	)
(Increase) decrease in restricted cash		—			(2	)		—			—			(2	)
Payment of deferred transmission credits		—			(2,765	)		—			—			(2,765	)
Proceeds from deferred transmission credits		—			46,~~458~~886			—			—			46,~~458~~886
Purchases of property, plant and equipment		—			(23,~~641~~477	)		—––			—			(23,~~641~~477	)
Receipts from notes receivable		—			~~197~~365			—			—			~~197~~365
Net cash used in investing activities	$	—		$	~~(753~~1,007	)	$	—		$	—––		$	~~(753~~1,007	)
Net increase in cash and cash equivalents		62,053			2			—			—			62,055
Cash flows from financing activities:
Repayment on notes payable	$	––		$	(156	)	$	––		$	––		$	(156	)
Net cash used in financing activities		—			(156	)		—			—			(156	)
Net increase in cash and cash equivalents		234,940			(2	)		—			—			234,938
Cash and cash equivalents, beginning of period		143,427			26			3			—			143,456
Cash and cash equivalents, end of period	$	~~205~~378,~~480~~367		$	2824		$	3		$	—		$	~~205~~378,~~511~~394

Index Definitions

CALPINE GENERATING COMPANY, LLC

(a wholly owned subsidiary of Calpine Corporation)

(Debtor-in-Possession)

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

SUPPLEMENTAL CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS

For the ~~six~~Nine ~~months~~Months ~~ended~~Ended ~~June~~September 30, 2005

(Unaudited)

(Restated, in thousands)

	CalGen			Subsidiary Guarantors			Other Subsidiaries			Consolidating Adjustments			CalGen Consolidated
Cash flows from operating activities:
Net income (loss)	$	~~(42~~32,~~455~~920	)	$	~~(31~~46,~~212~~226	)	$	(69,~~767~~053)	)	$	(37,~~979~~173	)	$	~~(42~~32,~~455~~920	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		69,~~625~~499			86135,~~482~~575			46,~~053~~314			(69,~~625)~~499	)		90141,~~535~~889
Deferred income taxes		(2,~~778~~641	)		~~(19~~28,~~375~~695	)		(45,~~200~~619	)		—			~~(26~~20,~~353~~435	)
Change in derivative assets		7,~~464~~954			—			—			—			7,~~464~~954
Equity loss on subsidiary		(37,979	)		—			—			37,979			—
Long-term service agreement cancellation charge		—			23,860			—			—			23,860
Long-term service agreement cancellation charge		—			23,864			—			—			23,864
Equity (income) in subsidiary		(37,173	)		—			—			37,173			—
Change in operating assets and liabilities:
Accounts receivable		(121	)		(6,075	)		18			—			(6,178	)
Accounts receivable, net of allowance		(26,757	)		(10,386	)		(107	)		—			(37,250	)
Accounts receivable – related party		19,833			(11,310	)		6,864			(63,543	)		(48,156	)
Accounts receivable – related party, net of allowance		97,058			(189,686	)		6,025			—			(86,603	)
Other current assets		(~~304~~815	)		~~490~~(1,184	)		(51636	)		—			~~135~~(2,635	)
Other assets		—			54,~~657~~052			—			—			54,~~657~~052
Accounts payable and accrued liabilities		1923,~~871~~872			104,~~722~~219			~~(115~~2,130	)		—			30,~~478~~221
Accrued interest payable		530,~~790~~070			528,~~522~~540			~~268~~1,530			(530,~~790~~070	)		530,~~790~~070
Other accrued liabilities		—			24,~~868~~476			9394			—			24,~~961~~570
Net cash provided by (used in) operating activities		(24,054	)		67,633			163			—			43,742
Net cash provided by operating activities		133,987			74,387			678			(39,569	)		169,483
Cash flows from investing activities:
Increase in restricted cash		—			—			(162	)		—			(162	)
Loans to subsidiaries for project financing		(40,034	)		—			—			40,034			—
Payment of deferred transmission credits		—			(500	)		—			—			(500	)
(Increase) decrease in restricted cash		—			—			(153	)		—			(153	)
Proceeds from deferred transmission credits		—			659			—			—			659
Purchases of property, plant and equipment		465			(76,101	)		(522	)		(465	)		(76,623	)
Purchases of property, plant and equipment		—			(67,630	)		—			—			(67,630	)
Payment of deferred transmission credits		—			(1,481	)		—			—			(1,481	)
Net cash used in investing activities		—			(67,471	)		(162	)		—			(67,633	)
Proceeds from deferred transmission credits		—			3,357			—			—			3,357
Receipts from notes receivable		—			—			—			—			—
Net cash used in investing activities	$	(39,569	)	$	(74,225	)	$	(675	)	$	39,569		$	(74,900	)
Cash flows from financing activities:
Repayment on notes payable	$	—		$	(166	)	$	—		$	—		$	(166	)
Net cash used in financing activities		—			(166	)		—			—			(166	)
Net increase (decrease) in cash and cash equivalents		(24,054	)		(4	)		1						(24,057	)
Net increase in cash and cash equivalents		94,418			(4)			3			—			94,417
Cash and cash equivalents, beginning of period		64,510			28			—			—			64,538
Cash and cash equivalents, end of period	$	40158,~~456~~928		$	24		$	13		$	—		$	40158,~~481~~955

Index Definitions

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 1933 Act and Section 21E of the 1934 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 Chapter 11 cases, including impact on operations; (ii) risks relating to the Chapter 11 cases by Calpine and certain of its affiliates including CES, COSCI and CASCI, which risks include: risks related to the ability of Calpine and its affiliates to continue to perform under the various affiliate agreements, including the Fixed Price and Index Based Agreements, and their ability to attract, retain and motivate key employees who provide services to us; (iii) our and their ability to successfully implement new strategies; (iv) our ability to successfully reorganize and emerge from Chapter 11; (v) our ability to attract and retain customers and counterparties; (vi) our ability to implement our business plan; (vii) financial results that may be volatile and may not reflect historical trends; (viii) our ability to manage liquidity needs and comply with financing obligations; (ix) the direct or indirect effects on our business of our and our affiliates’ (including Calpine’s) impaired credit; (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 the operation of power plants including unscheduled outages of operating plants; (xiii) quarterly and seasonal fluctuations of our results; (xiv) competition; (xv) risks associated with marketing and selling power from plants in the evolving energy markets; (xvi) present and possible future claims, litigation and enforcement actions; (xvii) effects of the application of laws or regulations, including changes in laws or regulations or the interpretation thereof; (xviii) restrictions imposed by the instruments governing our debt, and (xix) other risks identified in this report and the 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 periodic reports 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 and other information regarding issuers that file electronically with the SEC. Our SEC filings, including the exhibits thereto, 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. You may request a copy of our SEC filings, at no cost to you, by writing or telephoning us care of: 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.

Overview

We are a Delaware limited liability company and an indirect wholly owned subsidiary of Calpine. We are engaged, through our subsidiaries, in the ownership and operation of power generation facilities and the sale of energy, capacity and related products in the United States of America. We indirectly own 14 power generation facilities that have an aggregate combined estimated peak capacity of 9,815 MW (nominal 8,416 MW without peaking capacity). Our aggregate combined estimated peak capacity represents approximately 37.1% of Calpine’s 26,459 MW of aggregate estimated peak capacity in operation at ~~June~~September 30, 2006. Thirteen of our facilities are natural gas-fired combined cycle facilities, and the fourteenth, our Zion facility, is a natural gas-fired simple cycle facility. As of ~~June~~September 30, 2006, all 14 of our facilities were operating.

Index Definitions

Our revenues are generated from the sale of electrical capacity and energy together with a by-product, steam, through a series of agreements with third parties and through the Fixed Price and Index Based Agreements with CES, which were entered into in connection with the 2004 Refinancing on March 23, 2004. Under the Fixed Price and Index Based Agreements, CES purchases a portion of our energy at a fixed price and all of our remaining energy (after sales pursuant to our third-party agreements) at floating prices based on day-ahead energy and gas prices.

Currently, we continue to conduct business in the ordinary course as debtors-in-possession under the protection of the Bankruptcy Court. Accordingly, a substantial amount of the resources available to us are being devoted to our Chapter 11 restructuring in conjunction with the Chapter 11 restructuring of the other Debtors, which includes developing a plan of reorganization and a new business plan, as well as resolving claims disputes, addressing various 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.

We are largely dependent upon the plans and actions taken by Calpine, through its Chapter 11 restructuring to develop, implement and approve a plan of reorganization that will strengthen and improve our financial health and permit us to emerge from Chapter 11. Four of our power plants are identified for possible sale by Calpine. They are the Carville, Columbia, Decatur and Goldendale facilities. CES currently is our primary customer and primary fuel supplier. CES purchases the majority of the electricity produced by our facilities, and supplies the majority of all of the natural gas needed to operate our facilities, under the Fixed Price and Index Based Agreements. Should CES reject the Fixed Price or Index Based Agreements, or both, in the Chapter 11 cases, it could have a material adverse impact on our ability to continue to operate as a going concern. If CES were to reject either or both of the agreements, we plan to continue to sell power to CES under another contract or identify other potential customers and enter into alternative arrangements. COSCI, which is a Debtor and a wholly owned direct subsidiary of Calpine, acts as our primary operator for our plants under the Maintenance Agreement and the O&M Agreement. Should COSCI reject the Maintenance Agreement or the O&M Agreement, or both, we would seek similar operating agreements from COSCI or other providers. There is no assurance that we can negotiate other arrangements related to the above on acceptable terms.

In addition, the Bankruptcy Court approved cash collateral and adequate assurance stipulations in connection with the approval of the DIP Facility (discussed below under “— Liquidity and Capital Resources,” which has allowed Calpine’s, as well as our own, business activities to continue to function. We have also sought and obtained 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, and maintain our insurance programs, which has allowed us to continue to operate the existing business in the ordinary course of business. In addition, the Bankruptcy Court has approved certain trading notification and transfer procedures designed to allow Calpine to restrict trading in its common stock (and related securities) and, currently on an interim basis only, trading in its claims which could negatively impact our accrued 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 or plans of reorganization.

Index Definitions

See Note 2 of the Notes to Consolidated Condensed Financial Statements for more information regarding our Chapter 11 cases.

All amounts in this Management’s Discussion and Analysis of Financial Condition and Results of Operations reflect the restatement discussed below and in Note 3 of the Notes to Consolidated Condensed Financial Statements. See “— Liquidity and Capital Resources” below for discussion of the financial challenges facing CalGen.

Restatement

Income taxes — We determined that deferred tax liabilities should have been allocated to us related to certain plant assets contributed by Calpine to us via the transfer of Calpine’s equity ownership interest therein. These assets had been acquired by Calpine in a transaction that resulted in a step-up in the book basis of the assets to the purchase price values but for which a step-up of the tax basis of the assets is not allowed. The resultant deferred tax liabilities totaling $175.1 million should have been pushed down to our books when Calpine transferred the assets to us to account for the difference in the book and tax basis of the assets. Instead, we initially recorded amounts related to these deferred tax liabilities as subordinated debt owed to Calpine, which was later converted to equity invested in us by Calpine at the time of the 2004 Refinancing, consummated on March 23, 2004, of our $2.5 billion construction credit agreement. As a result of these errors, changes in deferred tax liabilities were not reflected in the periodic income tax provision from 2000 through 2004 and valuation allowances were established against deferred tax assets associated with net operating losses that would not have been necessary had the full amount of deferred tax liabilities been taken into account. Amounts reported for net deferred income tax liabilities was understated by $350.76 million as of ~~June~~September 30, 2005, and net ~~loss~~income was overstated for income tax ~~benefits~~expense not recognized in the amount of $1746.58 million ~~for the three months ended June 30, 2005~~ and $2620.4 million for the ~~six~~three months and nine months ended ~~June~~September 30, 2005, respectively. Accordingly, we restated our Consolidated Condensed Statement of Operations for the three and nine months ended September 30, 2005, and our Consolidated Condensed Statement of Cash Flows for the ~~three~~nine months ~~and six months~~ ended ~~June~~ September 30, 2005, to correct this error.

Fuel expense — We determined through our intercompany reconciliation procedures that we overpaid CES by $47.9 million and $18.6 million for fuel expenses during the three months ~~ended June 30, 2005~~ and ~~$10.7~~nine ~~million during the three~~ months ended ~~June~~September 30, 2005, respectively. The error was the result of failure to deduct fuel quantities provided directly to our Channel and Corpus Christi facilities by unrelated parties (the steam hosts) when calculating CES’ net payment to us for power generated net of fuel cost. We include all fuel quantities used by the plant in our calculation of fuel cost netted with power sales to CES unless the fuel quantities are provided by unrelated parties. Failure to deduct these quantities from our calculation of fuel cost resulted in a lower net payment received from CES and a corresponding overstatement of fuel expense. Accordingly, we restated fuel expenses by recording a reduction of $47.69 million and $1018.76 million in fuel expense for the three months and ~~six~~nine months ended ~~June~~September 30, 2005, respectively.

Deferred transmission credits — We determined that we incorrectly classified $01.5 million in payments made for point-to-point deferred transmission credits and $03.74 million in reimbursement in payments received for point-to-point deferred transmission credits in our Consolidated Condensed Statement of Cash Flows for the ~~six~~nine months ended ~~June~~September 30, 2005. The amounts were previously included in cash flows from operating activities within changes in prepaid assets (in changes in operating assets and liabilities). We have determined that these pre-payments made, and receipt of payments, for transmission rights had more of the characteristics of investing cash flows than operating cash flows due to their nature and longer term and therefore should have been included in cash flows from investing activities. We restated our Consolidated Condensed Statements of of Cash Flows for the ~~six~~nine months ended ~~June~~September 30, 2005, to properly classify such amounts.

Index Definitions

corrected. Accordingly, we restated herein our Consolidated Condensed Statement of Operations for the three months ended June 30, 2005 in the amount of $(1.5) million to correct such errors.

Results of Operations

Three Months Ended ~~June~~September 30, 2006, Compared to Three Months Ended ~~June~~September 30, 2005

In the comparative tables below, increases in revenue/income or decreases in expense (for favorable variances) are shown without brackets. Decreases in revenue/income or increase in expense (unfavorable variances) are shown with brackets (in millions, except for percentages).

	Three Months Ended June 30,
	Three Months Ended September 30,
	2006			2005 ~~(Restated)~~			$ Change			% Change
					(Restated)
Revenue:
Electricity and steam revenue – related party	$	~~473~~697,~~285~~185		$	~~362~~813,~~015~~715		$	~~111~~(116,~~270~~530	)		30(14.73	)%
Electricity and steam revenue – third party		~~107~~114,~~379~~164			~~127~~139,~~150~~765			(1925,~~771~~601	)		(1518.53	)
Mark-to-market activity, net		(3,~~227~~109	)		(~~179~~490	)		(32,~~048~~619	)		(#	)
Other Revenue		2,300			448			1,852			#
Other revenue		1,211			824			387			47.0
Total revenue		~~579~~809,~~737~~451			~~489~~953,~~434~~814			90(144,~~303~~363	)		18(15.51	)
Cost of revenue:
Plant operating expense		4961,~~069~~899			7146,~~553~~737			22(15,~~484~~162	)		31(32.4	)
Fuel expense		~~419~~558,~~629~~244			~~332~~672,~~742~~133			~~(86~~113,~~887~~889	)		~~(26~~16.19	)
Purchased power expense		~~3,648~~428			~~2,895~~269			(~~753~~159	)		(2659.01	)
Depreciation and amortization expense		3742,~~683~~480			4348,~~725~~022			65,~~042~~542			1311.85
Total cost of revenue		~~510~~663,~~029~~051			~~450~~767,~~915~~161			~~(59~~104,~~114~~110	)		(13.16	)
Gross profit		69146,~~708~~400			38186,~~519~~653			31(40,~~189~~253	)		81(21.06	)
LTSA cancellation		—1,500			~~23,864~~—			23(1,~~864~~500)			(#	)
Sales, general and administrative expense		62,~~695~~792			34,~~519~~115			(31,~~176~~323	)		~~(90~~32.32	)
Other operating expense		—			1,500			1,500			#
Income from operations		142,108			182,538			(40,430	)		(22.1	)
Income from operations		63,013			9,636			53,377			#
Interest expense – third party		73,370			61,358			(12,012	)		(19.6	)
Interest expense – third party		73,354			55,308			(18,046	)		(32.6	)
Interest (income)		(4,290	)		(1,582	)		2,708			#
Interest (income)		(2,457	)		(608	)		1,849			#
Reorganization items		4,111			—			(4,111	)		(#	)
Other (income) expense, net		~~(78~~178	)		~~610~~599			~~688~~421			#70.3
Reorganization items		1,553			—			(1,553	)		#
Income before income taxes		68,739			122,163			(53,424	)		(43.7	)
Loss before income taxes		(9,359	)		(45,674	)		36,315			79.5
Income tax expense		5,287			46,788			41,501			88.7
Income tax expense (benefit)		6,889			(17,493	)		(24,382	)		#
Net Income	$	63,452		$	75,375		$	(11,923	)		(15.8	)
Net loss	$	(16,248	)	$	(28,181	)	$	11,933			42.3	%

____________

#	Variance of 100% or greater

~~The~~Electricity ~~overall~~and ~~increase~~steam in revenue ~~was~~decreased ~~due primarily to a 30.5% increase in MWh generated from 5,991 MWh~~ for the three months ended ~~June~~September 30, ~~2005 to 7~~2006,~~819~~ ~~MWh~~compared ~~for~~to the three months ended ~~June~~September 30, ~~2006. Electricity~~2005, ~~and~~due ~~steam~~primarily ~~revenue~~to ~~increased~~a asdecrease wein ~~completed~~our ~~construction~~average ~~and~~all-in ~~brought~~realized ~~into~~electric ~~operation~~price ~~the~~from ~~Pastoria facility in May 2005~~$92.60 ~~New~~for ~~revenue~~the ~~generated~~three atmonths ~~our~~ended ~~Pastoria~~September 30, ~~facility~~2005, ~~contributed~~to $4370.755 ~~million,~~for orthe ~~nearly~~three ~~half,~~months ofended ~~the~~September 30, ~~total increase~~2006. ~~Additional~~The ~~increases~~decrease in ~~revenue~~average ofall-in ~~$30.3~~electric ~~million~~price ~~and~~was ~~$29.6~~largely ~~million~~attributable ~~were~~to ~~also~~lower ~~recorded~~average atfuel ~~our Decatur and Morgan facilities~~prices, ~~respectively.~~which ~~The~~decreased ~~higher revenue at~~ the ~~Morgan~~indexed ~~and~~energy ~~Decatur~~component ~~facilities is primarily the result~~ of ~~increased~~our ~~dispatch~~electric byrevenues from CES. ~~resulting~~This ~~from~~was apartially ~~tolling~~offset ~~agreement~~by ~~between~~an ~~CES~~11.7% ~~and~~increase ~~the~~in ~~Tennessee~~generation ~~Valley~~from ~~Authority~~10,294 ~~which~~MWh ~~became~~to ~~effective~~11,495 ~~in September 2005~~MWh.

Plant operating expense ~~decreased~~increased ~~due~~for to the ~~non-reoccurrence~~three ofmonths ~~$9.2~~ended ~~million~~September 30, ~~and~~2006, ~~$5.0~~compared ~~million in equipment repair costs related~~ to ~~unplanned outages recorded in~~ the three months ended ~~June~~September 30, 2005 ~~for the Corpus Christi and Channel facilities~~, ~~respectively. Also~~primarily ~~contributing~~due to ~~the~~increased ~~decrease~~maintenance ~~was~~for ~~the~~both ~~non-reoccurrence of $2.7 million in~~ planned ~~maintenance at the Channel facility in the second quarter of 2005~~ and ~~$2.6~~unplanned ~~million~~outages ~~in expenses incurred~~ at the Morgan facility ~~associated with a contract with BP Amoco which expired in December 2005~~.

Fuel expense decreased for the three months ended September 30, 2006, compared to three months ended September 30, 2005, primarily due to decreases in fuel prices. Our average cost of natural gas per MMBtu decreased 25.3% from $8.42 to $6.29. The decrease in fuel expense due to lower natural gas prices was partially offset by increased consumption due higher generation as discussed above.

Depreciation expense decreased for the three months ended September 30, 2006, compared to the three months ended September 30, 2005, due to power asset impairment charges of approximately $1.2 billion recognized in the three months

Index Definitions

~~Fuel expense increased for the three months~~ ended ~~June~~December 3031, ~~2006 compared to the three months ended June 30,~~ 2005 ~~primarily due to increased generation at the Pastoria, Morgan and Decatur facilities~~. ~~Gas~~Total ~~prices~~depreciation ~~remained~~expense ~~relatively~~related ~~unchanged compared~~ to the ~~corresponding~~four ~~period~~facilities inthat ~~2005~~were asimpaired ~~our average cost of natural gas~~ decreased ~~$0.01/MMBtu~~by ~~from~~approximately $6.591 ~~MMBtu for the three months ended June 30, 2005 to $6~~million.~~58 MMBtu for the three months ended June 30, 2006.~~

~~Depreciation~~Sales, ~~expense~~general ~~decreased~~and ~~for~~administrative ~~the~~expense, ~~three~~which ~~months~~includes ~~ended~~allocations ~~June 30~~from Calpine, ~~2006~~decreased ~~compared~~for to the three months ended ~~June~~September 30, ~~2005~~2006, ~~due~~compared to ~~power asset impairment charges of approximately $1.2 billion recognized in~~ the three months ended ~~December~~September 3130, 2005~~. This~~, ~~was~~due ~~partially offset by depreciation related~~ to ~~the~~lower ~~Pastoria~~allocations ~~facility,~~from ~~which was brought into operation in May 2005~~Calpine.

~~LTSA~~Interest ~~cancellation~~expense-third-party ~~costs~~increased ~~decreased~~primarily ~~for~~due ~~the~~to ~~three~~increases ~~months~~in ~~ended~~interest ~~June 30,~~rates ~~2006~~on ~~compared to~~ the ~~three~~Notes ~~months~~and ~~ended~~Term ~~June 30~~Loans, ~~2005.~~which Inpredominantly ~~June 2005,~~carry wefloating ~~canceled~~interest ~~long-term~~rates, ~~service~~and ~~agreements~~usage atof ~~Carville,~~$112.3 ~~Corpus~~million ~~Christi,~~in ~~Freestone,~~2006 ~~Los~~under ~~Medanos,~~the ~~Oneta~~Revolving ~~and~~Credit ~~Zion,~~Facility ~~and~~which wehad ~~recorded~~no abalances ~~cost~~in ~~of $23~~2005.5 ~~million~~Our asweighted aaverage ~~result~~interest ofrate ~~these~~increased ~~cancellations~~to 11.3% Nofrom ~~LTSAs~~9.6% ~~were~~for ~~canceled~~the innine months ended September 30, 2006, compared to the ~~three~~nine months ended ~~June~~September 30, ~~2006~~2005.

~~Sales,~~Interest ~~general~~income ~~and administrative expense, which includes an allocation from Calpine,~~ increased ~~for~~primarily ~~the~~due ~~three months ended June 30, 2006 compared~~ to the ~~three~~increase ~~months~~of ~~ended~~our ~~June 30,~~average ~~2005~~cash ~~due~~balances toand ~~increased~~interest ~~costs~~rates ~~incurred~~thereon byin ~~Calpine~~the ~~relating~~third toquarter ~~our~~of ~~facilities and associated with our Chapter 11 cases~~2006.

~~Interest~~Reorganization ~~expense~~items –were ~~third-party~~incurred ~~increased primarily due to increases~~ in ~~interest~~the ~~rates~~three ~~paid~~months onended ~~the~~September 30, ~~Notes~~2006, ~~Term~~while ~~Loans~~no ~~and~~similar ~~Revolving~~costs ~~Credit~~were ~~Facility,~~incurred ~~which~~in ~~predominantly~~the ~~carry~~same ~~variable~~period ~~interest~~a ~~rates~~year ago. ~~Additionally,~~Reorganization ~~part~~items ofrepresent ~~the~~direct ~~increase~~and isincremental ~~due~~costs toassociated ~~Pastoria’s~~with ~~commencement~~our ~~of commercial operations in May~~Chapter ~~2005,~~11 atcases. ~~which~~During ~~time~~the ~~capitalization~~three ofmonths ~~interest~~ended ~~expense~~September 30, at2006, ~~that~~we ~~facility~~incurred ~~ceased~~$1.2 ~~Also~~million ~~contributing~~in tolegal ~~the~~fees ~~increase~~and ~~was~~$2.9 ~~higher~~million ~~average~~in ~~debt~~financial ~~balances~~advisory ~~under~~and ~~the~~consulting ~~Revolving Credit Facility, which had no balances in 2005~~fees.

Interest income increased primarily due to the increase of our average cash balances and interest rates thereon for the three months ended June 30, 2006 compared to the same period in 2005.

Reorganization items were incurred in the three months ended June 30, 2006 while no similar costs were incurred in the same period a year ago. Reorganization items represent direct and incremental costs associated with our Chapter 11 cases. During the three months ended June 30, 2006, we incurred $1.0 million in legal fees and $0.5 million in financial advisory and consulting fees.

The increase in income tax expense was due primarily to the increase of deferred tax liabilities associated with temporary property differences (primarily depreciation expense) that was not offset due to valuation allowances recorded against deferred tax assets.

Six Months Ended June 30, 2006, Compared to Six Months Ended June 30, 2005

Index Definitions

	Six Months Ended June 30,
	2006			2005 (Restated)			$ Change			% Change
Revenue:
Electricity and steam revenue – related party	$	833,313		$	707,341		$	125,972			17.8	%
Electricity and steam revenue – third party		231,722			240,189			(8,467	)		(3.5	)
Mark-to-market activity, net		(7,356	)		(7,464	)		108			1.4
Other Revenue		5,090			1,648			3,442			#
Total revenue		1,062,769			941,714			121,055			12.9
Cost of revenue:
Plant operating expense		88,561			115,027			26,466			23.0
Fuel expense		798,465			667,297			(131,168	)		(19.7	)
Purchased power expense		12,472			7,313			(5,159	)		(70.5	)
Depreciation and amortization expense		78,836			84,368			5,532			6.6
Total cost of revenue		978,334			874,005			(104,329	)		(11.9	)
Gross profit		84,435			67,709			16,726			24.7
LTSA cancellation		—			23,864			23,864			#
Sales, general and administrative expense		9,031			6,770			(2,261	)		(33.4	)
Income from operations		75,404			37,075			38,329			#
Interest expense – third party		142,261			106,057			(36,204	)		(34.1	)
Interest (income)		(4,731	)		(1,397	)		3,334			#
Reorganization items		1,553			—			(1,553	)		#
Other (income) expense, net		(131	)		1,223			1,354			#
Loss before income taxes		(63,548	)		(68,808	)		5,260			7.6
Income tax expense (benefit)		12,176			(26,353	)		(38,529	)		#
Net loss	$	(75,724	)	$	(42,455	)	$	(33,269	)		(78.4	)

Nine Months Ended September 30, 2006, Compared to Nine Months Ended September 30, 2005

	Nine Months Ended September 30,
	2006			2005			$ Change			% Change
					(Restated)
Revenue:
Electricity and steam revenue – related party	$	1,530,498		$	1,521,056		$	9,442			0.6	%
Electricity and steam revenue – third party		345,886			379,954			(34,068	)		(9.0	)
Mark-to-market activity, net		(10,465	)		(7,954	)		(2,511	)		(31.6	)
Other Revenue		6,301			2,472			3,829			#
Total revenue		1,872,220			1,895,528			(23,308	)		(1.2	)
Cost of revenue:
Plant operating expense		150,460			161,764			11,304			7.0
Fuel expense		1,356,709			1,339,430			(17,279	)		(1.3	)
Purchased power expense		12,900			7,582			(5,318	)		(70.1	)
Depreciation and amortization expense		121,316			132,390			11,074			8.4
Total cost of revenue		1,641,385			1,641,166			(219	)		(0.0	)
Gross profit		230,835			254,362			(23,527	)		(9.2	)
LTSA cancellation		1,500			23,860			22,360			93.7
Sales, general and administrative expense		11,823			10,889			(934	)		(8.6	)
Income from operations		217,512			219,613			(2,101	)		(1.0	)
Interest expense – third party		215,631			167,415			(48,216	)		(28.8	)
Interest (income)		(9,021	)		(2,979	)		6,042			#
Reorganization items		5,664			—			(5,664	)		(#	)
Other (income) expense, net		47			1,822			1,775			97.4
Income before income taxes		5,191			53,355			(48,164	)		(90.3	)
Income tax expense		17,463			20,435			2,972			14.5
Net (loss) income	$	(12,272	)	$	32,920		$	(45,192	)		(#	)

____________

#	Variance of 100% or greater

~~The~~Revenues ~~overall~~remained ~~increase~~relatively inflat ~~revenue was due primarily to a 10.2% increase in MWh generated from 12,574 MWh~~ for the ~~six~~nine months ended ~~June~~September 30, ~~2005 to 13~~2006,~~858~~ ~~MWh~~compared ~~for~~to the ~~six~~nine months ended ~~June~~September 30, ~~2006.~~2005, ~~Electricity~~decreasing ~~and~~approximately ~~steam~~$23.3 ~~revenue~~million. ~~increased~~Our asgeneration weincreased ~~completed~~10.9% ~~construction~~from ~~and~~22,868MW ~~brought into operation the Pastoria facility~~ in ~~May~~ 2005. ~~New~~to ~~revenue~~25,354MW ~~generated~~for ~~at our Pastoria facility contributed $103~~2006.4 ~~million~~However, of the ~~total~~ increase. ~~Additional increases~~ in ~~revenue~~generation ofwas ~~$58.2~~offset ~~million~~by ~~and~~decreased ~~$36.5~~natural ~~million~~gas ~~were~~index ~~recorded~~prices, bywhich decreased the ~~Morgan~~indexed ~~and~~energy ~~Decatur~~component ~~facilities,~~of ~~respectively.~~our ~~The~~electric ~~higher~~revenues ~~revenue~~from atCES under the ~~Morgan~~Index ~~and~~Based ~~Decatur~~Agreement. ~~facilities~~As isa ~~the~~ result ofwe ~~increased~~experienced ~~dispatch~~a bydecrease ~~CES~~in ~~resulting~~our ~~from~~average aall-in ~~tolling~~realized ~~agreement~~electricity ~~between~~price ~~CES~~from ~~and~~$83.04/MWh ~~the~~in ~~Tennessee~~2005 ~~Valley~~to ~~Authority~~$73.50/MWh ~~which became effective~~ in ~~September 2005~~2006.

Other revenue increased by $3.48 million for the ~~six~~nine months ended ~~June~~September 30, 2006, compared to the ~~six~~nine months ended ~~June~~September 30, 2005, primarily from the sale of purchased gas to CES by our Columbia facility. This excess fuel was previously used to generate steam, which iswas sold to Eastman Chemical Company; however, Eastman Chemical Company now provides the fuel, which Columbia uses to generate the steam. ~~The~~Any excess fuel is now sold to CES.

Plant operating expense decreased for the nine months ended September 30, 2006, compared to the nine months ended September 30, 2005, due, in part, to the non- reoccurrence of $9.25 million and $511.03 million in ~~equipment~~property ~~repair~~claims ~~costs~~at ~~related~~the toChannel ~~unplanned~~and ~~outages~~Corpus ~~recorded~~facilities in ~~the six months ended June 30,~~ 2005 ~~for the Corpus Christi~~ and ~~Channel~~due ~~facilities, respectively. Also contributing~~ to ~~the decrease was the non-reoccurrence of~~ $24.71 million in ~~planned~~insurance ~~maintenance~~proceeds atreceived in the ~~Channel~~first ~~facility~~quarter ~~incurred~~of in2006. ~~the~~This ~~second~~decrease ~~quarter~~was ofpartially ~~2005~~offset ~~and~~by ~~$4.1~~increased ~~million~~maintenance inexpense ~~insurance~~at ~~proceeds~~the ~~received~~Morgan facility in the ~~first~~third quarter of 2006.

Fuel expense increased for the ~~six~~nine months ended ~~June~~September 30, 2006, compared to the ~~six~~nine months ended ~~June~~September 30, 2005, ~~due~~ primarily due to increased ~~generation~~consumption atresulting ~~the~~from ~~Pastoria,~~higher ~~Morgan~~generation ~~and~~as ~~Decatur~~discussed ~~facilities~~above. ~~Additionally,~~This ~~our~~was ~~average~~partially ~~gas~~offset ~~price~~by ~~increased~~decreases byin $0fuel prices.~~53/MMBtu~~ ~~from~~Our ~~$6.42~~average ~~MMBtu~~cost ~~for~~of ~~the~~natural ~~six~~gas ~~months~~per ~~ended~~MMBtu ~~June 30,~~decreased ~~2005~~8.6% tofrom $67.9529 ~~MMBtu~~to ~~for the six months ended June 30, 2006~~$6.66.

Index Definitions

Purchased power expense increased ~~by $5.2 million~~ for the ~~six~~nine months ended ~~June~~September 30, 2006, compared to the ~~six~~nine months ended ~~June~~September 30, 2005, as we purchased more replacement power to meet contractual sales requirements resulting from planned and unplanned outages at our Baytown and Channel facilities in the first and second quarters of 2006.

Depreciation expense decreased for the ~~six~~nine months ended ~~June~~September 30, 2006, compared to the ~~six~~nine months ended ~~June~~September 30, 2005, due to power asset impairment charges of approximately $1.2 billion recognized in the three months ended December 31, 2005. Total depreciation expense related to these facilities decreased by approximately $23.9 million. This was partially offset by increased depreciation of $8.8 million related to the Pastoria facility, which was brought into operation in May 2005 as well as smaller increases at other plants.

LTSA cancellation costs decreased for the ~~six~~nine months ended ~~June~~September 30, 2006, compared to the ~~six~~nine months ended ~~June~~September 30, 2005~~. In June 2005~~, as we ~~canceled~~cancelled ~~long-term~~LTSA ~~service~~ agreements with General Electric International, Inc. at our Carville, Corpus Christi, Freestone, Los Medanos, ~~Oneta~~ and Zion, ~~and~~facilities wein ~~recorded~~2005 aresulting ~~cost~~in cancellation charges of $23.59 million. asIn athe ~~result~~three ofmonths ~~these~~ended ~~cancellations.~~September 30, No2006, ~~LTSAs~~we ~~were~~cancelled ~~canceled~~our inLTSA ~~the~~agreement ~~six~~with ~~months~~Siemens ~~ended~~Westinghouse ~~June 30,~~for ~~2006~~our Morgan facility and recorded a cancellation charge of $1.5 million.

~~Sales,~~Interest ~~general~~expense - third-party increased primarily due to increases in interest rates paid on the Notes and ~~administrative~~Term ~~expense~~Loans, which ~~includes~~predominantly ancarry ~~allocation~~floating ~~from~~interest ~~Calpine~~rates. During 2006, our weighted average interest rate increased ~~for~~from ~~the~~9.4% ~~six~~in ~~months~~2005 ~~ended~~to ~~June 30,~~10.9% in 2006. ~~compared~~Additionally, topart of the ~~six~~increase ~~months~~is ~~ended~~due ~~June~~to (a) Pastoria’s commencement of commercial operations in May 302005, ~~2005~~at ~~due~~which totime ~~increased~~capitalization ~~costs~~of ~~incurred~~interest byexpense ~~Calpine~~at ~~relating~~that tofacility ~~our~~ceased ~~facilities~~ and ~~associated~~(b) ~~with~~usage ~~our~~in ~~Chapter 11~~2006 ~~cases~~of $112.3 million under the Revolving Credit Facility, which had no outstanding balances in 2005.

Interest ~~expense~~income ~~– third-party~~ increased primarily due to ~~increases in interest rates paid on~~ the ~~Notes, Term Loans and Revolving Credit Facility, which predominantly carry variable interest rates. Additionally, part of the~~ increase ~~is due to Pastoria’s commencement~~ of ~~commercial~~our ~~operations~~average incash ~~May 2005,~~balances atand ~~which time capitalization of~~ interest ~~expense~~rates atthereon ~~that~~compared ~~facility ceased. Also contributing~~ to the ~~increase~~same ~~was~~period ~~higher average debt balances~~ in ~~2006 under the Revolving Credit Facility, which had no balances in~~ 2005.

~~Interest~~Reorganization ~~income~~items ~~increased~~were ~~primarily~~incurred ~~due~~in tothe nine months ended September 30, 2006, while no similar costs were incurred in the ~~increase~~same ofperiod ~~our~~a ~~average~~year ~~cash~~ago. ~~balances~~Reorganization items represent direct and ~~interest~~incremental ~~rates~~costs ~~thereon~~associated ~~for~~with our Chapter 11 cases. During the ~~six~~nine months ended ~~June~~September 30, 2006, ~~compared~~we toincurred ~~the~~$2.3 ~~same~~million ~~period~~in legal fees and $3.4 million in ~~2005~~financial advisory and consulting fees.

~~Reorganization~~Income ~~items~~tax ~~were~~expense ~~incurred~~decreased incompared to the ~~six~~same ~~months~~period ~~ended~~in ~~June 30,~~2005. ~~2006~~The ~~while~~decrease nois ~~similar~~due ~~costs~~to ~~were~~lower ~~incurred~~taxable inincome ~~the~~partially ~~same~~offset ~~period~~by aan ~~year~~increase ~~ago. Reorganization~~of ~~items~~deferred ~~represent~~tax ~~direct~~liabilities ~~and incremental costs~~ associated with ~~our~~temporary ~~Chapter 11~~property ~~cases.~~differences ~~During~~(primarily ~~the~~depreciation ~~six~~expense) ~~months~~that ~~ended~~was ~~June 30,~~not ~~2006,~~offset wedue ~~incurred~~to ~~$1.0~~valuation ~~million~~allowances inrecorded ~~legal~~against ~~fees~~deferred ~~and~~tax $0assets.~~5 million in financial advisory and consulting fees.~~

Liquidity and Capital Resources

Currently, we continue to conduct our business as debtors-in-possession under the jurisdiction of the Bankruptcy Court while a plan or plans of reorganization are developed. In general, as debtors-in-possession, we are authorized to continue to operate our business in the ordinary course, but may not engage in transactions outside the ordinary course of business without the prior approval of the Bankruptcy Court. Accordingly, the matters described in this section may be significantly affected by our Chapter 11 cases, the Chapter 11 cases of the other Debtors and by the risks and other factors described in “Forward-Looking Statements” above, including the risk factors included in Item 1A. “Risk Factors” in our 2005 Form 10-K.

Ultimately, whether we will have sufficient liquidity from cash flow from operations, access to borrowings under the DIP Facility and proceeds received from assets 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 Calpine’s business plan is successful as well as the other factors noted in “Forward-Looking Statements” above, including the risk factors included in Item 1A. “Risk Factors” included in our 2005 Form 10-K.

Index Definitions

As a result of our Chapter 11 cases and the other matters described herein, 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, including the restructuring of Calpine and the other Debtors; (iv) our ability to comply with our debt agreements, including the DIP Facility, and the adequate assurance provisions of the Cash Collateral Order; (v) the ability of Calpine to continue to meet the DIP Facility requirements; and (vi) our ability to achieve profitability following a restructuring. Additionally, because of our significant relationships with Calpine, CES and COSCI, we are also dependent upon those entities to continue to operate as a going concern. These challenges are in addition to those operational and competitive challenges faced by us in connection with our business. In conjunction with Calpine and 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.

Chapter 11 Cases and Financing Activities

As discussed above, most of our revenues are generated from the sale of electrical capacity and energy through agreements with CES, which is a subsidiary of Calpine. ~~CES~~Consequently, ~~also~~our ~~supplies~~cash ~~the~~flows ~~majority~~from ofoperations ~~the~~are ~~natural~~dependent ~~gas~~on ~~needed~~cash togenerated ~~operate~~from ~~our~~these ~~facilities,~~sales. ~~under~~In addition, the ~~Fixed~~majority ~~Price~~of ~~and~~the ~~Index~~fuel ~~Based~~used ~~Agreements.~~to ~~Consequently,~~generate ~~our~~power ~~cash flows~~ from ~~operations~~our ~~are~~facilities ~~dependent~~is onsupplied ~~cash~~by ~~generated from these sales~~CES. There is no assurance, however, that CES, or Calpine or its other affiliates, can continue to meet their obligations under their agreements with us including, in particular, the Index Based and Fixed Price Agreements, in the near term or otherwise. If Calpine is unable to meet its obligations under these agreements, we would be required to enter into power and gas purchase agreements and arrange for scheduling and marketing services and operating and maintenance services with third parties. If we were unable to secure these third-party agreements on acceptable terms or at all, we anticipate that it would have a material adverse effect on our financial condition, results of operations, cash flows and could cause us to be unable to make payments under our outstanding indebtedness, including our outstanding Notes and Term Loans.

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 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, our parent, Calpine, has entered into, and obtained Bankruptcy Court approval of, a $2 billion DIP Facility which we believe will be sufficient to support our operations for the anticipated duration of our Chapter 11 cases. In addition, Calpine has obtained 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) its cash management program (as described below), (ii) payments to its 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 Calpine to reduce overhead and discontinue activities without adversely impacting profit potential, particularly in the near term. In addition, we expect that certain power plants or other of our assets may be sold, and that commercial operations may be suspended at certain of our power plants during our reorganization effort.

DIP Facility. On December 22, 2005, Calpine entered into a $2 billion DIP Facility, which, as amended and restated as of February 23, 2006, is comprised of a $1 billion revolving credit facility priced at LIBOR plus 225 basis points, a $400 million first-priority term loan priced at LIBOR plus 225 basis points or base rate plus 125 basis point and a $600 million second-priority term loan priced at LIBOR plus 400 basis points or base rate plus 300 basis points. Calpine is the borrower under the DIP Facility, which is guaranteed by all of the other Debtors, including the CalGen Debtors. The Bankruptcy Court granted interim approval the DIP Facility on December 21, 2005, but initially limited Calpine’s access under the DIP Facility to $500 million under the revolving credit facility. On February 22, 2006, the Bankruptcy Court entered a final order approving the DIP Facility and removing the limitation on Calpine’s ability to borrow thereunder. The amendment and restatement of the DIP Facility and the syndication of the DIP Facility were closed on February 23, 2006. The DIP Facility was further amended on May 3, 2006, September 25, 2006, and most recently December 20, 2006, to, among other things, (i) implement various provisions of the December 20, 2006, Bankruptcy Court order amending the Cash Collateral Order, including allowing for certain liens in favor of us, (ii) allow adequate protection payments to holders of Calpine’s second priority debt totaling approximately $466 million for 2006 and 2007 and (iii) eliminating the provision that reduces the DIP

Index Definitions

including allowing for certain liens in favor of us, (ii) allow adequate protection payments to holders of Calpine’s second priority debt totaling approximately $466 million for 2006 and 2007 and (iii) eliminating the provision that reduces the DIP revolver commitment from $1 billion to $750 million based on certain asset sale mechanics. Deutsche Bank Securities Inc. and Credit Suisse were co-lead arrangers for the DIP Facility, which is secured by first priority liens on all of the unencumbered assets of the Debtors, including the CalGen Debtors, and junior liens on all of their encumbered assets. The DIP Facility will remain in place until the earlier of an effective plan of reorganization or December 20, 2007. 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.

As of ~~June~~September 30, 2006, there was $~~998~~997.34 million outstanding under the DIP Facility term loan facilities, nothing outstanding under the DIP Facility revolving facility, and $11.7 million letters of credit had been issued against the revolving facility. As of December 31, 2006, there was $996.5 million outstanding under the DIP Facility term loan facilities, nothing outstanding under the DIP Facility revolving facility and $82.5 million of letters of credit had been issued against the revolving facility. We do not record a liability related to the guarantees because each guarantee is a subsidiary’s guarantee of the debt owed to a third party by its parent.

Cash Management. The Debtors have received Bankruptcy Court approval to continue to manage their cash in accordance with their 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. Such cash management systems are subject to the requirements of the DIP Facility, the 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 Bankruptcy Court orders, intercompany transfers are generally recorded as intercompany loans. Upon the closing of the DIP Facility, the cash balances of the 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 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 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.

On June 30, 2006, our liquidity totaled approximately $205.5 million. This only includes cash and cash equivalents on hand. While we have $750 million of borrowing capacity under our Working Capital Facility for specific permitted purposes, we are not permitted to borrow under the Working Capital Facility due to our Chapter 11 filing. If, as discussed above, Calpine and its affiliates are unable to meet their obligations under their agreements with us, including providing access to the Working Capital Facility, we would be unable to satisfy all obligations under our outstanding indebtedness unless we were able to enter into new third party agreements sufficient to support such obligations. As described above, there can be no assurance that Calpine and its affiliates will continue to be able to meet their obligations or, if they do not, that we will be able to enter into new third party arrangements upon acceptable terms or at all.

On September 30, 2006, our liquidity totaled approximately $378.4 million. This only includes cash and cash equivalents on hand. While we have $750 million of borrowing capacity under our Working Capital Facility for specific permitted purposes, we are not permitted to borrow under the Working Capital Facility due to our Chapter 11 filing. If, as discussed above, Calpine and its affiliates are unable to meet their obligations under their agreements with us, including providing access to the Working Capital Facility, we would be unable to satisfy all obligations under our outstanding indebtedness unless we were able to enter into new third party agreements sufficient to support such obligations. As described above, there can be no assurance that Calpine and its affiliates will continue to be able to meet their obligations or, if they do not, that we will be able to enter into new third party arrangements upon acceptable terms or at all.

Index Definitions

Rejection of Executory Contracts and Unexpired Leases. 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 Bankruptcy Court and certain other conditions. Parties to executory contracts or unexpired leases rejected or deemed rejected by a CalGen Debtor may file proofs of claim against that CalGen 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 ~~determine~~project ~~with certainty~~ the magnitude of these potential claims at this time, but to the extent a potential claim is probable and estimable, we record our estimate of the allowed claim at the time of rejection or upon Bankruptcy Court approval, depending upon the facts and circumstances. The most significant of these contract rejections that were pending or occurred during the three months ending ~~June~~September 30, 2006, or thereafter through the date of this filing ~~include~~includes the following:

•

On September 12, 2006, we filed with the Bankruptcy Court of a notice of rejection of a transportation contract between Columbia Energy LLC, a CalGen Debtor, and South Carolina Pipeline Corporation. The contract, which is scheduled to expire on November 30, 2023, was for transportation capacity on an intrastate pipeline that exceeded the Columbia facility’s requirements. On September 25, 2006, South Carolina Pipeline Corporation filed certain objections to the rejection notice, which were ultimately resolved by the parties, and, on October 25, 2006, the Bankruptcy Court entered the parties’ stipulation settling this matter. Under the stipulation, the effective date of rejection is October 25, 2006, and South Carolina Pipeline Corporation must file its claim for rejection damages by December 22, 2006. South Carolina Pipeline Corporation filed a proof of claim December 21, 2006, for rejection damages comprising $5,300,000 in secured claims and $160,283,593 in unsecured claims. It is not certain at this time whether some or all of these claims will ultimately be allowed.

•

In addition, we had until July 18, 2006, to assume unexpired non-residential real property leases. Absent the consent of the applicable counterparty, such leases not assumed by that date are deemed rejected. Accordingly, 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 Bankruptcy Court approved our motion to extend the time for us to assume leases between Debtor-lessees and any affiliated lessors until the confirmation of a plan of reorganization of the applicable Debtor-lessee. Without an extension of time to assume, leases between CalGen Debtors and their affiliates would also have been deemed rejected if not assumed by July 18, 2006. The most significant of these matters that were pending or occurred during the three months ending ~~June~~September 30, 2006, or thereafter through the date of this filing ~~include~~includes the following:

•

Index Definitions

counterparty to the facility site lease and energy services agreement, pursuant to which certain disputes under those agreements have been resolved.

• On January 1931, 2007, ~~we filed a motion with~~ the Bankruptcy Court approved our motion to assume certain leases and executory contracts relating to operation of the Baytown facility, a 753-MW natural gas-fired combined cycle cogeneration plant located near Baytown, Texas. The agreements ~~we seek to assume~~ include (i) the Ground Lease and Easement, (ii) the Services Agreement, and (iii) numerous other agreements that facilitate the operation and maintenance of the Baytown facility and the use of certain real property rights appurtenant thereto. ~~Hearing on the motion is currently scheduled for January 31, 2007, before the Bankruptcy Court.~~

Asset Sale — We are also required to obtain Bankruptcy Court approval of sales of assets, subject to certain exceptions including with respect to de minimis assets. Such sales are subject in certain cases to Bankruptcy Court-approved auction procedures. The most significant of these matters that were pending or occurred during the ~~six~~nine months ended ~~June~~September 30, 2006, or thereafter through the date of this filing includes the following:

•

• On January 26, 2007, Calpine filed a motion for an order authorizing the Debtors to obtain a $5.0 billion replacement debtor-in-possession financing facility to refinance the existing $2.0 billion DIP Facility and repay the approximately $2.516 billion of CalGen Secured Debt. The proposed refinancing is intended to replace the higher interest-rate DIP Facility and CalGen Secured Debt with lower interest-rate debt, resulting in potential savings in interest expense and in savings to audit fees and compliance costs ~~related~~relating to existing CalGen Secured Debt. To effectuate the proposed repayment of the CalGen Secured Debt, the motion also asks the Bankruptcy Court to allow the Debtors’ limited objection to the claims filed by the holders of the CalGen Secured Debt and to determine the value of those claims. A hearing on the motion is currently ~~sche~~scheduled ~~duled~~ before the Bankruptcy Court on February 27, 2007.

Index Definitions

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

	Six Months Ended June 30,
	Nine Months Ended September 30,
	2006			2005 ~~(Restated)~~
				(Restated)
Beginning cash and cash equivalents	$	143,456		$	64,538
Net cash provided by (used in):
Operating activities		62234,~~808~~087			43169,~~742~~483
Investing activities		~~(753~~1,007	)		(6774,~~633~~900	)
Financing activities		––(156	)		(166	)
Net increase in cash and cash equivalents		62234,~~055~~938			~~(24~~94,~~057~~417	)
Ending cash and cash equivalents	$	~~205~~378,~~511~~394		$	40158,~~481~~955

Operating activities for the ~~six~~nine months ended ~~June~~September 30, 2006, provided net cash of $ 62234.81 million, compared with $43169.75 million for the ~~same~~nine ~~period~~months inended September 30, 2005. The increase in operating cash flow is primarily due to ~~improved~~the ~~operating~~timing ~~performance~~of ~~which~~payments ~~resulted~~received inon anaccounts ~~increase~~receivable. inThere ~~gross~~was ~~profit~~a todecrease ~~$84.4~~in ~~million~~receivable ~~for~~balances ~~the~~from ~~six~~December 31, ~~months~~2005, ~~ended~~to ~~June~~September 30, 2006, ~~from~~of $6731.73 million ~~for~~compared ~~the~~to ~~six~~a ~~months~~$37.3 ~~ended~~million ~~June~~increase from December 31, 2004, to September 30, 2005.

Investing activities for the ~~six~~nine months ended ~~June~~September 30, 2006, ~~consumed~~provided net cash of $01.81 million, compared with using cash of $6774.79 million in the same period of 2005. The ~~decrease~~increase ~~between the first quarter of 2006 and 2005~~ is due to ~~the~~receipts ~~completion~~ of ~~construction~~deferred oftransmission ~~Phase~~credit Ipayments ofin ~~our~~2006 ~~Pastoria~~as ~~facility~~well inas ~~May 2005.~~reduced ~~Capital~~capital expenditures for completing construction of the Pastoria facility ~~represent the majority of investing cash outflows for the six months ended June 30, 2005~~. All CalGen plants have completed construction and been in commercial operation since ~~July~~May 2005.

Letter of Credit Facilities — At ~~June~~September 30, 2006, and December 31, 2005, we had approximately $41.90 ~~million~~ and $158.3 million, respectively, in letters of credit outstanding under our $200 million Revolving Credit Facility to support fuel purchases and other operational activities. ~~Additionally~~ Also, at ~~June~~September 30, 2006, we had $82.3 million in borrowings drawn on our Revolving Credit Facility related to letters of credit that were issued to third parties to pay for pre-petition gas purchases made by CES. An additional $30.0 million, in borrowings under the Revolving Credit Facility related to letters of credit, was drawn on April 1, 2006, as a deposit with Wisconsin Electric Power Company in lieu of renewing the letter of credit with them. Total borrowings from letter of credit drawings under the Revolving Credit Facility were approximately $112.3 million at September 30, 2006. Total borrowings from letter of credit drawings related to the Revolving Credit Facility were approximately $112.3 million at ~~June~~September 30, 2006, and at December 31, 2006.

Negative Working Capital — We had a negative working capital balance (current assets less current liabilities) of approximately $2.32 billion at ~~both June~~September 30, 2006, and $2.3 billion at December 31, 2005. The negative working capital balances were due to classifying all debt as current as a result of Chapter 11 related defaults under the debt agreements.

Credit Considerations — On March 1, 2006, Moody’s Investors Services withdrew its ratings on the Notes and Term Loans, after having lowered its credit ratings on our debt obligations, reduced our first priority debt to B3 from B2, our second priority debt to Caa1 from B3 and our third priority debt to Caa2 from Caa1 (with negative outlook). Because the pricing of our debt is not linked to debt and credit ratings by the rating agencies and the majority of our revenues are from CES, a related party, we do not currently expect the downgrade to have a material impact on our financial position, results of operations, or cash flows. However, the downgrade could potentially impact the cost of doing business with third parties in the future or could impact our ability to refinance our debt or fund our growth in the capital markets.

We believe that as we implement the steps of our business plan and then emerge from Chapter 11, our credit rating will gradually improve.

~~Capital~~Distributions ~~Expenditures~~to ~~and~~Sole ~~Sources~~Member —–– WeUnder ~~expect~~the toindentures ~~make~~governing ~~capital~~the ~~expenditures~~Notes, inwe ~~2006~~are ~~with~~generally ~~respect~~permitted to ~~major~~make ~~maintenance~~distributions ~~and~~to ~~miscellaneous~~CalGen ~~projects~~Holdings, ofour ~~approximately~~sole ~~$78~~member, ~~million.~~out Weof ~~expect~~excess tocash ~~fund~~flow ~~these~~generated ~~expenditures~~by ~~through~~operations, provided that cumulative cash onflow ~~hand~~is positive and ~~operating~~that ~~cash~~no ~~flow.~~default or event of default exists and there are no amounts outstanding under the

Index Definitions

Distributions to Sole Member –– Under the indentures governing the Notes, we are generally permitted to make distributions to CalGen Holdings, our sole member, out of excess cash flow generated by operations, provided that cumulative cash flow is positive and that no default or event of default exists and there are no amounts outstanding under the Working Capital Facility. Because of the event of default related to our Chapter 11 cases, we are unable to make distributions to our equity holders, payments on our subordinated debt and similar payments from excess cash flow (after the payment of operating expenses, debt service and deposits to the reserve accounts created in connection with the 2004 Refinancing) while such event of default continues. It is possible we will be unable to make a distribution to our equity holder until we emerge from Chapter 11. During the pendency of our Chapter 11 cases, in lieu of distributions we are permitted under the terms of the Cash Collateral Order to make transfers from our excess cash flow in the form of intercompany loans to other Debtors notwithstanding the existence of any default or event of default related to our Chapter 11 cases. However, we may be prevented from making such transfers if a default or event of default occurs due to events that are not related to our Chapter 11 cases. No distribution was made during the six months ended June 30, 2006. In December 2006, the collateral agent for our Notes and Term Loans transferred $259.6 million in excess cash to Calpine in the form of an intercompany loan in accordance with the Cash Collateral Order as modified by the Bankruptcy Court’s December 20, 2006, order. In addition, pursuant to the order, the collateral agent will honor all future requests for intercompany loan transfers within three days of receipt of the ~~r equest~~request, provided that the Debtors are in compliance with their adequate protection obligations under the Cash Collateral Order and certain specified provisions of the indentures governing the Notes.

Capital Availability — Under the Notes and Term Loans, our ability to incur additional indebtedness is severely limited because of our Chapter 11 cases. If a need for capital does arise, either because our business changes or because the sources on which we are depending are not available, we may not be able to obtain such capital under the Notes and Term Loans or on terms that are attractive to us.

Compliance with Debt ~~Covenants~~ Covenant — See Note 5 of the Notes to Consolidated Condensed Financial Statements for compliance information.

Guarantees — In connection with its Chapter 11 cases, Calpine entered into the $2 billion DIP Facility, which was amended and restated as of February 23, 2006. Calpine is the borrower under the DIP Facility, which is guaranteed by all of the other Debtors, including the CalGen Debtors. The DIP Facility will remain in place until the earlier of an effective Calpine plan of reorganization or December 20, 2007. As of ~~June~~September 30, 2006, there was $~~998~~997.34 million outstanding under the DIP Facility term loan facilities, nothing outstanding under the DIP Facility revolving facility, and $11.7 million of letters of credit had been issued against the revolving facility. As of December 31, 2006, Calpine had borrowed $996.5 million under the DIP Facility term loan facilities and issued $82.5 million of letters of credit against the revolving facility. We do not record a liability related to the guarantee, as it is a subsidiary’s guarantee of the debt owed to a third party by its parent.

Performance Indicators — We believe the following factors are important in assessing our ability to continue to fund our growth in the capital markets: (a) various interest coverage ratios; (b) our credit and debt ratings by the rating agencies; (c) our anticipated capital requirements over the coming quarters and years; (d) the profitability of our operations; (e) the non-GAAP financial measures and other performance metrics discussed in “Performance Metrics” below; (f) our cash balances and remaining capacity under existing credit facilities; (g) compliance with covenants in existing debt facilities, including the DIP Facility; (h) gaining access to new or replacement capital; and (i) the stability and growth of future contractual cash flows, particularly cash flows from the Index Based and Fixed Price Agreements with CES.

Off-Balance Sheet Commitments — Operating leases are not reflected on our balance sheet. All counterparties in these transactions are third parties that are unrelated to us.

Performance Metrics

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

MWh generated. — We generate power, which is sold to CES and third parties, and steam, which is primarily sold to third-party hosts. These sales are recorded as electricity and steam revenue. The volume in MWh for power is a direct indicator of our level of electricity and steam generation activity.

Index Definitions

MWh generated. — We generate power, which is sold to CES and third parties, and steam, which is primarily sold to third-party hosts. These sales are recorded as electricity and steam revenue. The volume in MWh for power is a direct indicator of our level of electricity and steam 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 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 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 the average cost of generation. We also calculate a “steam-adjusted” Heat Rate, in which we adjust the fuel consumption in Btus 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. — We calculate the all-in realized electric price per MWh generated by dividing (a) the sum of adjusted electricity and steam revenue, which includes capacity revenues, energy revenues, thermal revenues, plus realized gain or (loss) on the Index Hedge plus other revenue related to the Index Hedge by (b) total generated MWh in the period.

Average cost of natural gas expressed in dollars per MMBtus of fuel consumed. — The fuel costs for our gas-fired power plants are a function of volumes consumed and the prices we pay for fuel purchased from CES. Accordingly, we calculate the cost of natural gas per MMBtus of fuel consumed in our power plants by dividing (a) adjusted fuel expense by (b) the heat content in MMBtus of the fuel we consumed in our power plants for the period.

Average spark spread expressed in dollars per MWh generated. — We calculate the spark spread per MWh generated by subtracting (a) adjusted fuel expense from (b) adjusted electricity and steam revenue and dividing the difference by (c) total generated MWh in the period.

Average POX per MWh. — To assess trends in electric power POX per MWh, we divide POX by actual MWh.

Index Definitions

The table below shows the operating performance metrics discussed above.

	Three Months Ended June 30,									Six Months Ended June 30,
	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005	~~2005~~		2006			~~2006~~2005				~~2005~~
					(Restated)	~~(Restated)~~					(Restated)				~~(Restated)~~
	(in thousands)
	(In thousands)
Operating Performance Metrics:
MWh generated		7,819					5,991					13,858				12,574
Total deliveries of power:
Average availability		93.2		%			84.6		%			92.6	%			87.7	%
MWh generated		11,495			10,294			25,354			22,868
Average baseload capacity factor:
Average availability		96.2	%		96.5	%		93.3	%		91.3	%
Average total MW in operation		9,815					9,065					9,815				9,065
Average baseload capacity factor:
Less: Average MW of pure peakers		513					513					513				513
Average total MW in operation		9,815			9,782			9,815			9,360
Average baseload MW in operation		9,302					8,552					9,302				8,552
Less: Average MW of pure peakers		513			513			513			513
Hours in the period		2,184					2,184					4,344				4,344
Average baseload MW in operation		9,302			9,269			9,302			8,847
Potential baseload generation (MWh)		20,316					18,678					40,408				37,150
Hours in the period		2,208			2,208			6,552			6,552
Actual total generation (MWh)		7,819					5,991					13,858				12,574
Potential baseload generation (MWh)		20,539			20,467			60,947			57,965
Less: Actual pure peakers’ generation (MWh)		5					5					5				5
Actual total generation (MWh)		11,495			10,294			25,354			22,868
Actual baseload generation (MWh)		7,813					5,986					13,853				12,569
Less: Actual pure peakers’ generation (MWh)		36			25			41			30
Average baseload capacity factor		38.5		%			32.0		%			34.3	%			33.8	%
Actual baseload generation (MWh)		11,459			10,269			25,313			22,838
Average Heat Rate for gas-fired power plants (excluding peakers)(Btu’s/KWh):
Average baseload capacity factor		55.8	%		50.2	%		41.5	%		39.4	%
Not steam adjusted		8,150					8,427					8,294				8,268
Average Heat Rate for gas-fired power plants (excluding peakers)(Btu’s/KWh):
Steam adjusted		7,257					7,253					7,236				7,148
Not steam adjusted		7,746			7,778			8,046			8,048
Average all-in realized electric price:
Steam adjusted		7,133			7,130			7,189			7,140
Electricity and steam revenue	$	580,664			$		489,165			$		1,065,035		$		947,530
Average all-in realized electric price:
Spread on sales of purchased power for hedging and optimization		(3,648		)			(2,116		)			(12,472	)			(1,854	)
Electricity and steam revenue	$	811,349		$	953,480		$	1,876,384		$	1,901,010
Adjusted electricity and steam revenue	$	577,016			$		487,049			$		1,052,563		$		945,676
Spread on sales of purchased power for hedging and optimization		(428	)		(269	)		(12,900	)		(2,122	)
MWh generated		7,819					5,991					13,858				12,574
Adjusted electricity and steam revenue	$	810,921		$	953,211		$	1,863,484		$	1,898,888
Average all-in realized electric price per MWh	$	73.80			$		81.30			$		75.95		$		75.21
MWh generated		11,495			10,294			25,354			22,868
Average cost of natural gas:
Average all-in realized electric price per MWh	$	70.55		$	92.60		$	73.50		$	83.04
Adjusted fuel expense	$	419,629			$		332,742			$		798,465		$		667,297
Average cost of natural gas:
MMBtu of fuel consumed by generating plants		63,735					50,500					114,956				103,984
Fuel expense	$	558,244		$	672,133		$	1,356,709		$	1,339,430
Average cost of natural gas per MMBtu	$	6.58			$		6.59			$		6.95		$		6.42
MMBtu of fuel consumed by generating plants		88,773			79,871			203,673			183,801
MWh generated		7,819					5,991					13,858				12,574
Average cost of natural gas per MMBtu	$	6.29		$	8.42		$	6.66		$	7.29
Average cost of adjusted fuel expense per MWh	$	53.67			$		55.54			$		57.62		$		53.07
MWh generated		11,495			10,294			25,354			22,868
Average spark spread:
Average cost of fuel expense per MWh	$	48.56		$	65.29		$	53.51		$	58.57
Adjusted electricity and steam revenue	$	577,016			$		487,049			$		1,052,563		$		945,676
Average spark spread:
Less: Adjusted fuel expense		419,629					332,742					798,465				667,297
Adjusted electricity and steam revenue	$	810,921		$	953,211		$	1,863,484		$	1,898,888
Less: Realized amortization expense on Index Hedge		2,959					130					6,360				5,741
Less: Fuel expense		558,244			672,133			1,356,709			1,339,430
Spark spread	$	154,428			$		154,177			$		247,738		$		272,638
Less: Realized amortization expense on Index Hedge		2,959			416			9,319			6,157
MWh generated		7,819					5,991					13,858				12,574
Spark spread	$	249,718		$	280,662		$	497,456		$	553,301
Average spark spread per MWh	$	19.75			$		25.73			$		17.88		$		21.68
MWh generated		11,495			10,294			25,354			22,868
Average plant operating expense (POX) per normalized MW (for comparison purposes we also include POX per actual MWh):
Average spark spread per MWh	$	21.72		$	27.26		$	19.62		$	24.20
Plant operating expense (POX)	$	49,069			$		71,553			$		88,561		$		115,027
Average plant operating expense (POX) per actual MWh:
POX per actual MWh		6.28					11.94					6.39				9.15
Plant operating expense (POX)	$	61,899		$	46,737		$	150,460		$	161,764
POX per actual MWh		5.38			4.54			5.93			7.07

Index Definitions

Financial Market Risks

Debt Financing — Certain debt instruments may affect us adversely because of changes in market conditions. In connection with the 2004 Refinancing on March 23, 2004, we issued approximately $2.4 billion in Notes and Term Loans, of which $150 million is at a fixed rate, and the balance is at floating rates based on LIBOR plus a spread. Significant LIBOR increases could have a negative impact on our future interest expense. In addition, borrowings under our Revolving Credit Facility and our Working Capital Facility carry an interest rate based on LIBOR plus a spread.

The following table summarizes our variable-rate debt, by contractual maturity date, exposed to interest rate risk as of ~~June~~September 30, 2006. As a result of our Chapter 11 cases, all such debt is classified as current in our Consolidated Condensed Balance Sheet as of ~~June~~September 30, 2006. All fair market values are shown net of applicable premium or discount, if any (dollars in thousands):

	2006		2007		2008		2009		2010		Thereafter		Fair Value ~~June~~September 30, 2006
First Priority Secured Floating Rate Notes Due 2009	$	—	$	1,175	$	2,350	$	231,475	$	—	$	—	$	~~240~~239,~~288~~700
Second Priority Secured Floating Rate Notes Due 2010		—		—		3,200		6,400		624,~~439~~839		—		~~660~~668,~~986~~800
Third Priority Secured Floating Rate Notes Due 2011		—		—		—		—		—		680,000		~~717~~727,~~400~~600
Total Floating Rate Notes(1)		—		1,175		5,550		237,875		624,439		680,000		1,618,674
Total Floating Rate Notes(2)		—		1,175		5,550		237,875		624,839		680,000		1,636,100
First Priority Secured Term Loans Due 2009		—		3,000		6,000		591,000		—		—		600,000
First Priority Secured Term Loans Due 2009(1)		—		3,000		6,000		591,000		—		—		600,000
Second Priority Secured Term Loans Due 2010		—		—		500		1,000		97,569		—		99,069
Second Priority Secured Term Loans Due 2010(1)		—		—		500		1,000		97,631		—		99,131
Total Floating Rate Term Loans(2)		—		3,000		6,500		592,000		97,569		—		699,069
Total Floating Rate Term Loans(1) (3)		—		3,000		6,500		592,000		97,631		––		699,131
Revolving Credit Facility(2)		—		112,258		—		—		—		—		112,258
Revolving Credit Facility(1) (3)		—		112,258		—		—		—		—		112,258
Working Capital Facility(1)		—		—		—		—		—		—		—
Working Capital Facility(1) (2)		—		—		—		—		—		—		—
Total Other Financing		—		112,258		—		—		—		—		112,258
Total Other Financings(1)		—		112,258		—		—		—		—		112,258
Grant total variable-rate debt instruments	$	—	$	116,433	$	12,050	$	829,875	$	722,~~008~~470	$	680,000	$	2,~~430~~447,~~001~~489

__________

(1) ~~Interest~~Fair ~~rate~~value ~~based~~equals oncarrying ~~LIBOR~~value, ~~plus~~which ais ~~spread~~the aggregate principal amount subject to variable rate risk.

(2) Interest rate based on LIBOR plus a spread~~; however the Company may elect the base rate plus a spread (see Note 5 of the Notes to Consolidated Condensed Financial Statements)~~.

(3)	Interest rate based on LIBOR plus a spread; however the Company may elect the base rate plus a spread (see Note 5 of the Notes to Consolidated Condensed Financial Statements).

Derivatives — We are primarily focused on generation of electricity using gas-fired turbines. As a result, our natural physical commodity position is “short” fuel (i.e., natural gas consumer) and “long” power (i.e., electricity seller). To mitigate forward exposure to price fluctuations in these commodities, we entered into the Index Hedge with MSCG discussed in Note 9 of the Notes to Consolidated Condensed Financial Statements.

The Index Hedge provides for semi-annual payments to us equal to the amount, if any, that the aggregate spark spread amount calculated under the Index Based Agreement, in each six-month period, falls below $50 million. The Hedge Index is in place until April 1, 2007.

Index Definitions

The change in fair value of outstanding derivative instruments for the ~~six~~nine months ended ~~June~~September 30, 2006, is summarized in the table below (in thousands):

Fair value of contracts outstanding at January 1, 2006	$	24,558
Changes in fair value attributable to new contracts		—
Amortization during the period, net(1)		(69,~~360~~319	)
Changes in fair value attributable to price movements, net		(~~996~~1,146	)
Fair value of contracts outstanding at June 30, 2006(2)	$	17,202
Fair value of contracts outstanding at September 30, 2006(2)	$	14,093

__________

(1)	Non-cash losses from roll-off (amortization) of deferred premium (see discussion in Note 9 of the Notes to Consolidated Condensed Financial Statements).

(2)	Net derivative assets are reported in Note 9 of the Notes to Consolidated Condensed Financial Statements.

The price source of the fair value of the outstanding derivative instrument at ~~June~~September 30, 2006, is based on prices provided by external sources, and the instrument will mature at April 1, 2007.

The credit quality of the counterparty holding our Index Hedge at ~~June~~September 30, 2006, and for the period then ended is investment grade.

Calpine’s risk managers maintain and validate the fair value information associated with the Index Hedge. This information is derived from various sources. 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. See “Application of Critical Accounting Policies” for a discussion of valuation estimates used where external prices are unavailable.

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

	Fair Value		Fair Value After 10% Adverse Price Change
At June 30, 2006:
At September 30, 2006:
Other mark-to-market activity	$	1714,~~202~~093	$	1714,~~198~~093

The derivative instrument included in this table is the Index Hedge discussed in Note 9 of the Notes to Consolidated Condensed Financial Statements. Valuation of the Index Hedge depends, to a large degree, upon assumptions about future gas and power prices. Accordingly, we have calculated the change in fair value shown above based upon an assumed 10% increase in power prices and an assumed 10% decrease in gas prices. Changes in fair value of the Index Hedge economically offset the price risk exposure of our physical assets. We have included none of the offsetting changes in value of our physical assets in the table above.

The primary factors affecting the fair value of our derivative at any point in time are (1) the term of our open derivative position and (2) changing market prices for electricity and natural gas. The Index Hedge is valued using the mean reversion model and, as prices for electricity and natural gas are among the most volatile of all commodity prices, there may be material changes in the fair value of our derivative over time, driven by price volatility and the realized portion of the derivative asset. Under SFAS No. 133, the change since the last balance sheet date in the total value of the derivative is reflected in the statement of operations as an item (gain or loss) of current earnings.

Index Definitions

Recent Accounting Pronouncements

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

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 on 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 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 by numerous countries, 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, seven northeastern states have entered into the Regional Greenhouse Gas Initiative, which is an agreement 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~~ determine the collective impact climate change initiatives may have on our business.

Index Definitions

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 the SEC’s rules and forms, and to ensure that such information is accumulated and communicated to our management, including our President and ~~the~~ Chief Financial Officer, as appropriate, to allow timely decisions regarding required financial disclosure.

As a result of the material weaknesses discussed below, our management, including our President and Chief Financial Officer, has concluded that our disclosure controls and procedures were not effective as of ~~June~~September 30, 2006. We continue to perform additional analysis and post-closing procedures to ensure that our Consolidated Condensed Financial Statements are prepared and presented in accordance with GAAP. Accordingly, management believes that the Consolidated Condensed Financial Statements included in the Report fairly present in all material respects our financial condition, results of operations and cash flows for the periods presented.

As of December 31, 2005, management identified material weaknesses related to the controls over accounting for income taxes and the accuracy of affiliate billings that were discussed in Item 9A. “Controls and Procedures” of our 2005 Form 10-K. These material weaknesses continue to exist at ~~June~~September 30, 2006.

Status of Remediation of the Material Weakness

During 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 book and tax basis of our property, plant and equipment.

Our remediation efforts include the following:

• Implementing software to perform the tax depreciation, supporting book to tax reconciliations and valuation allowance computations. This software will be run parallel with the ~~spreadsheet~~tax calculations during 2006;

•

Implemented quarterly meetings between the Tax and Accounting Departments to ensure timely performance of book-tax reconciliations;

•

Implemented consistent terminology related to fixed asset transactions types in the accounting system to ensure effective conversion of accounting data for use in the tax calculation; and

•

Hired a Director of Federal Income Tax Accounting.

Additionally, we are implementing tax provision software to aid in performing the tax provision calculation. This software will be run parallel with the ~~spreadsheet~~tax ~~calculations~~calculation during 2006. We continue to monitor the effectiveness of the tax controls and procedures and will make any additional changes that management deems appropriate. We will not be able to conclude that this material weakness has been successfully remediated until management’s testing and assessment demonstrates the controls have operated effectively for a sufficient period of time.

During fourth quarter 2005 and first quarter 2006, we have taken steps necessary to improve our internal controls relating to the accuracy of affiliate billings, including the following:

Index Definitions

During fourth quarter 2005 and first quarter 2006, we have taken steps necessary to improve our internal controls relating to the accuracy of affiliate billings, including the following:

•

Implemented a system to automate the calculation of our affiliate billings in the fourth quarter of 2005;

•

Enhanced our general review procedures over revenues generated from CES; and

•

Implemented additional analytical review and managerial approval of the monthly billings.

While we believe that meaningful progress was made during late 2005 and early 2006 in strengthening our controls related to affiliate transactions for related party revenues and expenses, we plan to continue enhancing the above described procedures to improve our control environment over affiliate transactions. We believe we are taking the steps necessary for the successful remediation of this material weakness during 2006. We will continue to monitor the effectiveness of these procedures and to make any changes that management deems appropriate.

In connection with the preparation of the Consolidated Financial Statements for fiscal 2005, an error was discovered in the classification of pre-payments made for point-to-point deferred transmission credits and reimbursement payments received for point-to-point deferred transmission credits in the Consolidated Statement of Cash Flows. The error affected our Consolidated Condensed Statement of Cash Flows for the ~~six~~nine months ended ~~June~~September 30, 2005, and had no effect on our Consolidated Condensed Statements of Operations for the three and ~~six~~nine months ended ~~June~~September 30, 2005, as presented in this Report. As a result of the effect on the Consolidated Condensed Statement of Cash Flows, we have restated our previously issued Consolidated Condensed Financial Statements for the ~~three~~nine ~~and six~~ months ended ~~June~~September 30, 2005.

In coming to the conclusion that our disclosure controls and procedures and our internal control over financial reporting were not effective as of ~~June~~September 30, 2006, management considered, among other things, the control deficiency related to the classification of pre-payments made for point-to-point deferred transmission credits and reimbursement payments received for point-to-point deferred transmission credits in the Consolidated Condensed Statement of Cash Flow, which resulted in the need to restate our previously issued financial statements as described above. Management has concluded that the cash flow control deficiency that resulted in the restatement of the previously issued financial statements did not constitute a material weakness as of December 31, 2005, because management determined that as of ~~June~~September 30, 2006, there were controls designed and in place to prevent or detect a material misstatement and therefore, the likelihood of the Consolidated Condensed Statement of Cash Flows being materially misstated was remote.

Changes in Internal Control over Financial Reporting

Other than the remediation steps described above, there have been no other changes in our internal control over financial reporting during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Index Definitions

PART II — OTHER INFORMATION

Item 1. Legal Proceedings.

See Note 10 of the Notes to Consolidated Condensed Financial Statements for a description of our legal proceedings.

Item 3. Defaults Upon Senior Securities.

See Note 5 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 6 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 continue to make current payments of interest and, if applicable, principal on our Notes, Term Loans and borrowings, if any, under the Revolving Credit Agreement.

Item 6. Exhibits.

The following exhibits are filed herewith unless otherwise indicated:

EXHIBIT INDEX

Exhibit
Number		Description

3.1		Amended and Restated Certificate of Formation of Calpine Generating Company, LLC (incorporated by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-4 (Registration No. 333-117335), filed with the SEC on July 13, 2004).

3.2		Certificate of Incorporation of CalGen Finance Corp. (incorporated by reference to Exhibit 3.2 to the Company’s Registration Statement on Form S-4 (Registration No. 333-117335), filed with the SEC on July 13, 2004).

3.3		Limited Liability Company Operating Agreement of Calpine Generating Company, LLC (incorporated by reference to Exhibit 3.93 to the Company’s Registration Statement on Form S-4 (Registration No. 333-117335), filed with the SEC on July 13, 2004).

3.4		Bylaws of CalGen Finance Corp. (incorporated by reference to Exhibit 3.94 to the Company’s Registration Statement on Form S-4 (Registration No. 333-117335), filed with the SEC on July 13, 2004).

10.1.1		$2,000,000,000 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 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 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).

10.1.2		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, and 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).

Index Definitions

Exhibit
Number		Description
10.1.3		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, and Credit Suisse, Cayman Islands Branch, as administrative agent for the Second Priority Term Lenders. (Incorporated by reference to Exhibit 10.1.1.3 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).
10.1.4		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, Credit Suisse, Cayman Islands Branch, as administrative agent for the Second Priority Term Lenders (incorporated by reference to Exhibit 10.1.2.4 to Calpine Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, filed with the SEC on November 9, 2006).
10.1.5		Letter Agreement, dated 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 (incorporated by reference to Exhibit 10.1.1.5 to Calpine Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, filed with the SEC on November 9, 2006).
10.1.6		Third Amendment, dated as of December 20, 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, Credit Suisse, Cayman Islands Branch, as administrative agent for the Second Priority Term Lenders (incorporated by reference to Exhibit 10.*1.6 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, filed with the SEC on January 31, 2007).
10.2		Membership Interest Purchase Agreement, dated as of November 3, 2006, by and between Goldendale Energy Center, LLC, as seller, and Puget Sound Energy Center, as buyer (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006, filed with the SEC on December 14, 2006).
31.1		Certification of the President and Corporate Secretary 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 and Treasurer 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 President and Corporate Secretary and Chief Financial Officer and Treasurer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*

____________

*	Filed herewith.

Index Definitions

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each of the registrants has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

CALPINE GENERATING COMPANY, LLC

CALGEN FINANCE CORP.

	By:	/s/ CHARLES B. CLARK, JR.
		Charles B. Clark, Jr.
		Chief Financial Officer and Treasurer
		(Principal Financial Officer)
Date: January 30, 2007
Date: January 31, 2007

Index Definitions

The following exhibits are filed herewith unless otherwise indicated:

EXHIBIT INDEX

Exhibit
Number		Description

3.1		Amended and Restated Certificate of Formation of Calpine Generating Company, LLC (incorporated by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-4 (Registration No. 333-117335), filed with the SEC on July 13, 2004).

3.2		Certificate of Incorporation of CalGen Finance Corp. (incorporated by reference to Exhibit 3.2 to the Company’s Registration Statement on Form S-4 (Registration No. 333-117335), filed with the SEC on July 13, 2004).

3.3		Limited Liability Company Operating Agreement of Calpine Generating Company, LLC (incorporated by reference to Exhibit 3.93 to the Company’s Registration Statement on Form S-4 (Registration No. 333-117335), filed with the SEC on July 13, 2004).

3.4		Bylaws of CalGen Finance Corp. (incorporated by reference to Exhibit 3.94 to the Company’s Registration Statement on Form S-4 (Registration No. 333-117335), filed with the SEC on July 13, 2004).

10.1.1		$2,000,000,000 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 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 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).

10.1.2		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, and 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).

10.1.3		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, and Credit Suisse, Cayman Islands Branch, as administrative agent for the Second Priority Term Lenders. (Incorporated by reference to Exhibit 10.1.1.3 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).

Index Definitions

Exhibit
Number		Description
10.1.4		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, Credit Suisse, Cayman Islands Branch, as administrative agent for the Second Priority Term Lenders (incorporated by reference to Exhibit 10.1.2.4 to Calpine Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, filed with the SEC on November 9, 2006).
10.1.5		Letter Agreement, dated 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 (incorporated by reference to Exhibit 10.1.1.5 to Calpine Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, filed with the SEC on November 9, 2006).
10.1.6		Third Amendment, dated as of December 20, 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, Credit Suisse, Cayman Islands Branch, as administrative agent for the Second Priority Term Lenders (incorporated by reference to Exhibit 10.*1.6 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, filed with the SEC on January 31, 2007).
10.2		Membership Interest Purchase Agreement, dated as of November 3, 2006, by and between Goldendale Energy Center, LLC, as seller, and Puget Sound Energy Center, as buyer (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006, filed with the SEC on December 14, 2006).
31.1		Certification of the President and Corporate Secretary 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 and Treasurer 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 President and Corporate Secretary and Chief Financial Officer and Treasurer 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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