Edgar Filing: CALPINE CORP

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K


(Mark One)
þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the fiscal year ended December 31, 2005

or

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the transition period from to

Commission file number: 1-12079

Calpine Corporation

(A Delaware Corporation)

I.R.S. Employer Identification No. 77-0212977

50 West San Fernando Street

San Jose, California 95113

Telephone: (408) 995-5115

Securities registered pursuant to Section 12(b) of the Act:

Calpine Corporation Common Stock, $.001 Par Value

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

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

Large accelerated filer þ Accelerated filer o Non-accelerated filer o

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

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

Calpine Corporation: 568,957,616 shares of common stock, par value $.001, were outstanding as of May 17, 2006.

State the aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2005, the last business day of the registrant’s most recently completed second fiscal quarter: approximately $1.9 billion.

FORM 10-K

ANNUAL REPORT

For the Year Ended December 31, 2005

TABLE OF CONTENTS


		Page

PART I
Item 1.	Business		8
Item 1A.	Risk Factors		38
Item 1B.	Unresolved Staff Comments		58
Item 2.	Properties		58
Item 3.	Legal Proceedings		59
Item 4.	Submission of Matters to a Vote of Security Holders		59
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		59
Item 6.	Selected Financial Data		60
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		62
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		114
Item 8.	Financial Statements and Supplementary Data		114
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		114
Item 9A.	Controls and Procedures		114
Item 9B.	Other Information		117
PART III
Item 10.	Directors and Executive Officers of the Registrant		117
Item 11.	Executive Compensation		122
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		129
Item 13.	Certain Relationships and Related Transactions		130
Item 14.	Principal Accounting Fees and Services		131
PART IV
Item 15.	Exhibits, Financial Statement Schedules		131
Signatures and Power of Attorney			145
Index to Consolidated Financial Statements and Other Information			147
EXHIBIT 2.6
EXHIBIT 4.13.5
EXHIBIT 4.13.6
EXHIBIT 4.21.1
EXHIBIT 4.21.2
EXHIBIT 4.22
EXHIBIT 10.1.1.1
EXHIBIT 10.1.1.2
EXHIBIT 10.1.2
EXHIBIT 10.2.6.5
EXHIBIT 10.2.6.6
EX-10.5.2
EX-10.5.3
EXHIBIT 10.5.9
EXHIBIT 12.1
EXHIBIT 21.1
EXHIBIT 31.1
EXHIBIT 31.2
EXHIBIT 32.1
EXHIBIT 99.1

DEFINITIONS

As used in this Form 10-K, the abbreviations contained herein have the meanings set forth below. Additionally, the terms, “the Company,” “Calpine,” “we,” “us” and “our” refer to Calpine Corporation and its subsidiaries, unless the context clearly indicates otherwise.


Abbreviation		Definition

2004 Form 10-K		Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2004, filed with the SEC on March 31, 2005, as modified by its Current Report on Form 8-K dated December 31, 2004, filed with the SEC on October 17, 2005, to reflect the effect of certain discontinued operations
2006 Convertible Notes		4% Convertible Senior Notes Due 2006
2014 Convertible Notes		Contingent Convertible Notes Due 2014
2015 Convertible Notes		7³/4 % Contingent Convertible Notes Due 2015
2023 Convertible Notes		4³/4 % Contingent Convertible Senior Notes Due 2023
Acadia PP		Acadia Power Partners, LLC
AELLC		Androscoggin Energy LLC
AICPA		American Institute of Certified Public Accountants
AMS		Aquila Merchant Services, Inc.
AOCI		Accumulated Other Comprehensive Income
APB		Accounting Principles Board
Aries		MEP Pleasant Hill, LLC
ARO		Asset Retirement Obligation
Auburndale PP		Auburndale Power Partners, L.P.
Bankruptcy Code		United States Bankruptcy Code
Bankruptcy Courts		The U.S. Bankruptcy Court and the Canadian Court
BBPTS		Babcock Borsig Power Turbine Services
Bcfe		Billion cubic feet equivalent
Bear Stearns		Bear Stearns Companies, Inc.
BPA		Bonneville Power Administration
Btu(s)		British thermal unit(s)
CAISO		California Independent System Operator
CalBear		CalBear Energy, LP
CalGen		Calpine Generating Company, LLC, formerly Calpine Construction Finance Company II LLC
Calpine Capital Trusts		Trust I, Trust II and Trust III
Calpine Cogen		Calpine Cogeneration Corporation, formerly Cogen America
Calpine Debtor(s)		The U.S. Debtors and the Canadian Debtors
Calpine Jersey I		Calpine (Jersey) Limited
Calpine Jersey II		Calpine European Funding (Jersey) Limited
CalPX		California Power Exchange
CalPX Price		CalPX zonal day-ahead clearing price
Canadian Court		The Court of Queen’s Bench of Alberta, Judicial District of Calgary
Canadian Debtor(s)		The subsidiaries and affiliates of Calpine Corporation that have been granted creditor protection under the CCAA in the Canadian Court


Abbreviation		Definition

Cash Collateral Order		Second Amended Final Order of the U.S. Bankruptcy Court Authorizing Use of Cash Collateral and Granting Adequate Protection, dated February 24, 2006
CCAA		Companies’ Creditors Arrangement Act (Canada)
CCFC		Calpine Construction Finance Company, L.P
CCFCP		CCFC Preferred Holdings, LLC
CCRC		Calpine Canada Resources Company, formerly Calpine Canada Resources Ltd.
CDWR		California Department of Water Resources
CEC		California Energy Commission
CEM		Calpine Energy Management, L.P.
CERCLA		Comprehensive Environmental Response, Compensation and Liability Act, as amended, also called “Superfund”
CES		Calpine Energy Services, L.P.
CESCP		Calpine Energy Services Canada Partnership
CFE		Comision Federal de Electricidad (Mexico)
Chapter 11		Chapter 11 of the Bankruptcy Code
Chubu		Chubu Electric Power Company, Inc.
CIP		Construction in Progress
Clean Air Act		Federal Clean Air Act of 1970
Cleco		Cleco Corp.
CMSC		Calpine Merchant Services Company, Inc.
CNEM		Calpine Northbrook Energy Marketing, LLC
CNGLP		Calpine Natural Gas L.P.
CNGT		Calpine Natural Gas Trust
Cogen America		Cogeneration Corporation of America, now called Calpine Cogeneration Corporation
CPIF		Calpine Power Income Fund
CPLP		Calpine Power, L.P.
CPSI		Calpine Power Services, Inc.
CPUC		California Public Utilities Commission
Creed		Creed Energy Center, LLC
CTA		Cumulative Translation Adjustment
DB London		Deutsche Bank AG London
Deer Park		Deer Park Energy Center Limited Partnership
DIG		Derivatives Implementation Group
DIP		Debtor-in-possession


Abbreviation		Definition

DIP Facility		The Revolving Credit, Term Loan and Guarantee Agreement, dated as of December 22, 2005, as amended on January 26, 2006, and as amended and restated by that certain Amended and Restated Revolving Credit, Term Loan and Guarantee Agreement, dated as of February 23, 2005, 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, as amended
E&S		Electricity and steam
Eastman		Eastman Chemical Company
EIA		Energy Information Administration of the Department of Energy
EITF		Emerging Issues Task Force
Enron		Enron Corp.
Enron Canada		Enron Canada Corp.
Entergy		Entergy Services, Inc.
EOB		California Electricity Oversight Board
EPA		United States Environmental Protection Agency
EPAct (1992)(2005)		Energy Policy Act of 1992 — or — Energy Policy Act of 2005
EPS		Earnings per share
ERC(s)		Emission reduction credit(s)
ERCOT		Electric Reliability Council of Texas
ERISA		Employee Retirement Income Security Act
ESA		Energy Services Agreement
ESPP		2000 Employee Stock Purchase Plan
EWG(s)		Exempt wholesale generator(s)
Exchange Act		United States Securities Exchange Act of 1934, as amended
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FFIC		Fireman’s Fund Insurance Company
FIN		FASB Interpretation Number
FIN 46-R		FIN 46, as revised
First Priority Notes		9⁵/8 % First Priority Senior Secured Notes Due 2014
FPA		Federal Power Act
Freeport		Freeport Energy Center, LP
FSP		FASB staff positions
FUCO(s)		Foreign Utility Company(ies)
GAAP		Generally accepted accounting principles


Abbreviation		Definition

GE		General Electric International, Inc.
GEC		Gilroy Energy Center, LLC
GECF		GE Commercial Finance Energy Financial Services
General Electric		General Electric Company
Gilroy		Calpine Gilroy Cogen, L.P.
Gilroy 1		Calpine Gilroy 1, Inc.
Goose Haven		Goose Haven Energy Center, LLC
GPC		Geysers Power Company, LLC
Greenfield LP		Greenfield Energy Centre LP
Heat rate		A measure of the amount of fuel required to produce a unit of electricity
HIGH TIDES I		5³/4 % Convertible Preferred Securities, Remarketable Term Income Deferrable Equity Securities
HIGH TIDES II		5¹/2 % Convertible Preferred Securities, Remarketable Term Income Deferrable Equity Securities
HIGH TIDES III		5% Convertible Preferred Securities, Remarketable Term Income Deferrable Equity Securities
HRSG		Heat recovery steam generator
HTM		Heat Thermal Medium Heater System
IP		International Paper Company
IPP(s)		Independent power producer(s)
IRS		United States Internal Revenue Service
ISO		Independent System Operator
King City Cogen		Calpine King City Cogen, LLC
KWh		Kilowatt hour(s)
LCRA		Lower Colorado River Authority
LDC(s)		Local distribution company(ies)
LIBOR		London Inter-Bank Offered Rate
LNG		Liquid natural gas
LSTC		Liabilities Subject to Compromise
LTSA		Long Term Service Agreement
Mankato		Mankato Energy Center, LLC
Metcalf		Metcalf Energy Center, LLC
Mitsui		Mitsui & Co., Ltd.
MLCI		Merrill Lynch Commodities, Inc.
MMBtu		Million Btu
MMcfe		Million net cubic feet equivalent
Morris		Morris Energy Center
MW		Megawatt(s)
MWh		Megawatt hour(s)
NERC		North American Electric Reliability Council
NESCO		National Energy Systems Company
NGA		Natural Gas Act
NGPA		Natural Gas Policy Act


Abbreviation		Definition

NOL		Net operating loss
Non-Debtor(s)		The subsidiaries and affiliates of Calpine Corporation that are not Calpine Debtors
NOPR		Notice of Proposed Rulemaking
NOR		Notice of Rejection
NPC		Nevada Power Company
NYSE		New York Stock Exchange
O&M		Operations and maintenance
OCI		Other Comprehensive Income
Oneta		Oneta Energy Center
Ontelaunee		Ontelaunee Energy Center
OPA		Ontario Power Authority
OTC		Over-the-counter
Panda		Panda Energy International, Inc., and related party PLC II, LLC
PCF		Power Contract Financing, L.L.C.
PCF III		Power Contract Financing III, LLC
Petition Date		December 20, 2005
PG&E		Pacific Gas and Electric
Pink Sheets		Pink Sheets Electronic Quotation Service maintained by Pink Sheets LLC for the National Quotation Bureau, Inc.
PJM		Pennsylvania-New Jersey-Maryland
PLC		PLC II, LLC
POX		Plant operating expense
PPA(s)		Power purchase agreement(s)
PSM		Power Systems Mfg., LLC
PUC(s)		Public Utility Commission(s)
PUHCA 1935		Public Utility Holding Company Act of 1935
PUHCA 2005		Public Utility Holding Company Act of 2005
PURPA		Public Utility Regulatory Policies Act of 1978
QF(s)		Qualifying facility(ies)
RCRA		Resource Conservation and Recovery Act
RMR Contracts		Reliability Must Run contracts
Rosetta		Rosetta Resources Inc.
SAB		Staff Accounting Bulletin
Saltend		Saltend Energy Centre
SDG&E		San Diego Gas & Electric Company
SDNY Court		United States District Court for the Southern District of New York
SEC		Securities and Exchange Commission
Second Priority Notes		Calpine Corporation’s Second Priority Senior Secured Floating Rate Notes due 2007, 8.500% Second Priority Senior Secured Notes due 2010, 8.750% Second Priority Senior Secured Notes due 2013 and 9.875% Second Priority Senior Secured Notes due 2011


Abbreviation		Definition

Second Priority Secured Debt Instruments		The Indentures between the Company and Wilmington Trust Company, as Trustee, relating to the Company’s Second Priority Senior Secured Floating Rate Notes due 2007, 8.500% Second Priority Senior Secured Notes due 2010, 8.750% Second Priority Senior Secured Notes due 2013, 9.875% Second Priority Senior Secured Notes due 2011 and the Credit Agreement among the Company, as Borrower, Goldman Sachs Credit Partners L.P., as Administrative Agent, Sole Lead Arranger and Sole Book Runner, The Bank of Nova Scotia, as Arranger and Syndication Agent, TD Securities (USA) Inc., ING (U.S.) Capital LLC and Landesbank Hessen-Thuringen, as Co-Arrangers, and Credit Lyonnais New York Branch and Union Bank of California, N.A., as Managing Agent, relating to the Company’s Senior Secured Term Loans Due 2007, in each case as such instruments may be amended from time to time
Securities Act		United States Securities Act of 1933, as amended
SFAS		Statement of Financial Accounting Standards
SFAS No. 123-R		SFAS No. 123, as revised
SFAS No. 128-R		SFAS No. 128, as revised
Siemens-Westinghouse		Siemens-Westinghouse Power Corporation (changed to Siemens Power Generation, Inc. on August 1, 2005)
SIP		1996 Stock Incentive Plan
SkyGen		SkyGen Energy LLC, now called Calpine Northbrook Energy, LLC
SOP		Statement of Position
SPE		Special-Purpose Entities
SPP		Southwest Power Pool
SPPC		Sierra Pacific Power Company
Trust I		Calpine Capital Trust
Trust II		Calpine Capital Trust II
Trust III		Calpine Capital Trust III
TSA(s)		Transmission service agreement(s)
TTS		Thomassen Turbine Systems, B.V.
ULC I		Calpine Canada Energy Finance ULC
ULC II		Calpine Canada Energy Finance II ULC
U.S		United States of America
U.S. Bankruptcy Court		United States Bankruptcy Court for the Southern District of New York
U.S. Debtor(s)		Calpine Corporation and each of its subsidiaries and affiliates that have filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court, which matters are being jointly administered in the U.S. Bankruptcy Court under the caption In re Calpine Corporation, et al., Case No. 95-60200 (BRL)
Valladolid		Valladolid III Energy Center
VIE(s)		Variable interest entity(ies)
Whitby		Whitby Cogeneration Limited Partnership

PART I


Item 1.	*Business*

In addition to historical information, this report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. 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 U.S. and Canadian bankruptcy cases, including impact on operations; (ii) our ability to attract, incentivize and motivate key employees and successfully implement new strategies; (iii) our ability to successfully reorganize and emerge from bankruptcy; (iv) our ability to attract and retain customers and counterparties; (v) our ability to implement our business plan; (vi) financial results that may be volatile and may not reflect historical trends; (vii) our ability to manage liquidity needs and comply with financing obligations; (viii) the direct or indirect effects on our business of our impaired credit including increased cash collateral requirements; (ix) the expiration or termination of our PPAs and the related results on revenues; (x) potential volatility in earnings and requirements for cash collateral associated with the use of commodity contracts; (xi) price and supply of natural gas; (xii) risks associated with power project development, acquisition and construction activities; (xiii) unscheduled outages of operating plants; (xiv) factors that impact the output of our geothermal resources and generation facilities, including unusual or unexpected steam field well and pipeline maintenance and variables associated with the waste water injection projects that supply added water to the steam reservoir; (xv) quarterly and seasonal fluctuations of our results; (xvi) competition; (xvii) risks associated with marketing and selling power from plants in the evolving energy markets; (xviii) present and possible future claims, litigation and enforcement actions; (xix) effects of the application of laws or regulations, including changes in laws or regulations or the interpretation thereof; and (xx) other risks identified in this report. You should also carefully review other reports that we file with the Securities and Exchange Commission. 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, proxy statements and other information with the SEC. You may obtain and copy any document we file with the SEC at the SEC’s public reference room at 100 F Street, NE, Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the SEC’s public reference facilities by calling the SEC at 1-800-SEC-0330. You can request copies of these documents, upon payment of a duplicating fee, by writing to the SEC at its principal office at 100 F Street, NE, Room 1580, Washington, D.C. 20549-1004. The SEC maintains an Internet website at http://www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. Our SEC filings are accessible through the Internet at that website.

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

OVERVIEW


	*Our Business*

We are an integrated power company owning, operating and developing power generation facilities and selling electricity, capacity and related electricity products and services, primarily in the United States and Canada. Based in San Jose, California, we were established as a corporation in 1984 and operate through a variety of divisions, subsidiaries and affiliates. Historically, we have focused on two efficient and clean types of power generation technologies: natural gas-fired combustion turbine and geothermal. At December 31, 2005, we owned or leased a portfolio of 73 clean burning natural gas-fired power plants and 19 geothermal power plants at The Geysers in California, with an aggregate net capacity of 26,459 MW. Additionally, we had interests in five new plants in construction and one expansion project. We offer to third parties energy procurement, scheduling, settlement and risk management services through our subsidiary CMSC. We have an O&M organization based in Folsom, California, which staffs and oversees the operations of our power plants. We also offer combustion turbine component parts through our subsidiary PSM. As discussed further below, on or after December 20, 2005, we and many of our subsidiaries filed voluntary petitions for reorganization in the United States and Canada and are currently operating as debtors-in-possession under the protection of the United States and Canadian laws, and, as part of our reorganization process, we are reevaluating whether to continue in or to exit some of our business activities. See “— Strategy,” below.

We draw on PSM’s capabilities to design and manufacture high performance combustion system and turbine blade parts with the objective of enhancing the performance of our modern portfolio of gas-fired power plants and lowering our replacement parts and maintenance costs. PSM manufactures new vanes, blades, combustors and other replacement parts for our plants and for those owned and operated by third parties as well. It offers a wide range of Low Emissions Combustion (commonly referred to as LEC) systems and advanced airfoils designed to be compatible for retrofitting or replacing existing combustion systems or components operating in General Electric and Siemens-Westinghouse turbines.

CMSC provides us with the trading and risk management services needed to schedule power sales and to ensure fuel is delivered to our power plants on time to meet delivery requirements and to manage and optimize the value of our physical power generation assets. Our marketing and sales activities are directed towards our traditional load serving client base of local utilities, municipalities and cooperatives as well as industrial customers.

Additionally, we have developed information technology capabilities to enable us to operate our plants as an integrated system in many of our major markets (and thereby enhance the economic performance of our portfolio of assets) and to provide load-following and ancillary services to our customers. These capabilities, combined with our sales, marketing and risk management resources, enable us to add value to traditional commodity products.

We have acquired or built and now operate a modern and efficient portfolio of gas-fired generation assets. However, in certain markets our facilities have been significantly underutilized due to poor market conditions. Nonetheless, we believe that our low cost position, integrated operations and skill sets will allow us to emerge from bankruptcy protection based on a smaller, but economically viable and sustainable portfolio of generation assets.


	*Bankruptcy Cases*

The following discussion provides general background information regarding our bankruptcy cases, and is not intended to be an exhaustive description. Further information pertaining to our bankruptcy filings may be obtained through our website at www.calpine.com. Access to documents filed with the U.S. Bankruptcy Court and other general information about the U.S. bankruptcy cases is available at www.kccllc.net/calpine. Certain information regarding the Canadian cases under the CCAA, including the reports of the monitor appointed by the Canadian Court, is available at the monitor’s website at www.ey.com/ca/calpinecanada. The content of the foregoing websites is not a part of this report.

On December 20, 2005 and December 21, 2005 we and 254 of our direct and indirect wholly owned subsidiaries in the United States filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court and, in Canada, 12 of our wholly owned Canadian subsidiaries were granted relief in the Canadian Court under the CCAA, which, like Chapter 11 in the United States, allows for reorganization under the protection of the Canadian courts. On December 27, 2005, December 29, 2005, January 8, 2006, January 9, 2006, February 3, 2006 and May 2, 2006, a total of 19 additional wholly owned indirect subsidiaries of Calpine also commenced Chapter 11 cases under the Bankruptcy Code in the U.S. Bankruptcy Court. Certain other subsidiaries could file in the U.S. or Canada in the future. See Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview” for a discussion of the events leading up to our bankruptcy filings.

The Calpine Debtors are continuing to operate their business as debtors-in-possession, under the jurisdiction of the Bankruptcy Courts and in accordance with the applicable provisions of the Bankruptcy Code, the Federal Rules of Bankruptcy Procedure, the CCAA and applicable Bankruptcy Court orders, as well as other applicable laws and rules. In general, each of the Calpine Debtors is authorized to continue to operate as an ongoing business, but may not engage in certain transactions outside the ordinary course of business without the prior approval of the applicable Bankruptcy Court. Through our bankruptcy cases, we are endeavoring to restore the Company to financial health. As discussed more fully under “— Strategy,” below as well as in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and Notes 3 and 4 of the Notes to Consolidated Financial Statements, these efforts include reducing overhead and operating expenses, and discontinuing activities and disposing of assets without compelling profit potential, particularly near term profit potential. In addition, development activities will continue to be further reduced, and we expect that certain power plants or other of our assets will be sold (or that we will surrender certain leased power plants to the lessors of such plants), and that commercial operations may be suspended at certain of our power plants during our reorganization effort. It is also possible that some or all of our Canadian assets may be liquidated pursuant to the Canadian cases.

THE MARKET FOR ELECTRICITY

The electric power industry represents one of the largest industries in the United States and impacts nearly every aspect of our economy, with an estimated end-user market comprising approximately $296 billion of electricity sales in 2005 based on information published by the Energy Information Administration of the U.S. Department of Energy. Historically, the power generation industry was largely characterized by electric utility monopolies producing electricity from generating facilities owned by utilities and selling to a captive customer base. However, industry trends and regulatory initiatives have transformed some markets into more competitive arenas where load-serving entities and end-users may purchase electricity from a variety of suppliers, including IPPs, power marketers, regulated public utilities and others. For the past decade, the power industry has been deregulated at the wholesale level allowing generators to sell directly to the load serving entities such as public utilities, municipalities and electric cooperatives. Although industry trends and regulatory initiatives aimed at further deregulation have slowed, and markets vary by geographic region in terms of the level of competition, pricing mechanisms and pace of regulatory reform, the power industry continues to transform into a more competitive market.

The United States market consists of distinct regional electric markets, not all of which are effectively interconnected, so reserve margins vary from region to region. Due primarily to the completion of more than 200,000 MW of gas-fired combustion turbine projects in the past decade, we have seen power supplies and reserve margins increase in the last several years, accompanied by a decrease in liquidity in the energy trading markets. According to data published by Edison Electric Institute, the growth rate of overall consumption of electricity in 2005 compared to 2004 was estimated to be 3.7%. The estimated growth rates in our major markets were as follows: South Central (primarily Texas) 3.6%, Pacific Southwest (primarily California) (0.6)%, and Southeast 3.4%. The growth rate in supply has been diminishing with many developers canceling or delaying completion of their projects as a result of current market conditions. The supply and demand balance in the natural gas industry continues to be strained, with gas prices averaging $7.59/ MMBtu in 2006

through April, compared to averages of approximately $6.59 and $5.63/ MMBtu in the same periods in 2005 and 2004, respectively.

Even though most new power plants are fueled by natural gas, the majority of power generated in the U.S. is still produced by coal and nuclear power plants. The Energy Information Administration has estimated that approximately 50% of the electricity generated in the U.S. is fueled by coal, 19% by nuclear sources, 19% by natural gas, 6% by hydro, and 6% from fuel oil and other sources. As regulations continue to evolve, many of the current coal plants will likely be faced with having to install a significant amount of costly emission control devices. This activity could cause some of the oldest and dirtiest coal plants to be retired, thereby allowing a greater proportion of power to be produced by cleaner natural gas-fired generation.

STRATEGY

As indicated above, since December 20, 2005, the Calpine Debtors have sought to reorganize under the jurisdiction of the Bankruptcy Courts and in accordance with the applicable provisions of the Bankruptcy Code and the CCAA, as applicable. On February 1, 2006, and again on April 4, 2006, we announced the initial steps of a comprehensive program designed to stabilize, improve and strengthen our core power generation business and our financial health. This program is designed to help ensure that we will emerge from our reorganization as a profitable, stronger and more competitive power company. We are reducing activities and curtailing expenditures in certain non-core areas and business units. As part of this program, we have begun to implement staff reductions that will ultimately affect approximately 1,100 positions, or over one-third of our pre-petition date workforce, by the end of 2006. We expect that the staff reductions, together with non-core office closures and reductions in controllable overhead costs, will reduce annual operating costs by approximately $150 million, significantly improving our financial and liquidity positions.

The areas of our business that will be most immediately impacted by this program include:


	•	Business Development: We are limiting our new business development activities and are focusing our ongoing efforts on maximizing the value of our advanced development opportunities, including projects with long-term power contracts or in advanced contract negotiations. We will review for possible sale certain development projects and will continue to evaluate existing petroleum coke gasification development in Texas.

	•	Construction: We are completing construction projects with long-term power sales commitments and are significantly scaling back construction management activities. We are continuing to evaluate options for those projects without long-term PPAs, some of which have been identified for potential sale.

	•	Power Services: We are discontinuing all new business activity for Calpine Power Services, Inc. CPSI will continue to perform its service obligations under existing construction management and O&M contracts.

	•	Marketing and Sales: We are evaluating our future participation in certain power markets to determine the right balance between short-term, long-term and tolling contracts for the sale of our electrical generation. Until then, we are curtailing new retail power sales efforts and, while administering existing contracts, we are limiting our efforts to put long-term power contracts in place for existing generation plants.

	•	TTS: In keeping with our focus on the North American power generation sector, we have determined that TTS is not a core business for us and we are exploring the possible sale of this company.

In connection with this program, we announced on April 4, 2006, that we had identified approximately 20 facilities for potential disposition, including operating facilities and facilities in development or construction. As a result of our determination to seek to dispose of such facilities, as well as other factors, we have concluded that we are required under GAAP to recognize impairment charges of $2.4 billion with respect to the operating facilities identified as subjects for potential disposition and $2.1 billion with respect to development and construction assets and other investments, including the development and construction

facilities identified as subjects for potential disposition. See Note 6 of the Notes to Consolidated Financial Statements for further information regarding the impairment charges. We can make no assurance that we will not recognize additional material impairment charges, or incur material costs and expenses, in the future.

We have started the process of developing a new business plan, beginning with a comprehensive review of our power assets, business units and markets where we are active. Our goal is to improve near-term results, while positioning the Company for profitable growth in the future. This business plan will also serve as the foundation for our plan of reorganization, which will be developed once we complete our business plan. Throughout this process, we will continue to work closely with our creditors, the Bankruptcy Courts and other stakeholders to emerge from bankruptcy with a stronger financial position and a more profitable core business. The near and longer term goals of the business plan are as follows:


	•	Reduce negative cash flow and create a profitable, competitive and sustainable business with stable positive earnings


	•	Achieve positive operating cash flow in 2007

	•	Optimize our asset portfolio through selective asset sales and contract rejections

	•	Reduce operating cost and achieve greater operational efficiencies

	•	Reduce interest cost


	•	Simplify our business structure


	•	Define core businesses and functions

	•	Focus on new asset base and business functions

	•	Streamline management reporting processes and prioritize information reported

	•	Reduce management reporting overhead costs


	•	Simplify our project financing and overall corporate capital structure

	•	Improve access to working capital


	•	Align with new business model


	•	Motivate key employees to execute the goals of the business plan

	•	Formulate and implement a plan of reorganization

In implementing our corporate strategic objectives, the top priority for our company remains maintaining the highest level of integrity and transparency in all of our endeavors. We have adopted a code of conduct that is applicable to all employees, including our principal executive officer, principal financial officer and principal accounting officer, and to members of our Board of Directors. A copy of the code of conduct is posted on our website at www.calpine.com. We intend to post any amendments and any waivers to our code of conduct on our website in accordance with Item 5.05 of Form 8-K and Item 406 of Regulation S-K.

COMPETITION

Our commercial activity generally includes all those activities associated with acquiring the necessary fuel inputs and maintaining the necessary distribution channels to market our generated electricity and related products. The power sales competitive landscape consists of a patchwork of both competitive and highly regulated markets in which we compete against other IPPs, trading companies and regulated utilities to supply power. This patchwork has been caused by inconsistent transitions to deregulated markets across distinct geographic electricity markets in North America. For example, in markets where there is open competition, our gas-fired or geothermal merchant capacity (that which has not been sold under a long-term contract) competes directly on a real-time basis with all other sources of electricity such as nuclear, coal, oil, gas-fired, and renewable energy provided by others. However, there are other markets where the local utility still predominantly uses its own supply to satisfy its own demand before ordering competitively provided power

from others. Each of these markets offers a unique and challenging power sales environment, which is dependent on a variety of factors beyond the specific regulatory structure, including, among others: the fuel types (and their respective costs) and capacity of the various other generation sources in the market; the relative ease or difficulty in developing and constructing new capacity in the market; the particular transmission constraints that can limit, increase or otherwise alter the amount of lower-cost competition in a market; the fluctuations in supply due to planned and unplanned outages of various generation sources; the liquidity of various commercial products in a given market and the ability to hedge or optimize various positions a generator wants to take in a market; and short-term fluctuations in electricity demand or fuel supply due to weather or other factors.

We also compete to be the low cost producer of gas-fired power. We strive to have better efficiency, start and stop our combustion turbines using less fuel, operate with the fewest forced outages and maximum availability and to accomplish all of this while producing less pollutants than competing gas plants and those using other fuels.

ENVIRONMENTAL STEWARDSHIP

Our goal is to produce relatively low cost gas-fired electricity with minimal impact on the environment. To achieve this we have assembled the largest fleet of combined-cycle natural gas-fired power plants and the largest fleet of geothermal power facilities in North America.

Both fleets utilize state-of-the-art technology to achieve our goal of environmentally friendly power generation.

Our fleet of modern, combined-cycle natural gas-fired power plants is highly efficient. Our plants consume significantly less fuel to generate a megawatt hour of electricity than older boiler/steam turbine power plants. This means that less air pollutants enter the environment per unit of electricity produced, especially compared to electricity generated by coal-fired or oil-fired power plants.

Calpine’s 750-MW fleet of geothermal power plants utilizes natural heat sources from within the earth to generate electricity with negligible air emissions.

The table below summarizes approximate air pollutant emission rates from Calpine’s combined-cycle natural gas-fired power plants and our geothermal power plants compared to average emission rates from U.S. coal, oil and gas-fired power plants.

Air Pollutant Emission Rates — Pounds of Pollutant Emitted

per MWh of Electricity Generated

Average

Calpine Power Plants

US Coal, Oil &

Gas-Fired

Combined-Cycle

% Less Than

Geothermal

% Less Than

Air Pollutants

Power Plant(1)

Power Plant(2)

Avg US Plant

Power Plant(3)

Avg US Plant

Nitrogen Oxides, NOx

Acid rain, smog and fine particulate formation

3.10

0.21

93.2% Less

0.00074

99.9% Less

Sulphur Dioxide, SO(2)

Acid rain and fine particulate formation

8.09

0.005

99.9% Less

0.00015

99.9% Less

Mercury, Hg

Neurotoxin

0.000036

100% Less

0.000008

77.8% Less

Carbon Dioxide, CO(2)

Principal greenhouse gas — contributor to climate change

1,919

882

54.0% Less

80.8

95.86% Less

Particulate Matter, PM

Respiratory health effects

0.5

0.037

92.6% Less

0.014

97.2% Less


(1)	The U.S. fossil fuel fleet’s emission rates were obtained from the U.S. Department of Energy’s Electric Power Annual Report for 2004. Emission rates are based on 2004 emissions and net generation.

(2)	Calpine’s combined-cycle power plant emission rates are based on 2005 data.

(3)	Calpine’s geothermal power plant emission rates are based on 2004 data and include expected results from the mercury abatement program currently in process.

Our environmental record has been widely recognized.


	•	PSM is developing gas turbine components to improve turbine efficiency and to reduce emissions.

	•	Calpine Power Company has instituted a program of proprietary operating procedures to reduce gas consumption and lower air pollutant emissions per MWh of electricity generated.

	•	The American Lung Associations of the Bay Area selected Calpine and its Geysers geothermal operation for the 2004 Clean Air Award for Technology Development to recognize “Calpine’s commitment to clean renewable energy, which improves air quality and helps us all breathe easier.”

	•	Calpine joined the EPA’s Climate Leaders Program, which is intended to encourage climate change strategies, help establish future greenhouse gas emission reduction goals, and increase energy efficiency among participants. As part of Climate Leaders, Calpine has submitted data on greenhouse gas emissions annually since 2003, from all its natural gas-fired power plants, The Geysers and its natural gas production facilities located throughout the United States.

	•	Calpine became the first IPP to earn the distinction of Climate Action Leader^tm, and has certified its 2003 and 2004 CO₂ emissions inventory with the California Climate Action Registry. Calpine continues to publicly and voluntarily report its CO₂ emissions from generation of electricity in California under this rigorous registry program.

	•	Calpine was awarded a 2005 Flex Your Power Honorable Mention for our outstanding achievements in energy efficiency in the Innovative Products and Services category for our Performance Optimization Program and Santa Rosa Geysers Recharge Project.

	•	Calpine is one of several Silicon Valley firms pledging to reduce area CO₂ emissions to 20% below 1990 levels by 2010 as a participant in the Sustainable Silicon Valley Project, a multi-stakeholder collaborative initiative to produce significant environmental improvement and resource conservation in Silicon Valley through the development and implementation of a regional environmental management system.

RECENT DEVELOPMENTS

On January 26, 2006, the U.S. Bankruptcy Court granted final approval of our $2 billion DIP Facility. The DIP Facility will be used to fund our operations during our Chapter 11 restructuring. In addition, as described below, a portion of the DIP Facility was used to retire certain facility operating lease obligations at The Geysers. In addition, pursuant to the May 3, 2006 amendment, borrowings under the DIP Facility may be used to repay a portion of the First Priority Notes. The DIP Facility closed on December 22, 2005, with limited access to the commitments, pursuant to the interim of the U.S. Bankruptcy Court and was amended and restated and closed on February 23, 2006 funding the term loans. It consisted of a $1 billion revolving credit facility (including a $300 million letter of credit subfacility and a $10 million swingline subfacility), priced at LIBOR plus 225 basis points or base rate plus 125 basis points; $400 million first-priority term loan, priced at LIBOR plus 225 basis points or base rate plus 125 basis points; and $600 million second-priority term loan, priced at LIBOR plus 400 basis points or the base rate plus 300 basis points. The DIP Facility will remain in place until the earlier of an effective plan of reorganization on December 20, 2007.

Effective January 27, 2006, Ann B. Curtis, one of the founders of the Company, resigned from the Board of Directors and from her positions as Vice Chairman of the Board, Executive Vice President and Corporate Secretary.

On January 30, 2006, we announced the appointment of Scott J. Davido as Executive Vice President and Chief Financial Officer effective February 1, 2006. On March 3, 2006, we announced that Mr. Davido will also take on the role of Chief Restructuring Officer.

On February 1, 2006, we announced the initial steps of a comprehensive program designed to stabilize, improve and strengthen our core power generation business and financial health and, on March 3, 2006, we announced a corporate management and organizational restructuring as one of the steps in implementing this program. Pursuant to this program, we indicated that we will focus on power generation and related commercial activities in the United States while reducing activities and curtailing expenditures in certain non-core areas and business units. On April 4, 2006, we identified approximately 20 power plants in operation or under construction that are no longer considered to be core operations due to a combination of factors, including financial performance, market prospects and strategic fit. Accordingly, we will be seeking to sell certain of these assets by the end of 2006. In addition, we will close our office in Boston, Massachusetts, and have already closed our offices in Dublin, California, Denver and Fort Collins, Colorado, Deer Park, Texas, Portland, Oregon, Tampa, Florida and Atlanta, Georgia. As we complete asset sales and construction activities, we expect to reduce our workforce by approximately 1,100 positions, or over one third of our pre-petition date workforce by, the end of 2006. At the completion of this effort, we expect to retain a generating portfolio of clean and reliable geothermal and natural gas-fired power plants located in our key North American markets.

On February 3, 2006, as part of finalizing the collateral structure of the DIP Facility, we closed a transaction pursuant to which we acquired The Geysers operating lease assets and paid off the related lessor’s third party debt for approximately $275.1 million (including the $157.6 million purchase price and $109.3 million to pay related debt and costs and expenses of the transaction). As a result of this transaction, we became the 100% owner of The Geysers assets. Previously, we had leased the 19 Geysers power plants pursuant to a leveraged lease. Upon completion of this transaction, The Geysers assets were pledged as security for the DIP Facility.

On February 6, 2006, we filed a notice of rejection of our leasehold interests in the Rumford power plant and the Tiverton power plant with the U.S. Bankruptcy Court, and noticed the surrender of the two plants to their owner-lessor. The owner-lessor has declined to take possession and control of the plants, which are not currently being dispatched but are being maintained in operating condition. The deadline for filing objections to the notice of rejection, which pursuant to a U.S. Bankruptcy Court order regarding expedited lease rejection procedures was originally set for February 16, 2006, was consensually extended to April 14, 2006. Both the indenture trustee related to the leaseholds and the owner-lessor filed objections to the rejection notice on that date. Additionally, the indenture trustee filed a motion to withdraw the reference of the rejection notice to the SDNY Court, arguing that the U.S. Bankruptcy Court does not have jurisdiction over the lease rejection dispute. The ISO New England, Inc. has separately filed a motion to withdraw the reference of the rejection notice to the SDNY Court on similar grounds. A hearing is currently scheduled for May 24, 2006 before the U.S. Bankruptcy Court to determine whether or not to approve the rejection and any other matters raised by the objections. However, such hearing date is subject to change. The Rumford and Tiverton power plants represent a combined 530 MW of installed capacity with the output sold into the New England wholesale market.

On February 8, 2006, David C. Merritt was elected to the Board of Directors. Mr. Merritt also serves as a member of the Audit Committee and the Nominating and Governance Committee of the Board of Directors.

On February 15, 2006, we entered into a non-binding letter of intent contemplating the negotiation of a definitive agreement for the sale of Otay Mesa Energy Center to SDG&E. The letter included a period of exclusivity which expired May 1, 2006. The parties are discussing a possible extension of exclusivity. Any final, definitive agreement would require the approval of the CPUC and the U.S. Bankruptcy Court. Construction of the Otay Mesa Energy Center, a 593-MW power plant, located in San Diego County, began in 2001 and has proceeded only gradually while we have sought certain regulatory approvals and, more recently, as a result of the negotiations with SDG&E.

On February 22, 2006, CCFC announced the commencement of a solicitation (as amended on March 10, 2006) for consents to, among other things, a waiver of a default under the indenture governing its $415.0 million in principal amount of Second Priority Senior Secured Floating Rate Notes due 2011 and under the credit agreement governing its $385.0 million First Priority Senior Secured Institutional Term Loans due 2009. The proposed waivers would waive certain existing defaults under the indenture and the

On March 1, 2006, upon receipt of U.S. Bankruptcy Court approval, we implemented a severance program that provides eligible employees, whose employment is involuntarily terminated in connection with workforce reductions, with certain severance benefits, including base salary continuation for specified periods based on the employee’s position and length of service.

On March 3, 2006, pursuant to the Cash Collateral Order, the U.S. Debtors and the Official Committee of Unsecured Creditors of Calpine Corporation and the Ad Hoc Committee of Second Lien Holders of Calpine Corporation agreed, in consultation with the indenture trustee for the First Priority Notes on the designation of nine projects that, absent the consent of the committees or unless ordered by the U.S. Bankruptcy Court, may not receive funding, other than in certain limited amounts that were agreed to by the U.S. Debtors and the committees in consultation with the First Priority Notes trustee. The nine designated projects are the Clear Lake Power Plant, Dighton Power Plant, Fox Energy Center, Newark Power Plant, Parlin Power Plant, Pine Bluff Energy Center, Rumford Power Plant, Texas City Power Plant, and Tiverton Power Plant. The U.S. Debtors may determine, in consultation with the committees and the First Priority Notes trustee, that additional projects should be added to, or that certain of the foregoing projects should be deleted from, the list of designated projects.

On March 15, 2006, CCFC entered into agreements amending, respectively, the indenture governing its $415.0 million aggregate principal amount of Second Priority Senior Secured Floating Rate Notes due 2011 and the credit agreement governing its $385.0 million in aggregate principal amount of First Priority Senior Secured Institutional Term Loans due 2009. CCFC also entered into waiver agreements providing for the waiver of certain defaults that occurred following our bankruptcy filings as a result of the failure of CES to make certain payments to CCFC under a PPA with CCFC. Each of the amendment agreements (i) provides that it would be an event of default under the indenture or the credit agreement, as applicable, if CES were to seek to reject the PPA in connection with the bankruptcy cases and (ii) allows CCFC to make a distribution to its indirect parent, CCFCP, to permit CCFCP to make a scheduled dividend payment on its redeemable preferred shares. The amendment agreements and waiver agreements were executed upon the receipt by CCFC of the consent of a majority of the holders of the notes and the agreement of a majority of the term loan lenders pursuant to a consent solicitation and request for amendment initiated on February 22, 2006, as amended on March 10, 2006. CCFC made a consent payment of $1.89783 per each $1,000 principal amount of notes or term loans held by consenting noteholders or term loan lenders, as applicable. None of CCFCP, CCFC, or any of their direct and indirect subsidiaries, is a Calpine Debtor or has otherwise sought protection under the Bankruptcy Code.

Also on March 15, 2006, CCFCP entered into an agreement with its preferred members holding a majority of the redeemable preferred shares issued by CCFCP amending its LLC operating agreement. The amendment agreement, among other things, acknowledges that the waiver agreements under the CCFC indenture and credit agreement satisfied the provisions of a standstill agreement entered into on February 24, 2006, between CCFCP and its preferred members pursuant to which the preferred members had agreed not to declare a “Voting Rights Trigger Event,” as defined in CCFCP’s LLC operating agreement, to have occurred or to seek to appoint replacement directors to the board of CCFCP, provided that certain conditions were met, including obtaining such waiver agreements. The amendment agreement also gives preferred members the right to designate a replacement for one of the independent directors of CCFCP; prior to the amendment, the preferred members had the right to consent to the designation, but not to designate, any replacement independent director. Neither CCFCP nor any of its subsidiaries, which include CCFC and CCFC’s subsidiaries, has made a bankruptcy filing or otherwise sought protection under the Bankruptcy Code.

the Master Transaction Agreement, CalBear and Bear Stearns were entitled to terminate the Master Transaction Agreement upon certain events of default by Calpine, CES or CMSC, including a bankruptcy filing by one or more of them. In connection with the termination of the Master Transaction Agreement, the related agreements entered into thereunder were also terminated, including (i) the Agency and Services Agreement by and among CMSC and CalBear, pursuant to which CMSC acted as CalBear’s exclusive agent for gas and power trading, (ii) the Trading Master Agreement among CES, CMSC and CalBear, pursuant to which CalBear had executed credit enhancement trades on behalf of CES and (iii) the ISDA Master Agreement, Schedule, and applicable annexes between CES and CalBear to effectuate the credit enhancement trades. As a result of the termination of the Master Transaction Agreement and related agreements, CMSC has the obligation to liquidate all trading positions of CalBear and terminate all transactions done in the name of CalBear, except as otherwise approved by CalBear. Bear Stearns may, at its option, take over such liquidation from CMSC. In addition, Bear Stearns continues to maintain ownership of all of the third party master agreements executed in connection with the CalBear relationship.

In the first quarter of 2006 we expect to record a charge for an expected allowable claim related to a guarantee by Calpine Corporation of obligations under a tolling agreement between CESCP and Calgary Energy Centre Limited Partnership. CESCP repudiated this tolling agreement in January 2006, and as a consequence, we expect to record a charge of approximately $233 million as a reorganization item expense in the three month period ended March 31, 2006.

On April 11, 2006, CCFC notified the holders of its notes and term loans that, as of April 7, 2006, a default had occurred under the credit agreement governing the term loans and the indenture governing the notes due to the failure of CES to make a payment with respect to a hedging transaction under the PPA with CCFC. If such default is not cured, or the PPA is not replaced with a substantially similar agreement, within 60 days following the occurrence of the default, such default will become an “event of default” under the instruments governing the term loans and the notes.

On April 11, 2006, the U.S. Bankruptcy Court granted our application for an extension of the period during which we have the exclusive right to file a reorganization plan or plans from April 20, 2006 to December 31, 2006, and granted us the exclusive right until March 31, 2007, to solicit acceptances of such plan or plans. In addition, the U.S. Bankruptcy Court granted each of the U.S. Debtors an additional 90 days (or until July 18, 2006, for most of the U.S. Debtors) to assume or reject non-residential real property leases. Also on April 11, 2006, the U.S. Bankruptcy Court granted our application for the repayment of a portion of a loan we had extended to CPN Insurance Corporation, our wholly owned captive insurance subsidiary. The repayment of this loan facilitates our ability to continue to provide a portion of our insurance needs through this subsidiary and thus provides us additional flexibility to be able to continue to implement a comprehensive and cost effective property insurance program.

On April 17, 2006, we announced that we expected to record approximately $5.5 billion in non-cash impairment charges for the twelve months ending December 31, 2005, which impairment charges have been reflected in the our financial statements included in this Report. Further, we stated that we expected to record additional non-cash valuation allowances of approximately $1.6 billion against deferred tax assets, which allowances have been reflected in the tax provision for 2005. We concluded that these charges were necessary due to multiple factors, including constraints arising as a result of our bankruptcy filing on December 20, 2005. As we continue to develop our business plan, and otherwise in connection with our emergence from bankruptcy, there could be additional impairment charges in future periods.

On April 18, 2006, we completed the sale of our 45% indirect equity interest in the 525-MW Valladolid III Energy Center to the two remaining partners in the project, Mitsui and Chubu, for $42.9 million, less a 10% holdback and transaction fees. Under the terms of the purchase and sale agreement, we received cash proceeds of $38.6 million at closing. The 10% holdback, plus interest, will be returned to us in one year’s time. We eliminated $87.8 million of non-recourse unconsolidated project debt, representing our 45% share of the total project debt of approximately $195.0 million. In addition, funds held in escrow for credit support of $9.4 million were released to us. We recorded an impairment charge of $41.3 million for our investment in the project during the year ended December 31, 2005.

The DIP Facility was amended on May 3, 2006. Among other things, the amendment provides extensions of time to provide certain financial information (including financial statements for the year ended December 31, 2005, and the quarter ended March 31, 2006) to the DIP Facility lenders and, provided that we obtain the approval of the U.S. Bankruptcy Court to repurchase the First Priority Notes, allows us to use borrowings under the DIP Facility to repurchase a portion of such First Priority Notes.

DESCRIPTION OF POWER GENERATION FACILITIES


							Market Share
NERC Region/ Country		Projects			Megawatts		(NERC/UK)

WECC			49			8,361		5%
ERCOT			12			7,666		9%
SERC			9			5,030		3%
MAIN			4	*		2,136		3%
SPP			3			1,674		4%
NEPOOL			5			1,272		4%
FRCC			3			875		2%
MAAC			3			193		1%
MAPP			1			375		1%
NYPOOL			5			334		1%
NPCC			2			510		1%

	TOTAL NERC		96			28,426		3%
Mexico			1			236		1%

	TOTAL		97			28,662		3%


*	Includes Phase II of Fox Energy Center, which was under construction as of December 31, 2005.

At December 31, 2005, we had ownership or lease interests in 92 operating power generation facilities representing 26,459 MW of net capacity. Of these projects, 73 are gas-fired power plants with a net capacity of 25,709 MW, and 19 are geothermal power generation facilities with a net capacity of 750 MW. We also have 5 new gas-fired projects and 1 expansion project currently under construction with a net capacity of 2,203 MW. Each of the power generation facilities currently in operation is capable of producing electricity for sale to a utility, other third-party end user or an intermediary such as a marketing company. Thermal energy (primarily steam and chilled water) produced by the gas-fired cogeneration facilities is sold to industrial and governmental users. As discussed above, we will seek to sell certain of these projects over the next year.

Our gas-fired and geothermal power generation projects produce electricity and thermal energy that is sold pursuant to short-term and long-term PPAs or into the spot market. Revenue from a PPA often consists of either energy payments or capacity payments or both. Energy payments are based on a power plant’s net electrical output, and payment rates are typically either at fixed rates or are indexed to market averages for energy or fuel. Capacity payments are based on all or a portion of a power plant’s available capacity. Energy payments are earned for each MWh of energy delivered, while capacity payments, under certain circumstances, are earned whether or not any electricity is scheduled by the customer and delivered.

Upon completion of our projects under construction, subject to any dispositions that may occur, we will provide operating and maintenance services for 95 of the 97 power plants in which we have an interest. Such services include the operation of power plants, geothermal steam fields, wells and well pumps, and gas pipelines. We also supervise maintenance, materials purchasing and inventory control, manage cash flow, train staff and prepare operating and maintenance manuals for each power generation facility that we operate. As a facility develops an operating history, we analyze its operation and may modify or upgrade equipment or adjust operating procedures or maintenance measures to enhance the facility’s reliability or profitability. These services are sometimes performed for third parties under the terms of an O&M agreement pursuant to which we are generally reimbursed for certain costs, paid an annual operating fee and may also be paid an incentive fee based on the performance of the facility. The fees payable to us may be subordinated to any lease payments or debt service obligations of financing for the project.

In order to provide fuel for the gas-fired power generation facilities in which we have an interest, natural gas is purchased from third parties under supply agreements and gas hedging contracts. Additionally, we could acquire natural gas reserves, although we have sold substantially all of our gas reserves purchased in prior years. We manage a gas-fired power facility’s fuel supply so that we protect the plant’s spark spread.

We currently own geothermal resources in The Geysers in Lake and Sonoma Counties in northern California from which we produce steam for our geothermal power generation facilities. In late 2003, we began to inject waste water from the City of Santa Rosa Recharge Project into our geothermal reservoirs. We expect this recharge project to extend the useful life and enhance the performance of The Geysers geothermal resources and power plants.

Certain power generation facilities in which we have an interest have been financed primarily with project financing that is structured to be serviced out of the cash flows derived from the sale of electricity (and, if applicable, thermal energy) produced by such facilities and generally provides that the obligations to pay interest and principal on the loans are secured solely by the capital stock or partnership interests, physical assets, contracts and/or cash flow attributable to the entities that own the facilities. The lenders under these project financings generally have no recourse for repayment against us or any of our assets or the assets of any other entity other than foreclosure on pledges of stock or partnership interests and the assets attributable to the entities that own the facilities. Certain of these facilities have filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code; however, we do not, at this time, consider the non-recourse debt related to these U.S. Debtor entities to be subject to compromise.

Substantially all of the power generation facilities in which we have an interest are located on sites which we own or lease on a long-term basis. See Item 2. “Properties.”

Set forth below is certain information regarding our operating power plants and plants under construction as of December 31, 2005.


					Megawatts

							With		Calpine Net		Calpine Net
			Number of		Baseload		Peaking		Interest		Interest with
			Plants		Capacity		Capacity		Baseload		Peaking

In operation
	Geothermal power plants			19		750		750		750		750
	Gas-fired power plants			73		21,660		26,935		20,543		25,709
Under construction
	New facilities			5		2,312		2,734		1,636		1,943
	Expansion/ Phase II			—		245		260		245		260

		Total		97		24,967		30,679		23,174		28,662


	*Operating Power Plants*


		Country,											Calpine Net
		US				With					Calpine Net		Interest
		State or		Baseload		Peaking		Calpine			Interest		with		Total 2005
		Can.		Capacity		Capacity		Interest			Baseload		Peaking		Generation
Power Plant		Province		(MW)		(MW)		Percentage			(MW)		(MW)		MWh(1)

Geothermal Power Plants
	Total Geothermal Power Plants(19)				750.0		750.0					750.0		750.0		6,704,751

Gas-Fired Power Plants
Freestone Energy Center			TX		1,022.0		1,022.0		100.0	%		1,022.0		1,022.0		4,187,391
Deer Park Energy Center			TX		792.0		1,019.0		100.0	%		792.0		1,019.0		5,691,076
Oneta Energy Center			OK		994.0		994.0		100.0	%		994.0		994.0		683,307
Delta Energy Center			CA		799.0		882.0		100.0	%		799.0		882.0		5,509,506
Morgan Energy Center			AL		722.0		852.0		100.0	%		722.0		852.0		1,208,479
Decatur Energy Center			AL		793.0		852.0		100.0	%		793.0		852.0		690,875
Broad River Energy Center			SC		—		847.0		100.0	%		—		847.0		662,103
Baytown Energy Center			TX		742.0		830.0		100.0	%		742.0		830.0		4,299,914
Pasadena Power Plant			TX		776.0		777.0		100.0	%		776.0		777.0		3,094,913
Magic Valley Generating Station			TX		700.0		751.0		100.0	%		700.0		751.0		3,082,194
Pastoria Energy Facility			CA		750.0		750.0		100.0	%		750.0		750.0		2,582,487
Hermiston Power Project			OR		546.0		642.0		100.0	%		546.0		642.0		3,650,823
Columbia Energy Center			SC		464.0		641.0		100.0	%		464.0		641.0		391,087
Rocky Mountain Energy Center			CO		479.0		621.0		100.0	%		479.0		621.0		3,249,691
Osprey Energy Center			FL		530.0		609.0		100.0	%		530.0		609.0		1,780,739
Acadia Energy Center			LA		1,092.0		1,210.0		50.0	%		546.0		605.0		2,738,118
Riverside Energy Center			WI		518.0		603.0		100.0	%		518.0		603.0		1,769,523
Metcalf Energy Center			CA		554.0		600.0		100.0	%		554.0		600.0		1,974,610
Brazos Valley Power Plant			TX		508.0		594.0		100.0	%		508.0		594.0		3,368,606
Aries Power Project			MO		523.0		590.0		100.0	%		523.0		590.0		285,452
Channel Energy Center			TX		527.0		574.0		100.0	%		527.0		574.0		2,800,139
Los Medanos Energy Center			CA		497.0		566.0		100.0	%		497.0		566.0		3,705,762
Sutter Energy Center			CA		535.0		543.0		100.0	%		535.0		543.0		2,472,080


	Country,											Calpine Net
	US				With					Calpine Net		Interest
	State or		Baseload		Peaking		Calpine			Interest		with		Total 2005
	Can.		Capacity		Capacity		Interest			Baseload		Peaking		Generation
Power Plant	Province		(MW)		(MW)		Percentage			(MW)		(MW)		MWh(1)

Corpus Christi Energy Center		TX		414.0		537.0		100.0	%		414.0		537.0		2,315,678
Texas City Power Plant		TX		457.0		534.0		100.0	%		457.0		534.0		1,860,795
Carville Energy Center		LA		455.0		531.0		100.0	%		455.0		531.0		2,062,451
South Point Energy Center		AZ		520.0		530.0		100.0	%		520.0		530.0		1,523,763
Westbrook Energy Center		ME		528.0		528.0		100.0	%		528.0		528.0		3,492,152
Zion Energy Center		IL		—		513.0		100.0	%		—		513.0		35,058
RockGen Energy Center		WI		—		460.0		100.0	%		—		460.0		332,447
Clear Lake Power Plant		TX		344.0		400.0		100.0	%		344.0		400.0		1,063,972
Hidalgo Energy Center		TX		499.0		499.0		78.5	%		392.0		392.0		1,790,681
Fox Energy Center(2)		WI		245.0		300.0		100.0	%		245.0		300.0		443,536
Blue Spruce Energy Center		CO		—		285.0		100.0	%		—		285.0		252,702
Goldendale Energy Center		WA		237.0		271.0		100.0	%		237.0		271.0		1,025,566
Tiverton Power Plant(3)		RI		267.0		267.0		100.0	%		267.0		267.0		1,822,302
Rumford Power Plant(3)		ME		263.0		263.0		100.0	%		263.0		263.0		1,022,754
Santa Rosa Energy Center		FL		250.0		250.0		100.0	%		250.0		250.0		1,150
Hog Bayou Energy Center		AL		235.0		237.0		100.0	%		235.0		237.0		20,432
Pine Bluff Energy Center		AR		184.0		215.0		100.0	%		184.0		215.0		1,228,979
Los Esteros Critical Energy Facility		CA		—		188.0		100.0	%		—		188.0		276,974
Dighton Power Plant		MA		170.0		170.0		100.0	%		170.0		170.0		517,445
Auburndale Power Plant		FL		150.0		150.0		100.0	%		150.0		150.0		628,849
Gilroy Energy Center		CA		—		135.0		100.0	%		—		135.0		52,968
Gilroy Cogeneration Plant		CA		117.0		128.0		100.0	%		117.0		128.0		111,608
King City Cogeneration Plant		CA		120.0		120.0		100.0	%		120.0		120.0		815,948
Parlin Power Plant		NJ		98.0		118.0		100.0	%		98.0		118.0		78,593
Auburndale Peaking Energy Center		FL		—		116.0		100.0	%		—		116.0		7,332
Kennedy International Airport Power Plant (“KIAC”)		NY		99.0		105.0		100.0	%		99.0		105.0		736,749
Pryor Power Plant		OK		38.0		90.0		100.0	%		38.0		90.0		315,955
Calgary Energy Centre(4)		AB		252.0		286.0		30.0	%		75.6		85.8		327,617
Bethpage Energy Center 3		NY		79.9		79.9		100.0	%		79.9		79.9		199,395
Island Cogeneration(4)		BC		219.0		250.0		30.0	%		65.7		75.0		2,051,155
Pittsburg Power Plant		CA		64.0		64.0		100.0	%		64.0		64.0		194,235
Bethpage Power Plant		NY		55.0		56.0		100.0	%		55.0		56.0		109,930
Newark Power Plant		NJ		50.0		56.0		100.0	%		50.0		56.0		46,061
Greenleaf 1 Power Plant		CA		49.5		49.5		100.0	%		49.5		49.5		280,203
Greenleaf 2 Power Plant		CA		49.5		49.5		100.0	%		49.5		49.5		254,054
Wolfskill Energy Center		CA		—		48.0		100.0	%		—		48.0		16,475
Yuba City Energy Center		CA		—		47.0		100.0	%		—		47.0		36,188
Feather River Energy Center		CA		—		47.0		100.0	%		—		47.0		13,346
Creed Energy Center		CA		—		47.0		100.0	%		—		47.0		9,657
Lambie Energy Center		CA		—		47.0		100.0	%		—		47.0		15,899


		Country,											Calpine Net
		US				With					Calpine Net		Interest
		State or		Baseload		Peaking		Calpine			Interest		with		Total 2005
		Can.		Capacity		Capacity		Interest			Baseload		Peaking		Generation
Power Plant		Province		(MW)		(MW)		Percentage			(MW)		(MW)		MWh(1)

Goose Haven Energy Center			CA		—		47.0		100.0	%		—		47.0		11,036
Riverview Energy Center			CA		—		47.0		100.0	%		—		47.0		21,032
Stony Brook Power Plant			NY		45.0		47.0		100.0	%		45.0		47.0		299,722
Bethpage Peaker			NY		—		46.0		100.0	%		—		46.0		120,983
King City Peaking Energy Center			CA		—		45.0		100.0	%		—		45.0		16,261
Androscoggin Energy Center(5)			ME		136.0		136.0		32.3	%		44.0		44.0		1,552
Watsonville (Monterey) Cogeneration Plant			CA		29.0		30.0		100.0	%		29.0		30.0		164,929
Agnews Power Plant			CA		28.0		28.0		100.0	%		28.0		28.0		162,623
Philadelphia Water Project			PA		—		23.0		83.0	%		—		19.1		—
Whitby Cogeneration(4)			ON		50.0		50.0		15.0	%		7.5		7.5		337,281
	Total Gas-Fired Power Plants (73)				21,659.9		26,934.9					20,542.7		25,709.3		88,405,348

	Total Operating Power Plants (92)				22,409.9		27,684.9					21,292.7		26,459.3		95,110,099

Consolidated Projects including plants with operating leases					21,752.9		26,962.9					21,099.9		26,247.0
Equity (Unconsolidated) Projects					657.0		722.0					192.8		212.3


(1)	Generation MWh is shown here as 100% of each plant’s gross generation in MWh.

(2)	Subsequent to December 31, 2005, Phase II of the Fox Energy Center entered commercial operation, resulting in a total net operating peaking capacity of the facility of 560 MW.

(3)	On February 6, 2006, we filed a Notice of Rejection with the Bankruptcy Court to terminate the underlying operating lease of this facility. See Note 3 of the Notes to Consolidated Financial Statements.

(4)	These power plants were deconsolidated as of December 31, 2005. See Note 10 of the Notes to Consolidated Financial Statements.

(5)	See Note 10 of the Notes to Consolidated Financial Statements for the status of this project.


	*Projects Under Active Construction (All Gas-Fired)*


														Calpine Net
							With					Calpine Net		Interest
					Baseload		Peaking		Calpine			Interest		with
					Capacity		Capacity		Interest			Baseload		Peaking
Power Plant			US State		(MW)		(MW)		Percentage			(MW)		(MW)

Projects Under Active Construction(1)
	Otay Mesa Energy Center			CA		510.0		593.0		100.0	%		510.0		593.0
	Mankato Power Plant			MN		292.0		375.0		100.0	%		292.0		375.0
	Fox Energy Center II			WI		245.0		260.0		100.0	%		245.0		260.0
	Freeport Energy Center			TX		210.0		236.0		100.0	%		210.0		236.0
	Greenfield Energy Centre			Canada		775.0		1,005.0		50.0	%		387.5		502.5
	Valladolid III Power Plant			Mexico		525.0		525.0		45.0	%		236.3		236.3

		Total Projects Under Active Construction				2,557.0		2,994.0					1,880.8		2,202.8


(1)	See “Projects Under Active Construction at December 31, 2005” below for current status of these projects.

ACQUISITIONS OF POWER PROJECTS AND PROJECTS UNDER CONSTRUCTION

We have extensive experience in the development and acquisition of power generation projects. We have historically focused principally on the development and acquisition of interests in gas-fired and geothermal power projects, although we may also consider projects that utilize other power generation technologies. We have significant expertise in a variety of power generation technologies and have substantial capabilities in each aspect of the development and acquisition process, including design, engineering, procurement, construction management, fuel and resource acquisition and management, power marketing, financing and operations.

As indicated above under “Strategy,” our development and acquisition activities have been scaled back, for the indefinite future, to focus on liquidity and operational priorities in connection with our reorganization and our restructuring program.


	*Projects Under Active Construction at December 31, 2005*

The development and construction of power generation projects involves numerous elements, including evaluating and selecting development opportunities, designing and engineering the project, obtaining PPAs in some cases, acquiring necessary land rights, permits and fuel resources, obtaining financing, procuring equipment and managing construction. We intend to focus on completing certain of our projects already in construction, while construction on certain of the other projects may remain in suspension or they may be sold. We do not expect to start development or construction on new projects at least until after we have developed our plan of reorganization, however, in certain cases exceptions may be made if power contracts and financing are available and attractive returns are expected. For the year ended December 31, 2005, we recorded impairment charges of approximately $2.1 billion with respect to our development and construction projects, including joint venture investments and other assets. See Note 6 of the Notes to Consolidated Financial Statements for more information.

Otay Mesa Energy Center. In July 2001, we acquired Otay Mesa Generating Company, LLC and the associated development rights including a license permitting construction of the plant from the California Energy Commission. Construction of this 593-MW facility, located in southern San Diego County, California began in 2001. In February 2004 we signed a ten-year PPA with SDG&E for delivery of up to 615 MW of capacity and energy beginning January 1, 2008. Power deliveries are scheduled to begin on January 1, 2008, subject to certain conditions that have not yet been satisfied. On February 15, 2006, we entered into a non-binding letter of intent contemplating the negotiation of a definitive agreement for the sale of the Otay Mesa

facility to SDG&E. Construction of this facility has proceeded only gradually while we have sought certain regulatory approvals and, more recently, as a result of the negotiations with SDG&E. See Note 34 of the Notes to Consolidated Financial Statements for more information. Construction of this facility has proceeded only gradually while we have sought certain regulatory approvals and, more recently, as a result of the negotiations with SDG&E.

Mankato Power Plant. In March 2004, we announced plans to build, own and operate a 375-MW, natural gas-fired power plant in Mankato, Minnesota. Electric power generated at the facility will be sold to Northern States Power Co. under a 20-year purchased power agreement. Construction began in March 2004 and we expect commercial operation of the facility to commence in July 2006.

Fox Energy Center, Phase II. In 2003, we acquired the fully permitted development rights to the 560-MW Fox Energy Center in Kaukauna, Wisconsin. Commercial operation of Phase I began in June 2005. In March 2006, Phase II entered commercial operation resulting in the total net operating capacity for the facility of 560 MW. Output from the facility is sold under contract to Wisconsin Public Service.

Freeport Energy Center. In May 2004, we announced plans to build and own a 236-MW, natural gas-fired cogeneration energy center in Freeport, Texas. Under a 25-year agreement, up to 210 MW of electricity and one million pounds per hour of steam generated at the facility will be sold to Dow Chemical Co. in Freeport, Texas. Dow Chemical Co. will operate this facility. Construction of the facility began in June 2004. Commercial operations will commence in multiple phases, with the first phases completed in January 2006 and the last phase expected to occur in November 2006.

Greenfield Energy Centre. In April 2005, we announced, together with Mitsui, an intention to build, own and operate a 1,005-MW, natural gas-fired energy center located in the Township of St. Clair in Ontario, Canada. The facility will deliver electricity to the OPA under a 20-year Clean Energy Supply contract. We contributed three combustion gas turbine generators and one steam turbine generator to the project, giving us a 50% interest in the facility. Mitsui owns the remaining 50% interest. Construction began in November 2005.

Valladolid III Power Plant. In October 2003, we announced, together with Mitsui of Tokyo, Japan, an intention to build, own and operate a 525-MW natural gas-fired energy center, Valladolid, for CFE at Valladolid in the Yucatan Peninsula. The facility will deliver electricity to CFE under a 25-year PPA. We supplied two combustion gas turbines to the project, giving us a 45% indirect equity interest in the facility. Mitsui and Chubu were to own the remaining interest. Construction began in May 2004, and on April 18, 2006 the sale of our 45% indirect equity interest in Valladolid was completed. See Note 34 of the Notes to Consolidated Financial Statements for more information.

OIL AND GAS PROPERTIES

In July 2005, we completed the sale of substantially all of our remaining oil and natural gas assets. The divestiture of our historical oil and gas assets is discussed under Note 13 of the Notes to Consolidated Financial Statements.

Our consolidated financial statements reflect the oil and gas assets and related operations as discontinued operations.

MARKETING, HEDGING, OPTIMIZATION AND TRADING ACTIVITIES

Most of the electric power generated by our plants is scheduled and settled by our marketing and risk management unit, CES, which sells it to load-serving entities such as utilities, industrial and large retail end users, and to other third parties including power trading and marketing companies. CES enters into physical and financial purchase and sale transactions as part of its hedging, balancing and optimization activities.

The hedging, balancing and optimization activities that we engage in are directly related to exposures that arise from our ownership and operation of power plants and our open gas positions and are designed to protect or enhance our “spark spread” (the difference between our fuel cost and the revenue we receive for our

electric generation). In many of these transactions CES purchases and resells power and gas in contracts with third parties.

We utilize derivatives, which are defined in SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138, “Accounting for Certain Derivative Investments,” and SFAS No. 149, “Amendment of Statement 133 on Derivative Investment Hedging Activities,” to include many physical commodity contracts and commodity financial instruments such as exchange-traded swaps and forward contracts, to optimize the returns that we are able to achieve from our power plant assets and our open gas positions. From time to time we have entered into contracts considered energy trading contracts under EITF Issue No. 02-03, “Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” However, our risk managers have low capital at risk and value at risk limits for energy trading, and our risk management policy limits, at any given time, our net sales of power to our generation capacity and limits our net purchases of gas to our fuel consumption requirements on a total portfolio basis. This model is markedly different from that of companies that engage in significant commodity trading operations that are unrelated to underlying physical assets. Derivative commodity instruments are accounted for under the requirements of SFAS No. 133. The EITF reached a consensus under EITF Issue No. 02-03 that gains and losses on derivative instruments within the scope of SFAS No. 133 should be shown net in the income statement if the derivative instruments are held for trading purposes. In addition we present on a net basis certain types of hedging, balancing and optimization revenues and costs of revenue in accordance with EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments that are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ As Defined in 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,’ ” which we adopted prospectively on October 1, 2003. See Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Application of Critical Accounting Policies” and Note 2 of the Notes to Consolidated Financial Statements for additional discussion of this standard. We have received approval from the U.S. Bankruptcy Court pursuant to our “first day” and subsequent motions to continue to collateralize our gas supply contracts and enter into and collateralize trading contracts. These orders, together with the Cash Collateral Order and our DIP Facility, have allowed us to continue our marketing, hedging, optimization and trading activities during the pendency of the bankruptcy cases.

In some instances economic hedges may not be designated as hedges for accounting purposes. An example of an economic hedge that is not a hedge for accounting purposes would be a long-term fixed price electric sales contract that economically hedges us against the risk of falling electric prices, but which for accounting purposes can be exempted from derivative accounting under SFAS No. 133 as a normal purchase and sale. For a further discussion of our derivative accounting methodology, see Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Application of Critical Accounting Policies.”

GOVERNMENT REGULATION

We are subject to complex and stringent energy, environmental and other governmental laws and regulations at the federal, state and local levels in connection with the development, ownership and operation of our energy generation facilities, and in connection with the purchase and sale of electricity and natural gas. Federal laws and regulations govern, among other things, transactions by electric and gas companies, the ownership of these facilities, and access to and service on the electric and natural gas transmission grids.

In most instances, public utilities that serve retail customers are subject to rate regulation by the state’s utility regulatory commission. A state utility regulatory commission is often primarily responsible for determining whether a public utility may recover the costs of wholesale electricity purchases or other supply procurement-related activities through the retail rates the utility charges its customers. The state utility regulatory commission may, from time to time, impose restrictions or limitations on the manner in which a public utility may transact with wholesale power sellers, such as independent power producers. Under certain circumstances where specific exemptions are otherwise unavailable, state utility regulatory commissions may have broad jurisdiction over non-utility electric power plants.

Energy producing facilities are also subject to federal, state and local laws and administrative regulations which govern the emissions and other substances produced, discharged or disposed of by a plant and the geographical location, zoning, land use and operation of a plant. Applicable federal environmental laws typically have both state and local enforcement and implementation provisions. These environmental laws and regulations generally require that a wide variety of permits and other approvals be obtained before the commencement of construction or operation of a generation facility and that the facility then operate in compliance with such permits and approvals.

There have been a number of federal legislative and regulatory actions that have recently changed, and will continue to change, how the energy markets are regulated. Additional legislative and regulatory initiatives may occur. We cannot provide assurance that any legislation or regulation ultimately adopted would not adversely affect our existing projects. See the risk factors set forth under “Item 1A — Risk Factors — California Power Market” and “— Government Regulations.”


	*Federal Regulation of Electricity*

Electric utilities have historically been highly regulated by both the federal government and state public utility commissions. There are two principal pieces of federal legislation that have governed public utilities since the 1930s, the FPA and the PUHCA of 1935. These statutes have been amended and supplemented by subsequent legislation, including the PURPA, the EPAct 1992, and EPAct 2005. Many of the changes made by EPAct 2005 have recently been implemented or are currently in the process of being implemented through new FERC regulations. These particular statutes and regulations are discussed in more detail below.


	Federal Power Act

FERC regulation under the FPA includes approval of the disposition of FERC-jurisdictional utility property, authorization of the issuance of securities by public utilities, regulation of the rates, terms and conditions for the transmission or sale of electric energy at wholesale in interstate commerce, the regulation of interlocking directorates, and the imposition of a uniform system of accounts and reporting requirements for public utilities. Unless otherwise exempt, any person that owns or operates facilities used for the wholesale sale or transmission of electricity is a public utility subject to FERC jurisdiction.

The majority of our generating projects are or will be owned by EWGs. See “Item 1A— Government Regulation — Public Utility Holding Company Act of 1935.” Other than our EWGs located in ERCOT, our affiliates that are EWGs are or will be subject to FERC jurisdiction under the FPA. Many of the generating projects in which we own an interest are or will be operated as QFs under PURPA (see “— Public Utility Regulatory Policies Act of 1978”) and therefore are or will be exempt from many FERC regulations under the FPA. Several of our affiliates have been granted authority to engage in sales at market-based rates and blanket authority to issue securities, and have also been granted certain waivers of FERC regulations available to non-traditional public utilities; however, we cannot assure that such authorities or waivers will not be revoked for these affiliates or will be granted in the future to other affiliates.


	*Market Based Rate Authorization*

Under the FPA and FERC’s regulations, the wholesale sale of power at market-based or cost-based rates requires that the seller have authorization issued by FERC to sell power at wholesale pursuant to a FERC-accepted rate schedule. FERC grants market-based rate authorization based on several criteria, including a showing that the seller and its affiliates lack market power in generation and transmission, that the seller and its affiliates cannot erect other barriers to market entry and that there is no opportunity for abusive transactions involving regulated affiliates of the seller. All of our affiliates that own domestic power plants (except for those power plants that are QFs under PURPA or are located in ERCOT), as well as our power marketing companies (collectively referred to herein as Market Based Rate Companies), are currently authorized by FERC to make wholesale sales of power at market-based rates. This authorization could possibly be revoked for any of our Market Based Rate Companies if they fail in the future to continue to satisfy FERC’s current applicable criteria or future criteria as possibly modified by FERC; if FERC

eliminates or restricts the ability of wholesale sellers of power to make sales at market-based rates; or if FERC institutes a proceeding, based upon its own motion or a complaint brought by a third party, and establishes that any of our Market Based Rate Companies’ existing rates have become either unjust and unreasonable or contrary to the public interest (the applicable standard is determined by the circumstances).

FERC requires sellers making sales pursuant to their market-based rate authority to file electronic quarterly reports of their respective contract and transaction data. Such sellers also must submit triennial updated market power analyses. If a seller does not timely file these quarterly or triennial reports, FERC can revoke the seller’s market-based rate authority.

On November 17, 2003, FERC issued an order conditioning all jurisdictional electric sellers’ market-based rate authority upon the seller’s compliance with specified market behavior rules, with refunds and other possible remedies imposed on violators. The rules address such matters as power withholding, manipulation of market prices, communication of accurate information, and record retention. FERC required each seller with market-based rate authority to amend its rate schedule on file with FERC to include these market behavior rules.

EPAct 2005 contains provisions intended to prohibit the manipulation of the electric energy markets and increase the ability of FERC to enforce and promote entities’ compliance with the statutes, orders, rules, and regulations that FERC administers. To implement the market manipulation provision of EPAct 2005, FERC issued final rules on January 19, 2006, making it unlawful for any entity, in connection with the purchase or sale of electricity, or the purchase or sale of electric transmission service under FERC’s jurisdiction, to (1) use or employ any devise, scheme or artifice to defraud; (2) make any untrue statements of a material fact, or omit to state a material fact needed in order to make a statement not misleading; or (3) engage in any act, practice, or course of business that operates or would operate as a fraud or deceit upon any entity.

On February 16, 2006, FERC issued final rules rescinding two of the market behavior rules because they overlapped with the new anti-manipulation regulations, and codifying the remaining market behavior rules within FERC’s regulations. FERC reasoned that these actions simplify FERC’s rules and regulations, avoid confusion and provide greater clarity and regulatory certainty to the industry.

In February 2005, FERC issued an order requiring every seller with market-based rate authority to include in its market-based rate schedule a requirement to report to FERC any change in the seller’s status that would reflect a departure from the characteristics FERC relied upon in granting market-based rate authority to the particular seller. Such sellers must report these changes within 30 days of the legal or effective date of the change, whichever is earlier.


	*FERC Regulation of Transfers of Jurisdictional Facilities*

Pursuant to Section 203 of the FPA, as amended by EPAct 2005, a public utility must obtain authorization from FERC before the public utility is permitted to: sell, lease or dispose of FERC-jurisdictional facilities with a value in excess of $10 million; merge or consolidate facilities with those of another entity; or acquire any security with a value in excess of $10 million of another public utility. The amended section 203 also extends the scope of FERC’s prior approval jurisdiction to include transactions involving certain transfers of existing generation facilities and certain holding companies’ acquisitions with a value in excess of $10 million; and requires that FERC, when reviewing a proposed section 203 transaction, examine cross-subsidization and pledges or encumbrances of utility assets. These amendments to section 203 took effect on February 8, 2006.

On December 23, 2005, FERC issued a final rule implementing these new section 203 provisions. In its final rule, FERC noted that while EPAct 2005 applies to holding company acquisitions of foreign utilities, it will grant blanket authorizations of such acquisitions if certain conditions are met to protect captive utility customers, which, FERC stated, will allow U.S. companies to successfully compete abroad. The rule also grants blanket authorizations for certain types of transactions, including intra-holding company system financing and cash management arrangements, certain internal corporate reorganizations, and certain acquisitions by holding companies of non-voting securities in a “transmitting utility” and “electric utility

company” and up to 9.9% of voting securities in a “transmitting utility” and “electric utility company” as defined in the FPA and FERC regulations.

On April 24, 2006, FERC issued an order on rehearing of the December 23, 2005 final rule. On rehearing, FERC granted a new blanket authorization for holding companies that are holding companies solely due to their ownership, directly or indirectly, of one or more QFs, EWGs and FUCOs, to acquire the securities of additional QFs, EWGs and FUCOs without FERC pre-approval.


	*FERC Regulation Of Open Access Electric Transmission*

In 1996, FERC issued Order Nos. 888 and 889, introducing competitive reforms and increasing access to the electric power grid. Order No. 888 required the “functional unbundling” of transmission and generation assets by transmission-owning utilities subject to FERC’s jurisdiction. Under Order No. 888, the jurisdictional transmission-owning utilities were required to adopt FERC’s pro forma Open Access Transmission Tariff establishing terms of non-discriminatory transmission service. Many non-jurisdictional transmission owners complied voluntarily through reciprocity provisions. Order No. 889 required transmission-owning utilities to provide the public with an electronic system for buying and selling transmission capacity in transactions with the utilities and abide by specific standards of conduct when using their transmission systems to make wholesale sales of power. In addition, these orders established the operational requirements of Independent System Operators, or ISOs, which are entities that have been given authority to operate the transmission assets of certain jurisdictional and non-jurisdictional utilities in a particular region. The interpretation and application of the requirements of Order Nos. 888 and 889 continue to be refined through subsequent FERC proceedings. These orders have been subject to review, and those parts of the orders that have been the subject of judicial appeals have been affirmed, in large part, by the courts.

On November 16, 2005, FERC initiated a proceeding to consider revisions to the Order No. 888 pro forma Open Access Transmission Tariff to reflect FERC’s and the electric utility industry’s experience with open access transmission over the last decade. In addition to FERC’s Open Access efforts under Order Nos. 888 and 889, our business may be affected by a variety of other FERC policies and proposals, such as the voluntary formation of Regional Transmission Organizations. FERC’s policies and proposals will continue to evolve, and FERC may amend or revise them, or may introduce new policies or proposals in the future. In addition, such policies and proposals, in their final form, would be subject to potential judicial review. The impact of such policies and proposals on our business is uncertain and cannot be predicted at this time.


	Public Utility Holding Company Act of 1935

PUHCA 1935, which, as discussed below, was repealed by EPAct 2005 on February 8, 2006, provided for the extensive regulation of public utility holding companies and their subsidiaries, including registering with the SEC, limiting their utility operations to a single integrated utility system, and divesting any other operations not functionally related to the operation of the utility system. In addition, a public utility company that was a subsidiary of a registered holding company under PUHCA 1935 was subject to financial and organizational regulation, including approval by the SEC of its financing transactions. The EPAct 1992 amended PUHCA 1935 to create EWGs. An EWG is exempt from regulation under PUHCA 1935. To obtain and maintain status as an EWG, a generation facility owner must be exclusively engaged, directly or indirectly, in the business of owning and/or operating eligible electric generating facilities and selling electric energy at wholesale. Under PUHCA 1935, as amended by the EPAct 1992, we were not subject to regulation as a holding company provided that the facilities in which we had an interest were (i) QFs, (ii) owned or operated by an EWG or (iii) subject to another exemption or waiver, such as status as an electric utility geothermal small power production facility.

EPAct 2005 promulgated PUHCA 2005, which repeals PUHCA 1935, effective February 8, 2006. Under PUHCA 2005, certain companies in our ownership structure may be considered “holding companies” as defined in PUHCA 2005 by virtue of their control of the outstanding voting securities of companies that own or operate facilities used for the generation of electric energy for sale or that are themselves holding companies. Under PUHCA 2005, such holding companies are subject to certain FERC rights of access to the

companies’ books and records that are determined by FERC to be relevant to the companies’ respective FERC-jurisdictional rates. However, PUHCA 2005 also provides that FERC shall provide an exemption from this access to books and records for any person that is a holding company solely with respect to its control over EWGs, QFs, and FUCOs.

On December 8, 2005, FERC issued a final rule repealing its PUHCA 1935 regulations and implementing new regulations that focus on increased access to holding company books and records. Although under PUHCA 2005 Calpine is considered a holding company, it is exempt from the new books and records provisions because it is a holding company solely because it owns one or more QFs, EWG and FUCOs. On April 24, 2006, FERC issued an order on rehearing of the December 8, 2005 final rule. In this order, FERC clarified that if exempt holding companies were to lose their exemption from the books and records access requirement, and would not qualify for another type of exemption, that such holding companies would be subject to the books and records access requirement and certain accounting and record-retention requirements. Consequently, if any single Calpine entity were to lose its status as a QF, EWG or FUCO, then Calpine and its holding company subsidiaries would be subject to the books and records access requirement, and, certain Calpine affiliates would be subject to FERC’s accounting, record-retention, and/or reporting requirements.

EPAct 2005 also subjects “holding companies” and “associate companies” within a “holding company system,” other than holding companies that are holding companies solely with respect to ownership of QFs, to certain state commission rights of access to certain of the companies’ books and records if the state commission has jurisdiction to regulate a “public-utility company,” as defined in EPAct 2005, within that holding company system. We cannot predict what effect this part of EPAct 2005 and state regulations implementing it may have on our business. However, section 201(g) of the FPA already provides state commissions with access to books and records of certain electric utility companies subject to the state commission’s regulatory authority, EWGs that sell power to such electric utility companies, and any electric utility company, or holding company thereof, which is an associate company or affiliate of such EWGs.


	Public Utility Regulatory Policies Act of 1978

PURPA, prior to its amendment by EPAct 2005, and the new regulations adopted by FERC, provided certain incentives for electric generators whose projects satisfy FERC’s criteria for QF status. As recognized under FERC’s regulations, most QF generators were exempt from regulation under PUHCA 1935, most provisions of the FPA (including the regulation of the QF’s rates, ability to dispose of otherwise-jurisdictional facilities, and issuance of securities and assumption of liabilities of other parties), and most state laws and regulations relating to financial, organization and rate regulation of electric utilities. FERC’s regulations implementing PURPA required, in relevant part, that electric utilities (i) purchase energy and capacity made available by QFs, construction of which commenced on or after November 9, 1978, at a rate based on the purchasing utility’s full “avoided costs” and (ii) sell supplementary, back-up, maintenance and interruptible power to QFs on a just and reasonable and nondiscriminatory basis. FERC’s regulations defined “avoided costs” as the “incremental costs to an electric utility of electric energy or capacity or both which, but for the purchase from the qualifying facility or qualifying facilities, such utility would generate itself or purchase from another source.” Utilities were permitted to also purchase power from QFs at prices other than avoided cost pursuant to negotiations, as provided by FERC’s regulations.

To be a QF, a cogeneration facility must produce electricity and useful thermal energy for an industrial or commercial process or heating or cooling applications in certain proportions to the facility’s total energy output, and must meet certain efficiency standards. A geothermal small power production facility may qualify as a QF if, in most cases, its generating capability does not exceed 80 MW. Finally, PURPA required that no more than 50% of the equity of a QF could be owned by one or more electric utilities or their affiliates.

EPAct 2005 and FERC’s implementing regulations have eliminated certain benefits of QF status. FERC issued a final rule on February 2, 2006, to eliminate the exemption from sections 205 and 206 of the FPA for a QF’s wholesale sales of power made at market-based rates. Under FERC’s new regulations, our QFs will have to obtain market-based rate authorization for wholesale sales that are made pursuant to a contract executed

after March 17, 2006, and not under a state regulatory authority’s implementation of section 210 of PURPA. In addition, new cogeneration QFs will be required to demonstrate that their thermal, chemical, and mechanical output will be used fundamentally for industrial, commercial, residential, or institutional purposes.

EPAct 2005 also amends PURPA to eliminate, on a prospective basis, electric utilities’ requirement under Section 210 of PURPA to purchase power from QFs at the utility’s “avoided cost,” to the extent FERC determines that such QFs have access to a competitive wholesale electricity market. This amendment to PURPA does not change a utility’s obligation to purchase power at the rates and terms set forth in pre-existing QF power purchase agreements. On December 23, 2005, FERC issued a Notice of Proposed Rulemaking, or NOPR, to implement these new EPAct 2005 provisions. In the NOPR, FERC proposes that electric utilities that are members of the Midwest Independent System Transmission Operator, PJM Interconnection, ISO-New England and the New York Independent System Operator be relieved from the mandatory purchase obligation for new transactions. FERC reasons that the mandatory purchase obligation is no longer needed in these regions because the wholesale electricity markets are competitive due to the regional entities’ administration of auction-based day-ahead and real-time markets, and because bilateral long-term contracts are available to participants and QFs in these markets.

The NOPR also outlines the procedures for utilities outside these regional transmission entities to file to obtain relief from mandatory purchase obligations on a service territory-wide basis, and provides procedures for affected QFs to file to reinstate the purchase obligation. Consistent with the EPAct 2005, FERC proposes to leave intact existing rights under any contract or obligation in effect or pending approval involving QF purchases or sales. Market participants have submitted comments in response to FERC’s NOPR. FERC has not taken any final action. We cannot predict what effect this proposal, and FERC’s final regulations, if any, implementing it, will have on our business.

EPAct 2005’s amendments to PURPA also included certain new QF benefits, such as the elimination of the electric utility ownership limitations on QFs. While PUHCA 1935 has been repealed, FERC has exempted QFs from PUHCA 2005. QFs are still exempt from many provisions of the FPA and most state laws and regulations relating to financial, organization and rate regulation of electric utilities.

We cannot predict what effect other provisions of EPAct 2005 and FERC’s regulations implementing them may have on our business until FERC promulgates final rules implementing all of EPAct 2005’s PURPA provisions and any appeals of such rules are concluded. Nevertheless, we believe that each of the facilities in which we own an interest and which operates as a QF meets the current requirements for QF status. Certain factors necessary to maintain QF status are, however, subject to the risk of events outside our control. For example, some of our facilities have temporarily been rendered incapable of meeting such requirements due to the loss of a thermal energy customer and we have obtained limited waivers (for up to two years) of the applicable QF requirements from FERC. We cannot provide assurance that such waivers will in every case be granted. During any such waiver period, we would seek to replace the thermal energy customer or find another use for the thermal energy which meets PURPA’s requirements, but no assurance can be given that these remedial actions would be available. If one of our QFs were to lose its QF status, the owner of the power plant would need to obtain FERC acceptance of a market-based or cost-based rate schedule to continue making wholesale power sales. To maintain our exemption from PUHCA 2005, the owner would also need to obtain EWG status.


	Additional Provisions of EPAct 2005

EPAct 2005 made a number of other changes to laws affecting the regulation of electricity. These include, but are not limited to, giving FERC explicit authority to proscribe and enforce rules governing market transparency, giving FERC authority to oversee and enforce electric reliability standards, requiring FERC to promulgate rules providing for incentive ratemaking to encourage investments that promote transmission reliability and reduce congestion, giving FERC certain siting authority for transmission lines in critical transmission corridors, requiring FERC to promulgate rules granting incentives, including certain cost recoveries, for transmission owners to join Regional Transmission Organizations, authorizing FERC to require

unregulated utilities to provide open access transmission, and ensuring that load serving entities can retain transmission rights necessary to serve native load requirements.

EPAct 2005 also enhanced FERC’s enforcement authorities by: (i) expanding FERC’s civil penalty authority to cover violations of any provision of Part II of the FPA, as well as any rule or order issued thereunder; (ii) establishing the maximum civil penalty FERC may assess under the NGA or Part II of the FPA as $1,000,000 per violation for each day that the violation continues, and (iii) expanding the scope of the criminal provisions of the FPA by increasing the maximum fines and increasing the maximum imprisonment time. Accordingly, in the future, violations of the FPA and FERC’s regulations could potentially have more serious consequences than in the past.

For those regulations that FERC will promulgate in the future in connection with EPAct 2005, we cannot predict what effect these future regulations may have on our business. Furthermore, we cannot predict what future laws or regulations may be promulgated. We do not know whether any other new legislative or regulatory initiatives will be adopted or, if adopted, what form they may take. We cannot provide assurance that any legislation or regulation ultimately adopted would not adversely affect the operation of and generation of electricity by our business.


	Western Energy Markets

On February 13, 2002, FERC initiated an investigation of potential manipulation of electric and natural gas prices in the western United States. This investigation was initiated as a result of allegations that Enron and others, through their affiliates, used their market position to distort electric and natural gas markets in the West. The scope of the investigation is to consider whether, as a result of any manipulation in the short-term markets for electric energy or natural gas or other undue influence on the wholesale markets by any party since January 1, 2000, the rates of the long-term contracts subsequently entered into in the West are potentially unjust and unreasonable. On August 13, 2002, the FERC staff issued the Initial Report on Company-Specific Separate Proceedings and Generic Reevaluations; Published Natural Gas Price Data; and Enron Trading Strategies (the “Initial Report”), summarizing its initial findings in this investigation. There were no findings or allegations of wrongdoing by Calpine set forth or described in the Initial Report. On March 26, 2003, the FERC staff issued a final report in this investigation (the “Final Report”). In the Final Report, the FERC staff recommended that FERC issue a show cause order to a number of companies, including Calpine, regarding certain power scheduling practices that may have been in violation of the CAISO’s or CalPX’s tariff. The Final Report also recommended that FERC modify the basis for determining potential liability in the California Refund Proceeding discussed above.

On June 25, 2003, FERC issued a number of orders associated with these investigations, including the issuance of two show cause orders to certain industry participants. FERC did not subject Calpine to either of the show cause orders. Also on June 25, 2003, FERC issued an order directing the FERC Office of Markets and Investigations to investigate further whether market participants who bid a price in excess of $250 per megawatt hour into markets operated by either the CAISO or the CalPX during the period of May 1, 2000, to October 2, 2000, may have violated CAISO and CalPX tariff prohibitions. By letter dated May 12, 2004, the Director of FERC’s Office of Market Oversight and Investigation notified Calpine that the investigation of Calpine in this proceeding has been terminated.

Also during the summer of 2003, FERC’s Office of Market Oversight and Investigations began an investigation of generators in California to determine whether California generators improperly physically withhold power from the California markets between May 1, 2000 and June 30, 2001. On June 30, 2004, Calpine was notified by FERC that its investigation of Calpine in this matter has been terminated.

There are also a number of proceedings pending at FERC that were initiated by buyers of wholesale electricity seeking refunds for purchases made during the Western energy crisis, or seeking the reduction of price terms in contracts entered into at this time. We have been a party to some of these proceedings, including a proceeding to determine the level of refunds owed by California power suppliers for the period October 2, 2000, to June 19, 2001. A final FERC order directing refunds in this proceeding is still pending. Furthermore, many proceedings that have been concluded by FERC have been appealed to the Federal

Courts of Appeal. It is uncertain at this time when these proceedings and investigations will conclude or what will be the final resolution thereof. See Item 1A. “Risk Factors — California Power Market” and “California Power Market” in Note 33 of the Notes to Consolidated Financial Statements.

As part of certain proceedings, and as a result of its own investigations, FERC has made significant policy changes and rules regarding market conduct and price transparency. In California and the Western United States (among other regions), FERC’s policy changes include the implementation of price caps on the day ahead or real-time prices for electricity and a continuing obligation of electricity generators to offer uncommitted generation capacity to the CAISO.


	FERC Regulation of Natural Gas Transportation

Under the Natural Gas Act, the Natural Gas Policy Act and the Outer Continental Shelf Lands Act, FERC is authorized to regulate pipeline, storage, and liquefied natural gas facility construction; the transportation of natural gas in interstate commerce; the issuance of certificates of public convenience and necessity to companies providing energy services or constructing and operating interstate pipelines and storage facilities; the abandonment of facilities; the rates for services; and the construction and operation of pipeline facilities at U.S. points of entry for the import or export of natural gas.


	*FERC Regulation Over Natural Gas Transportation*

Pursuant to the Natural Gas Act of 1938, FERC has jurisdiction over the transportation and storage of natural gas in interstate commerce. With respect to most transactions that do not involve the construction of pipeline facilities, regulatory authorization can be obtained on a self-implementing basis. However, interstate pipeline rates, terms and conditions for such services are subject to continuing FERC oversight.

The cost of natural gas is ordinarily the largest operational expense of a gas-fired project and is critical to the project’s economics. The risks associated with using natural gas can include the need to arrange gathering, processing, extraction, blending, and storage, as well as transportation of the gas from great distances, including obtaining removal, export and import authority if the gas is imported from a foreign country; the possibility of interruption of the gas supply or transportation (depending on the quality of the gas reserves purchased or dedicated to the project, the financial and operating strength of the gas supplier, whether firm or non-firm transportation is purchased and the operations of the gas pipeline); regulatory diversion; and obligations to take a minimum quantity of gas and pay for it (i.e., take-and-pay obligations). As the owner of more than 70 natural gas-fired power plants, we rely on the natural gas pipeline grid for delivery of fuel. The use of pipelines for delivery of natural gas has proven to be an efficient and reliable method of meeting customer’s fuel needs. The risk of fuel supply disruption resulting from pipeline operation difficulties is limited given the historic performance of pipeline operators and in certain instances multiple pipeline interconnections to the generating facilities. See Item 1A. “Risk Factors — California Power Market” and Note 33 of the Notes to Consolidated Financial Statements.

Calpine has two natural gas transportation pipelines in Texas that are authorized by FERC to provide gas transportation service pursuant to Section 311 of the NGPA. These pipelines are also subject to regulation as gas utilities by the Railroad Commission of Texas for rates and services.


	*FERC Regulation of Sales of Natural Gas at Negotiated Rates*

In orders issued in 1992 and 1993, FERC, relying on findings by Congress in EPAct 1992 that a competitive market exists for natural gas, concluded that sellers of short-term or long-term natural gas supplies would not have market power over the sale for resale of natural gas. FERC established light-handed regulation over sales for resale of natural gas and issued blanket certificates to allow entities selling natural gas to make interstate sales for resale at negotiated rates.

On November 17, 2003, as a result of the western energy crisis, FERC amended the blanket marketing certificates held by entities making interstate sales for resale of natural gas at negotiated rates to require that all sellers adhere to a code of conduct with respect to natural gas sales. The code of conduct addresses such

matters as natural gas withholding, manipulation of market prices, communication of accurate information, and record retention.

EPAct 2005 contains provisions intended to prohibit the manipulation of the natural gas markets and to increase the ability of FERC to enforce and promote compliance with the statutes, orders, rules, and regulations that FERC administers. To implement the market manipulation provision of EPAct 2005, FERC issued a final rule on January 19, 2006, implementing new regulations that make it unlawful for any entity, in connection with the purchase or sale of natural gas, or the purchase or sale of transportation service under FERC’s jurisdiction, to (1) use or employ any devise, scheme or artifice to defraud; (2) make any untrue statements of a material fact, or omit to state a material fact needed in order to make a statement not misleading; or (3) engage in any act, practice, or course of business that operates or would operate as a fraud or deceit upon any entity.

EPAct 2005 also enhanced FERC’s enforcement authorities in natural gas markets by: (i) expanding FERC’s civil penalty authority to cover violations of any provision of the NGA, or any rule, regulation, restriction, condition, or order made or imposed by FERC under NGA authority; (ii) establishing the maximum civil penalty FERC may assess under the NGA as $1,000,000 per violation for each day that the violation continues, and (iii) expanding the scope of the criminal provisions of the NGA by increasing the maximum fines and increasing the maximum imprisonment time. Accordingly, in the future, violations of the NGA and FERC’s regulations could potentially have more serious consequences than in the past.

On February 16, 2006, FERC issued final rules rescinding certain provisions of its code of conduct regulations that relate to market behavior rules because they overlapped with the new anti-manipulation regulations. FERC retained other code of conduct regulations regarding price index reporting and record retention. FERC reasoned that these actions will avoid regulatory uncertainty and confusion and will assure that the same standard applies to all market participants.


	*State Energy Regulation*

State PUCs have historically had broad authority to regulate both the rates charged by, and the financial activities of, electric utilities operating in their states and to promulgate regulation for implementation of PURPA. Since a power sales agreement becomes a part of a utility’s cost structure (generally reflected in its retail rates), power sales agreements with independent electricity producers, such as EWGs, are potentially under the regulatory purview of PUCs and in particular the process by which the utility has entered into the power sales agreements. If a PUC has approved the process by which a utility secures its power supply, a PUC is generally inclined to authorize the purchasing utility to pass through to the utility’s retail customers the expenses associated with a power purchase agreement with an independent power producer. However, a regulatory commission under certain circumstances may not allow the utility to recover through retail rates its full costs to purchase power from a QF or an EWG. In addition, retail sales of electricity or thermal energy by an IPP may be subject to PUC regulation depending on state law. IPPs which are not QFs under PURPA, or EWGs pursuant to the EPAct 1992, are considered to be public utilities in many states and are subject to broad regulation by a PUC, ranging from requirement of certificate of public convenience and necessity to regulation of organizational, accounting, financial and other corporate matters. Because all of our affiliates are either QFs or EWGs, none of our affiliates are currently subject to such regulation. However, states may also assert jurisdiction over the siting and construction of electricity generating facilities including QFs and EWGs and, with the exception of QFs, over the issuance of securities and the sale or other transfer of assets by these facilities. In California, for example, the PUC was required by statute to adopt and enforce maintenance and operation standards for generating facilities “located in the state,” including EWGs but excluding QFs, for the purpose of ensuring their reliable operation.

State PUCs also have jurisdiction over the transportation of natural gas by LDCs. Each state’s regulatory laws are somewhat different; however, all generally require the LDC to obtain approval from the PUC for the construction of facilities and transportation services if the LDC’s generally applicable tariffs do not cover the proposed transaction. LDC rates are usually subject to continuing PUC oversight. In addition, PUC regulations can establish the priority of curtailment of gas deliveries when gas supply is scarce. We own and

operate certain midstream assets in certain states where we have plants. With the expected influx on liquefied natural gas into California from Mexico, the CPUC is reviewing the adequacy of the gas quality specifications contained in the California LDC tariffs. LNG deliveries into the LDC pipeline system could impact plant operations and the ability to meet emission limits unless appropriate gas specifications are implemented.


	*Environmental Regulations*

The exploration for and development of geothermal resources, and the construction and operation of wells, fields, pipelines, various other mid-stream facilities and equipment, and power projects, are subject to extensive federal, state and local laws and regulations adopted for the protection of the environment and to regulate land use. The laws and regulations applicable to us primarily involve the discharge of emissions into the water and air and the use of water, but can also include wetlands preservation, endangered species, hazardous materials handling and disposal, waste disposal and noise regulations. These laws and regulations in many cases require a lengthy and complex process of obtaining licenses, permits and approvals from federal, state and local agencies.

Noncompliance with environmental laws and regulations can result in the imposition of civil or criminal fines or penalties. In some instances, environmental laws also may impose clean-up or other remedial obligations in the event of a release of pollutants or contaminants into the environment. The following federal laws are among the more significant environmental laws as they apply to us. In most cases, analogous state laws also exist that may impose similar, and in some cases more stringent, requirements on us as those discussed below.


	Clean Air Act

The Clean Air Act provides for the regulation, largely through state implementation of federal requirements, of emissions of air pollutants from certain facilities and operations. As originally enacted, the Clean Air Act sets guidelines for emissions standards for major pollutants (i.e., sulfur dioxide and nitrogen oxide) from newly built sources. In late 1990, Congress passed the Clean Air Act Amendments. Those amendments attempt to reduce emissions from existing sources, particularly previously exempted older power plants. We believe that all of our operating plants and relevant oil and gas related facilities are in compliance with federal performance standards mandated under the Clean Air Act and the Clean Air Act Amendments.

In 2005, the EPA issued a new regulation under the Clean Air Act called the Clean Air Interstate Rule which directs 28 states in the southern, eastern and mid-western regions of the country to enact further restrictions on air emissions. How each state determines to implement the Clean Air Interstate Rule will have an impact on Calpine’s fleet of power plants. Recently, there have also been numerous federal legislative proposals to further reduce emissions of sulfur dioxide, nitrogen oxide and mercury, as well as to regulate emissions of carbon dioxide for the first time. Because Calpine’s fleet of efficient low-emitting gas-fired and geothermal power plants have a much lower emissions rate than the average U.S. fossil fuel fleet, it is possible that the company will be less impacted by such regulation than owners of older, higher emitting fleets. However, this will be determined by the details of implementation such as allocation of emissions allowances and point of regulation.


	Clean Water Act

The Federal Clean Water Act establishes rules regulating the discharge of pollutants into waters of the United States. We are required to obtain wastewater and storm water discharge permits for wastewater and runoff, respectively, from certain of our facilities. We believe that, with respect to our geothermal and oil and gas operations, we are exempt from newly promulgated federal storm water requirements. We are required to maintain a spill prevention control and countermeasure plan with respect to certain of our oil and gas facilities. We believe that we are in material compliance with applicable discharge requirements of the Federal Clean Water Act.


	Safe Drinking Water Act

Part C of the Safe Drinking Water Act mandates the underground injection control program. The program regulates the disposal of wastes by means of deep well injection, which is used for oil, gas, and geothermal production activities. Deep well injection is a common method of disposing of saltwater, produced water and other oil and gas wastes. With the passage of EPAct 2005, oil, gas and geothermal production activities are exempt from the underground injection control program under the Safe Drinking Water Act.


	Resource Conservation and Recovery Act

The Resource Conservation and Recovery Act regulates the generation, treatment, storage, handling, transportation and disposal of solid and hazardous waste. With respect to our solid waste disposal practices at the power generation facilities and steam fields located at The Geysers, we are subject to certain solid waste requirements under applicable California laws. We believe that our operations are in material compliance with the Resource Conservation and Recovery Act and all such laws.


	Comprehensive Environmental Response, Compensation and Liability Act

CERCLA, also referred to as Superfund, requires cleanup of sites from which there has been a release or threatened release of hazardous substances and authorizes the EPA to take any necessary response action at Superfund sites, including ordering potentially responsible parties liable for the release to pay for such actions. Potentially responsible parties are broadly defined under CERCLA to include past and present owners and operators of, as well as generators of wastes sent to, a site. As of the present time, we are not subject to any material liability for any Superfund matters. However, we generate certain wastes, including hazardous wastes, and send certain of our wastes to third party waste disposal sites. As a result, there can be no assurance that we will not incur liability under CERCLA in the future.


	*Canadian Environmental, Health and Safety Regulations*

Our Canadian power projects are also subject to extensive federal, provincial and local laws and regulations adopted for the protection of the environment and to regulate land use. We believe that we are in material compliance with all applicable requirements under Canadian law.


	*Regulation of Canadian Gas*

The Canadian natural gas industry is subject to extensive regulation by federal and provincial authorities. At the federal level, a party exporting gas from Canada must obtain an export license from the National Energy Board. The National Energy Board also regulates Canadian pipeline transportation rates and the construction of pipeline facilities. Gas producers also must obtain a removal permit or license from each provincial authority before natural gas may be removed from the province, and provincial authorities regulate intra-provincial pipeline and gathering systems. In addition, a party importing natural gas into the United States or exporting natural gas from the United States first must obtain an import or export authorization from the U.S. Department of Energy.

EMPLOYEES

As of December 31, 2005, we employed 3,265 full-time people, of whom 63 were represented by collective bargaining agreements. Since December 31, 2005, we have begun to implement staff reductions of approximately 1,100 positions, or over one-third of our pre-petition date workforce, by the end of 2006. We have never experienced a work stoppage or strike.

SUMMARY OF KEY ACTIVITIES


	*Summary of Key Activities*


	Finance — New Issuances and Amendments:


Date	Amount		Description

1/28/05	$	100.0 million	Complete a non-recourse construction credit facility for Metcalf (repaid on June 20, 2005, in connection with the Metcalf preferred share and senior term loan financing described below)
1/31/05	$	260.0 million	Calpine Jersey II completes issuance of redeemable preferred shares due July 30, 2005 (repurchased on July 28, 2005, in connection with the sale of the Saltend facility described below)
3/1/05	$	503.0 million	Close a non-recourse project finance facility that provides $466.5 million to complete construction of Mankato and Freeport as well as a $36.5 million collateral letter of credit facility
6/20/05	$	255.0 million	Metcalf closes on a $155.0 million 5.5-year redeemable preferred shares offering and a five-year $100.0 million senior term loan; (repaid $100 million non-recourse credit facility completed on January 28, 2005, described above)
6/23/05	$	650.0 million	Receive funding on offering of 2015 Convertible Notes
6/30/05	$	123.1 million	Close non-recourse project finance facility for Bethpage Energy Center 3
8/12/05	$	150.0 million	CCFCP completes a $150.0 million private placement of Class A Redeemable Preferred Shares due 2006 (repurchased in full on October 14, 2005)
10/14/05	$	300.0 million	CCFCP issues $300.0 million of 6-Year Redeemable Preferred Shares due 2011
12/22/05	$	2.0 billion	Receive approval of first day motions from the U.S. Bankruptcy Court, including permission to continue to perform under power trading contracts, authorization to continue paying employee wages, salaries and benefits as well as interim approval to immediately use $500 million of its $2 billion DIP Facility, arranged by Deutsche Bank Securities Inc. and Credit Suisse


	Finance — Repurchases and Extinguishments:


Date	Amount		Description

7/13/05	$	517.5 million	Repay the convertible debentures payable to Trust III, the issuer of the HIGH TIDES III preferred securities, the proceeds of which are applied by Trust III to redeem the HIGH TIDES III preferred securities in full
10/14/05	$	150.0 million	Repurchase $150.0 million in CCFCP Class A Redeemable Preferred Shares due 2006
6/28/05	$	94.3 million	Issue approximately 27.5 million shares of Calpine common stock in exchange for $94.3 million in aggregate principal amount at maturity of 2014 Convertible Notes pursuant to Section 3(a)(9) under the Securities Act
1/1/05 — 12/31/05	$	917.1 million	Repurchase Senior Notes in open market transactions totaling $917.1 million in principal for cash of $685.5 million plus accrued interest


	Finance — Other:


Date		Description

3/31/05		Deer Park Energy Center Limited Partnership enters into agreements with Merrill Lynch Commodities, Inc. to sell power and buy gas from April 1, 2005, to December 31, 2010, for a cash payment of $195.8 million, net of transaction costs, plus additional cash payments as additional transactions are executed


	Asset Sales:


Date		Description

7/7/05		Complete the sale of substantially all of our remaining oil and gas assets for $1.05 billion, less approximately $60 million of estimated transaction fees and expenses
7/8/05		Complete the sale of our 50% interest in the 175-MW Grays Ferry Power Plant for gross proceeds of $37.4 million
7/28/05		Complete the sale of the 1,200-MW Saltend Energy Centre for approximately $862.9 million
7/29/05		Complete the sale of Inland Empire Energy Center development project to GE for approximately $30.9 million
8/2/05		Complete the sale of the 156-MW Morris Energy Center for $84.5 million
10/6/05		Complete the sale of the 561-MW Ontelaunee Energy Center for $212.3 million


	Other:


Date		Description

2/22/05		Announce the selection of Inland Energy Center as site for North American launch of General Electric’s most advanced gas turbine technology, the “H System^tm”
2/23/05		NewSouth Energy, a newly formed subsidiary, launches an energy venture to better focus on wholesale power customers and energy markets in the South
3/28/05		Announce the receipt of a contract to provide 75 MW of Transmission Must Run Services to Alberta Electric System Operator with contract terms of March 17, 2005 to June 30, 2006, with options to extend until June 2008
4/12/05		Enter into a 20-year Clean Energy Supply Contract with the OPA to make clean energy available from Calpine’s new 1,005-MW Greenfield Energy Centre, a partnership between Calpine and Mitsui, once commercial operation is achieved
6/1/05		Expand and extend power contract with Safeway, Inc. for up to 141 MW during on peak and 122 MW during off peak through mid-2008
6/2/05		Carville Energy Center, LLC, CES, and Entergy enter into a one-year agreement to supply up to 485 MW of capacity and energy to Entergy
7/5/05		Sign an agreement with Siemens-Westinghouse to restructure the long-term relationship, which is expected to provide additional flexibility to self-perform maintenance work in the future
7/7/05		Announce a 15-year Master Products and Services Agreement with GE to supplement operations with a variety of services and to lower operating costs
7/11/05		Major merchant power generator selects PSM to install LEC-III^® and eliminate 90% of the power plant’s nitrogen oxide emissions
8/26/05		CES announces new service agreements with Project Orange Associates LLC and the Greater Toronto Airports Authority to provide them with marketing, scheduling, and other energy managements services
8/29/05		CES announces five year long-term power supply agreement for 170 MW of electricity with Tampa Electric Company
9/7/05		Agree to form an energy marketing and trading venture with Bear Stearns to develop a third-party customer business focused on physical natural gas and power trading and related structured transactions
9/14/05		Jeffrey E. Garten resigns from the Company’s Board of Directors
9/19/05		William J. Keese and Walter L. Revell elected as independent directors
11/4/05		John O. Wilson retires from the Company’s Board of Directors
11/10/05		Announce resignation of Susan C. Schwab from the Company’s Board of Directors due to her confirmation by the U.S. Senate as a Deputy U.S. Trade Representative


Date		Description

11/29/05		Announce change in executive management with the departures of Peter Cartwright, Chairman, President and Chief Executive Officer, and Robert D. Kelly, Executive Vice President and Chief Financial Officer
11/29/05		Announce appointments of Kenneth T. Derr as Chairman of the Board and Acting Chief Executive Officer of Calpine and Eric N. Pryor as Interim Chief Financial Officer
12/5/05		Gerald Greenwald resigns from the Company’s Board of Directors
12/6/05		NYSE suspends trading of Calpine common stock prior to the opening of the market
12/12/05		Robert P. May appointed as new Chief Executive Officer and member of the Company’s Board of Directors
12/20/05		Peter Cartwright resigns from the Board of Directors
12/20/05		The Company and certain of its United States subsidiaries file voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court, and certain of the Company’s Canadian subsidiaries file petitions for relief under the CCAA in Canada; in conjunction with the U.S. filings the Company receives commitments for up to $2 billion of secured DIP Financing


	Power Plant Development and Construction:


Date	Project	Description

5/4/05	Pastoria Energy Center		Commercial Operation
5/27/05	Metcalf Energy Center		Commercial Operation
6/1/05	Fox Energy Center (Phase 1)		Commercial Operation
7/1/05	Bethpage Energy Center 3		Commercial Operation
7/5/05	Pastoria Energy Center (Phase II)		Commercial Operation

See Item 1. “Business — Recent Developments” for 2006 developments.

NYSE CERTIFICATION

The annual certification of our former Chief Executive Officer, Peter Cartwright, required to be furnished to the NYSE pursuant to Section 303A.12(a) of the NYSE Listed Company Manual was previously filed with the NYSE in May 2005. The certification confirmed that he was unaware of any violation by the Company of NYSE’s corporate governance listing standards. Trading in our common stock on the NYSE was suspended effective December 6, 2005, and the SEC approved the application of the NYSE to delist our common stock effective March 15, 2006. Consequently, we are no longer required to provide this annual certification to the NYSE.


Item 1A.	*Risk Factors*


	*Risks Relating to Bankruptcy*

We are subject to the risks and uncertainties associated with bankruptcy cases as a result of our filing for reorganization. On December 20, 2005, we and many of our U.S. subsidiaries filed voluntary petitions to reorganize under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court, and many of our Canadian subsidiaries similarly filed petitions for relief under the CCAA in the Canadian Court. The U.S. bankruptcy cases have been consolidated and are being jointly administered by the U.S. Bankruptcy Court. The Canadian cases are being jointly administered by the Canadian Court. Since the original filings, additional subsidiaries have also filed voluntary petitions in the United States and have been joined in the original proceedings. We continue to operate our business as debtors-in-possession under the jurisdiction of the Bankruptcy Courts and in accordance with the applicable provisions of the Bankruptcy Code, the CCAA

and orders of the Bankruptcy Courts. For the duration of the bankruptcy cases, our operations will be subject to the risks and uncertainties associated with bankruptcy which include, among other things:


	•	the actions and decisions of our creditors and other third parties with interests in our bankruptcy cases, including official and unofficial committees of creditors and equity holders, which may be inconsistent with our plans;

	•	objections to or limitations on our ability to obtain Bankruptcy Court approval with respect to motions in the bankruptcy cases that we may seek from time to time or potentially adverse decisions by the Bankruptcy Courts with respect to such motions;

	•	objections to or limitations on our ability to avoid or reject contracts or leases that are burdensome or uneconomical;

	•	the expiration of the exclusivity period for us to propose and confirm a plan of reorganization or delays, limitations or other impediments to our ability to develop, propose, confirm and consummate a plan of reorganization;

	•	the ability of third parties to seek and obtain court approval to terminate or shorten the exclusivity period for us to propose and confirm a plan of reorganization;

	•	our ability to obtain and maintain normal terms with customers, vendors and service providers; and

	•	our ability to maintain contracts and leases that are critical to our operations.

These risks and uncertainties could negatively affect our business and operations in various ways. For example, negative events or publicity associated with our bankruptcy filings and events during the bankruptcy cases could adversely affect our relationships with customers, vendors and employees, which in turn could adversely affect our operations and financial condition, particularly if the bankruptcy cases are protracted. Also, transactions by Calpine Debtors that are outside the ordinary course of business will generally be subject to the prior approval of the applicable Bankruptcy Court, which may limit our ability to respond on a timely basis to certain events or take advantage of certain opportunities. In addition, although we have received approval from the U.S. Bankruptcy Court to an extension of the exclusivity period to propose a plan of reorganization, until December 31, 2006, and to seek acceptances thereon until March 31, 2007, if we are unable to propose and confirm a plan of reorganization within that time and are unable to obtain a further extension (or if the period is otherwise shortened or terminated), third parties could propose and seek confirmation of their own plan or plans of reorganization. Any such third party plan or plans could disrupt our business, adversely affect our relationships with customers, vendors and employees, or otherwise adversely affect our operations and financial condition.

Because of the risks and uncertainties associated with our bankruptcy cases, the ultimate impact of events that occur during these cases will have on our business, financial condition and results of operations cannot be accurately predicted or quantified at this time.

The bankruptcy cases may adversely affect our operations going forward. As noted above, our having sought bankruptcy protection may adversely affect our ability to negotiate favorable terms from suppliers, landlords, contract or trading counterparties and others and to attract and retain customers and counterparties. The failure to obtain such favorable terms and to attract and retain customers, as well as other contract or trading counterparties could adversely affect our financial performance. For example, as a result of our bankruptcy filing, certain of our former trading counterparties informed us that they are prohibited by their internal credit policies from continuing to execute trades with us. In addition, certain of our subsidiaries, including CES, have also filed for bankruptcy protection and we may deem it necessary to seek bankruptcy protection for additional subsidiaries as part of our overall restructuring effort. The existence of the bankruptcy cases may adversely affect the way such subsidiaries are perceived by investors, financial markets, trading counterparties, customers, suppliers and regulatory authorities, which could adversely affect our consolidated operations and financial performance.

We will be subject to claims made after the date that we filed for bankruptcy and other claims that are not discharged in the bankruptcy cases, which could have a material adverse effect on our results of operations and financial condition. We are currently subject to claims in various legal proceedings, and may become subject to other legal proceedings in the future. Although we will seek to satisfy and discharge all claims made against us prior to the date of the bankruptcy filings (which claims are generally stayed while the bankruptcy proceeding is pending), we may not be successful in doing so. In addition, claims made against our Non-Debtor subsidiaries are not stayed and will not be discharged in the bankruptcy proceeding; and any claims arising after the date of our bankruptcy filing may also not be subject to discharge in the bankruptcy proceeding. See Note 31 of the Notes to Consolidated Financial Statements for a description of the more significant legal proceedings in which we are presently involved. The ultimate outcome of each of these matters, including our ability to have these matters satisfied and discharged in the bankruptcy proceeding, cannot presently be determined, nor can the liability that may potentially result from a negative outcome be reasonably estimated presently for every case. The liability we may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued with respect to such matters and, as a result, these matters may potentially be material to our business or to our financial condition and results of operations.

The August 1, 2006 and June 30, 2006, bar dates by which claims must be filed against the U.S. Debtors and the Canadian Debtors, respectively, have not yet passed. Accordingly, it is not possible at this time to determine the extent of the claims that may be filed, whether or not such claims will be disputed, or whether or not such claims will be subject to discharge in the bankruptcy proceedings. Nor is it possible at this time to determine whether to establish any claims reserves. Once applicable bar dates have passed, we will review all claims filed and begin the claims reconciliation process. In connection with the review and reconciliation process, we will also determine the reserves, if any, that may be established in respect of such claims. To the extent that we are unable to resolve any claims filed, or our assets (including any applicable reserves) are inadequate to pay resolved claims, it could have an adverse impact on our financial condition or our ability to reorganize. In addition, it is likely that certain creditors may assert claims on multiple bases against multiple Calpine Debtor entities, resulting in a total overall claims pool significantly in excess of the amount of the Calpine Debtors’ potential liabilities. For example, there may be multiple claims by one creditor against multiple Calpine Debtors (as debtor and guarantor, joint tortfeasers, etc.), resulting in asserted bankruptcy claims significantly in excess of the amount of the actual underlying liabilities. Alternatively, there may be multiple bankruptcy claims by multiple creditors against a single Calpine Debtor based on different theories of liability, which would also result in asserted bankruptcy claims significantly in excess of the amount of underlying actual liabilities. Therefore, we expect that the amount of bankruptcy claims filed in our bankruptcy cases will be significantly greater than our total consolidated funded debt of approximately $17.4 billion (including deconsolidated Canadian debt) as of December 31, 2005. However, despite the likelihood that there will be bankruptcy claims asserted against the collective Calpine Debtors in excess of their potential liabilities, no individual creditor should receive more than 100% recovery on account of such multiple claims.

Our bankruptcy filings have exposed certain of our Non-Debtor subsidiaries to the potential exercise of rights and remedies by debt or equity holders. Our bankruptcy filings and constraints on our business during the bankruptcy cases have resulted in (and could result in additional) defaults under certain project loan agreements of Non-Debtor subsidiaries. These bankruptcy filings and limitations on the ability of certain of the Calpine Debtor subsidiaries to make payments under intercompany agreements with Non-Debtor subsidiaries has resulted in defaults or potential defaults under debt or preferred equity interests issued by or certain lease obligations of certain of those Non-Debtor subsidiaries, including CCFC, CCFCP and Metcalf. Absent cure, waiver or other resolution in respect of these defaults from the applicable creditors or equity holders, we may not be able to prevent the acceleration of the subsidiary debt or lease obligations and the exercise of other remedies against the subsidiaries, including a sale of the equity or assets of such subsidiaries, a termination of the leasehold rights or the enforcement of buy-out rights or other remedies. As of the date of this Report, although we have been able to obtain waivers with respect to certain defaults, we have not been able to obtain waivers or forbearances from or enter into other arrangements with certain project lenders, lessors and shareholders with respect to other defaults, and there is no assurance that we will be able to do so in the future. If we are unable to obtain waivers or make other arrangements with respect to current or future

defaults, if any, under debt, preferred equity or leases of Non-Debtor subsidiaries, such Non-Debtor subsidiaries may be adversely affected, or the holders of debt or equity of such Non-Debtor subsidiaries may take actions or exercise remedies, including sales of the assets of such Non-Debtor subsidiaries, which may cause adverse effects to our financial condition or results of operations as a whole.

Transfers of our equity, or issuances of equity in connection with our restructuring, may impair our ability to utilize our federal income tax net operating loss carryforwards in the future. Under federal income tax law, a corporation is generally permitted to deduct from taxable income in any year net operating losses carried forward from prior years. We have NOL carryforwards of approximately $2.9 billion as of December 31, 2005. Our ability to deduct NOL carryforwards could be subject to a significant limitation if we were to undergo an “ownership change” for purposes of Section 382 of the Internal Revenue Code of 1986, as amended, during or as a result of our Chapter 11 cases. During the pendency of the bankruptcy proceeding, the U.S. Bankruptcy Court has entered an order that places certain limitations on trading in our common stock or certain securities, including options, convertible into our common stock. However, we can provide no assurances that these limitations will prevent an “ownership change” or that our ability to utilize our net loss carryforwards may not be significantly limited as a result of our reorganization. On April 17, 2006, we announced that, primarily due to the inability under generally accepted accounting principles to assume future profits and due to our reduced ability to implement tax planning strategies to utilize our NOLs while in bankruptcy, we had concluded that valuation allowances on a portion of our deferred tax assets were required. The additional valuation allowances related to these assets recorded in the financial statements included in this Report for the year ended December 31, 2005, total approximately $1.6 billion. In addition, we expect that a portion of the losses that we expect to incur in 2006 will not generate tax benefits and, therefore, additional valuation allowances may be required.

Canadian Debtors and their creditors may advance claims against the U.S. Debtors. In accordance with procedures under the CCAA, Ernst & Young Inc. was appointed as monitor and has provided reports to the Canadian Court from time to time on various matters including the Canadian Debtors’ cash flow, asset transfers and other developments in the Canadian cases. (The monitor’s reports have been made generally available on the monitor’s website at www.ey.com/ca/calpinecanada; however, we are not responsible for the monitor’s reports or the other contents of that website, none of which is a part of this Report.) On March 30, 2006, the monitor issued a report containing its preliminary overview of the assets, liabilities and equity of the Canadian Debtors. The report indicates, among other things, that the claims of creditors of the Canadian Debtors, which includes approximately $3 billion of Senior Notes issued by ULC I and ULC II and guaranteed by Calpine Corporation, exceeds the value of the remaining assets of the Canadian Debtors on a stand-alone basis. The most significant assets of the Canadian Debtors, including Saltend and the Canadian oil and gas assets, were sold in 2004 and 2005. The Canadian Debtors intend to file a plan or plans of compromise and arrangement under the CCAA with a view to maximizing realizations to their creditors and resolving inter-creditor disputes without protracted litigation. It is possible that the creditors of the Canadian Debtors will apply to the Canadian Court to lift the stay of proceedings to have some or all of the Canadian Debtors petitioned into bankruptcy in Canada (a proceeding that is generally the equivalent of a liquidation proceeding under Chapter 7 of the Bankruptcy Code in the United States). In either case, the proceeds of realization will be used to make payments to the creditors of the Canadian Debtors. It is expected that the proceeds of such sales would not be sufficient to fully satisfy the claims of such creditors. At least some of the creditors of the Canadian Debtors may assert claims in the U.S. bankruptcy cases for any unpaid portion of their claims.

Claims based upon guarantees provided by us of obligations of ULC I and ULC II, or claims of other creditors of the Canadian Debtors who had received a guarantee from or otherwise had recourse to a U.S. Debtor, could be made against the U.S. Debtors in the U.S. Bankruptcy Court. Such claims, which would be unsecured, would likely be in excess of $2 billion.

In addition, certain Canadian Debtors have claims on account of inter-company indebtedness, which may be advanced against certain U.S. Debtors in the U.S. bankruptcy cases. Such claims, which would be unsecured, would likely be in excess of $2 billion.

Our successful reorganization will depend on our ability to motivate key employees and successfully implement new strategies. Our success is largely dependent on the skills, experience and efforts of our people. In particular, the successful implementation of our business plan and our ability to successfully consummate a plan of reorganization will be highly dependent upon our new Chief Executive Officer and our new Chief Financial Officer and Chief Restructuring Officer, as well as other members of our senior management. Our ability to attract, motivate and retain key employees is restricted by provisions of the Bankruptcy Code, which limit or prevent our ability to implement a retention program or take other measures intended to motivate key employees to remain with the Company during the pendency of the bankruptcy cases. In addition, we must obtain U.S. Bankruptcy Court approval of employment contracts and other employee compensation programs. The process of obtaining such approvals, including negotiating with certain official and unofficial creditor committees (which may raise objections to or otherwise limit our ability to implement such contracts or programs), has resulted in delays and reduced potential compensation for many employees. Certain employees, including certain members of our executive management, have resigned following our bankruptcy filings. The loss of the services of such individuals or other key personnel could have a material adverse effect upon the implementation of our business plan, including our restructuring program, and on our ability to successfully reorganize and emerge from bankruptcy.

We have recognized impairment and other charges of $7.1 billion for the period ending December 31, 2005 to certain of our projects and other assets and could recognize additional impairment charges in the future. As a result of the convergence of multiple facts and circumstances arising during the fourth quarter of 2005, we determined that certain of our projects and other assets had been impaired. These facts and circumstances include, among other things, restrictions on our ability to commit to expending additional capital on such projects due to Bankruptcy Court orders, required approvals of our official and unofficial creditors’ committees and the provisions of the DIP Facility, as well as our focus on reorganizing and emerging from bankruptcy and our inability to secure long term PPAs for such facilities in part due to credit support requirements imposed by potential counterparties both prior to and after our bankruptcy filings. As a result, in 2005 we recorded impairment charges totaling approximately (i) $2.4 billion with respect to certain of our operating projects, (ii) $2.1 billion with respect to certain of our development and construction assets, and other investments, (iii) $0.9 billion related to our investment in our Canadian subsidiaries, which have been deconsolidated as a result of our Canadian filings, and (iv) $0.1 billion with respect to deferred financing costs related to debt subject to compromise following our bankruptcy filings. In addition, primarily due to the inability under GAAP to assume future profits and due to our reduced ability to implement tax planning strategies to utilize our NOL carryforwards while in bankruptcy, we recorded valuation allowances of approximately $1.6 billion on a portion of our deferred tax assets. It is possible that we may be required to recognize additional impairment charges in the future with respect to our projects and other assets and, because we expect that a portion of our losses expected to be incurred in 2006 will not generate tax benefits, additional valuation allowances may be required.

The prices of our debt and equity securities are volatile and, in connection with our reorganization, holders of our securities may receive no payment, or payment that is less than the face value or purchase price of such securities. Prior to our bankruptcy filing, the market price for our common stock was volatile and, following our bankruptcy filing, the price of our common stock has generally been less than $.30 per share. Prices for our debt securities and preferred equity securities are also volatile and prices for such securities (in particular those issued by Calpine Debtors) have generally been substantially below par following our bankruptcy filing. In addition, following the delisting of our common stock from the NYSE, none of our securities are listed on an exchange, and many series of our securities are not registered with the SEC. Accordingly, trading in the securities of both Calpine Debtors and Non-Debtors may be limited and holders of such securities may not be able to resell their securities for their purchase price or at all. We can make no assurance that the price of our securities will not fluctuate substantially in the future.

It is possible that, in connection with our reorganization, all of the outstanding shares of our common stock could be cancelled, and holders of our common stock may not be entitled to any payment in respect of their shares. In addition, new shares of our common stock may be issued. It is also possible that our obligations to holders of debt or preferred equity securities of Calpine Debtors may be satisfied by payments to such

holders that are less than both the par value of such securities and the price at which holders purchased such securities, or that shares of our common stock may be issued to certain of such holders in satisfaction of their claims. The value of any common stock so issued may be less than the par value or purchase price of such holders’ securities, and the price of any such common shares may be volatile.

Accordingly, trading in our securities during the pendency of our bankruptcy cases is highly speculative and poses substantial risks to purchasers of such securities, as holders may not be able to resell such securities or, in connection with our reorganization, may receive no payment, or a payment or other consideration that is less than the par value or the purchase price of such securities.

Bankruptcy laws may limit our secured creditors’ ability to realize value from their collateral. Upon the commencement of a case for relief under Chapter 11 of the Bankruptcy Code, a secured creditor is prohibited from repossessing its security from a debtor in a bankruptcy case, or from disposing of security repossessed from such debtor, without bankruptcy court approval. Moreover, the Bankruptcy Code generally permits the debtor to continue to retain and use collateral even though the debtor is in default under the applicable debt instruments, provided that the secured creditor is given “adequate protection.” The meaning of the term “adequate protection” may vary according to circumstances, but it is intended in general to protect the value of the secured creditor’s interest in the collateral and may include cash payments or the granting of additional security if and at such times as the bankruptcy court in its discretion determines that the value of the secured creditor’s interest in the collateral is declining during the pendency of the bankruptcy case. A bankruptcy court may determine that a secured creditor may not require compensation for a diminution in the value of its collateral if the value of the collateral exceeds the debt it secures.

In view of the lack of a precise definition of the term “adequate protection” and the broad discretionary power of a bankruptcy court, it is impossible to predict:


	•	how long payments under our secured debt could be delayed as a result of the bankruptcy cases;

	•	whether or when secured creditors (or their applicable agents) could repossess or dispose of collateral;

	•	the value of the collateral; or

	•	whether or to what extent secured creditors would be compensated for any delay in payment or loss of value of the collateral through the requirement of “adequate protection.”

In addition, the instruments governing certain of our indebtedness provide that the secured creditors (or their applicable agents) may not object to a number of important matters following the filing of a bankruptcy petition. Accordingly, it is possible that the value of the collateral securing our indebtedness could materially deteriorate and secured creditors would be unable to raise an objection.

Furthermore, if the U.S. Bankruptcy Court determines that the value of the collateral is not sufficient to repay all amounts due on applicable secured indebtedness, the holders of such indebtedness would hold a secured claim to only the extent of the value of their collateral and would otherwise hold unsecured claims with respect to any shortfall. The Bankruptcy Code generally permits the payment and accrual of post-petition interest, costs and attorney’s fees to a secured creditor during a debtor’s bankruptcy case only to the extent the value of its collateral is determined by the Bankruptcy Court to exceed the aggregate outstanding principal amount of the obligations secured by the collateral.

We are subject to additional risks and uncertainties associated with revisions to the Bankruptcy Code that took effect in October 2005. President Bush signed the Bankruptcy Abuse Prevention and Consumer Protection Act of 2005 on April 20, 2005. Revisions to the Bankruptcy Code contained in that Act generally became effective 180 days thereafter, in October 2005, and were in effect at the time we and many of our U.S. subsidiaries filed our Chapter 11 bankruptcy petitions on December 20, 2005. These revisions to the Bankruptcy Code present additional potential risks and uncertainties associated with our bankruptcy cases. Some of the revisions may make it more difficult for us to enforce or obtain certain rights and remedies in Bankruptcy Court, such as with respect to the rejection of certain executory contracts or unexpired real property leases. The revisions also may shorten the time frames in which we must take certain actions, including determining whether to assume or reject unexpired real property leases and filing and seeking

confirmation of a plan of reorganization. In addition, the revisions may limit or prevent our ability to implement a retention program or take other measures intended to motivate key employees to remain with the Company during the pendency of the bankruptcy cases. It may make it more difficult to predict or anticipate a particular outcome because the revisions are new and have not been tested in a case as large or as complex as ours, and so could have unanticipated consequences for us or our creditors.

Accordingly, as a result of the recent Bankruptcy Code revisions, we are subject to additional risks and uncertainty in our bankruptcy cases, which we cannot fully predict or quantify at this time.

Our emergence from bankruptcy is not assured. Our plan of reorganization has not yet been formulated or submitted to the Bankruptcy Court. While we expect to emerge from bankruptcy in the future, there can be no assurance that we will successfully reorganize or, if we do, of the timing.


	*Capital Resources; Liquidity*

Our financial results may be volatile and may not reflect historical trends. While in bankruptcy, we expect our financial results to continue to be volatile as asset impairments, asset dispositions, restructuring activities, contract terminations and rejections, and claims assessments may significantly impact our consolidated financial statements. As a result, our historical financial performance is likely not indicative of our financial performance post-bankruptcy. In addition, upon emergence from bankruptcy, the amounts reported in subsequent consolidated financial statements may materially change relative to historical consolidated financial statements, including as a result of revisions to our operating plans pursuant to our plan of reorganization. In addition, as part of our emergence from bankruptcy protection, we may be required to adopt fresh start accounting in a future period. If fresh start accounting is applicable, our assets and liabilities will be recorded at fair value as of the fresh start reporting date. The fair value of our assets and liabilities may differ materially from the recorded values of assets and liabilities on our consolidated balance sheets. In addition, if fresh start accounting is required, the financial results of the Company after the application of fresh start accounting may be different from historical trends. See Note 2 of the Notes to Consolidated Financial Statements for further information on our accounting while in bankruptcy.

We have substantial liquidity needs and face significant liquidity pressure. At December 31, 2005, our cash and cash equivalents were $785.6 million. In addition, we have entered into the $2 billion DIP Facility, under which, at December 31, 2005, we had outstanding borrowings of $25 million under the $1 billion revolving commitment and no loans under the term loan commitments. We continue to have substantial liquidity needs in the operation of our business and face significant liquidity challenges. Because of our low credit ratings and the restrictions against additional borrowing in our DIP Facility, we believe we may not be able to obtain any material amount of additional debt financing during our bankruptcy cases.

Our liquidity and our ability to continue as a going concern, including our ability to meet our ongoing operational obligations, is dependent upon, among other things: (i) our ability to maintain adequate cash on hand; (ii) our ability to generate cash from operations; (iii) the cost, duration and outcome of the restructuring process; (iv) our ability to comply with our DIP Facility agreement and the adequate assurance provisions of the Cash Collateral Order and (v) our ability to achieve profitability following a restructuring. In conjunction with our advisors, we are working to design and implement strategies to ensure that we maintain adequate liquidity. However, there can be no assurance as to the success of such efforts.

Our DIP Facility imposes significant operating and financial restrictions on us; any failure to comply with these restrictions could have a material adverse effect on our liquidity and our operations. These restrictions could adversely affect us by limiting our ability to plan for or react to market conditions or to meet our capital needs and could result in an event of default under the DIP Facility. These restrictions limit or prohibit our ability, subject to certain exceptions to, among other things:


	•	incur additional indebtedness and issue stock;

	•	make prepayments on or purchase indebtedness in whole or in part;


	•	pay dividends and other distributions with respect to our capital stock or repurchase our capital stock or make other restricted payments;

	•	use DIP Loans for non-US Debtors or make inter-company loans to non-US Debtors;

	•	make certain investments;

	•	enter into transactions with affiliates on other than arms-length terms;

	•	create or incur liens to secure debt;

	•	consolidate or merge with another entity, or allow one of our subsidiaries to do so;

	•	lease, transfer or sell assets and use proceeds of permitted asset leases, transfers or sales;

	•	incur dividend or other payment restrictions affecting certain subsidiaries;

	•	make capital expenditures beyond specified limits;

	•	engage in certain business activities; and

	•	acquire facilities or other businesses.

These limitations include, among other things, limitations on our ability to incur or secure additional indebtedness, make investments, or sell certain assets. Our ability to comply with these covenants depends in part on our ability to implement our restructuring program during the bankruptcy cases. If we are unable to achieve the targets associated with our restructuring program and the other elements of our business plan, we may not be able to comply with these covenants. The DIP Facility contains events of default customary for DIP financings of this type, including cross defaults and certain change of control events. If we fail to comply with the covenants in the DIP Facility and are unable to obtain a waiver or amendment or a default exists and is continuing under the DIP Facility, the lenders could declare outstanding borrowings and other obligations under the DIP Facility immediately due and payable.

Our ability to comply with these covenants may be affected by events beyond our control, and any material deviations from our forecasts could require us to seek waivers or amendments of covenants or alternative sources of financing or to reduce expenditures. We cannot assure you that such waivers, amendments or alternative financing could be obtained, or if obtained, would be on terms acceptable to us. If we are unable to comply with the terms of the DIP Facility, or if we fail to generate sufficient cash flow from operations, or, if it became necessary, to obtain such waivers, amendments or alternative financing, it could adversely impact the timing of, and our ultimate ability to successfully implement a plan of reorganization.

To service our indebtedness and other potential liquidity requirements we will require a significant amount of cash. We have substantial indebtedness that we incurred to finance the acquisition and development of power generation facilities. As of December 31, 2005, our total funded debt was $17.4 billion (including $15.4 billion of consolidated debt and approximately $2.0 billion of unconsolidated debt of wholly owned subsidiaries), our total consolidated assets were $20.5 billion and our stockholders’ deficit was $(5.5) billion. Our ability to make payments on our indebtedness (including interest payments on our DIP Facility and our other outstanding secured indebtedness) and to fund planned capital expenditures and research and development efforts will depend on our ability to generate cash in the future. This, to a certain extent, is subject to industry conditions, as well as general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. We may not be able to generate sufficient cash to meet all of our commitments.

The DIP Facility requires that, subject to limited exceptions, cash proceeds from disposition of assets be used to prepay the loans under the DIP Facility.

Whether we will be able to meet our debt service obligations during the pendency of our bankruptcy cases, and whether we will be able to successfully implement a plan of reorganization will depend primarily upon the operational performance of our power generation facilities, movements in electric and natural gas prices over time, our marketing and risk management activities, our ability to successfully implement our

business plan, including our restructuring program, and our ability to consummate a plan of reorganization, as well as general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control.

This high level of indebtedness has important consequences, including:


	•	limiting our ability to borrow additional amounts for working capital, capital expenditures, debt service requirements, execution of our growth strategy, or other purposes;

	•	limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to service the debt;

	•	increasing our vulnerability to general adverse economic and industry conditions;

	•	limiting our ability to capitalize on business opportunities and to react to competitive pressures and adverse changes in government regulation;

	•	limiting our ability or increasing the costs to refinance indebtedness; and

	•	limiting our ability to enter into marketing, hedging, optimization and trading transactions by reducing the number of counterparties with whom we can transact as well as the volume of those transactions.

We may not have sufficient cash to service our indebtedness and other liquidity requirements. Our ability to successfully consummate a plan of reorganization, to make payments on our DIP Facility and other secured debt, and to fund planned capital expenditures and research and development efforts, will depend, in part, on our ability to generate cash in the future. Following our Chapter 11 filing, we have obtained cash from our operations and borrowings under our DIP Facility. Taking into account our debt service and repayment obligations, our remaining significantly scaled-back construction program, research and development and other planned capital expenditures, we are currently projecting that unrestricted cash on hand together with cash from operations will not by itself be sufficient to meet our cash and liquidity needs for the year. The budget for our DIP Facility takes this shortfall into account, and we expect to have sufficient resources and borrowing capacity under the DIP Facility to meet all of our commitments throughout the projected term of our bankruptcy case. However, the success of our business plan, including our restructuring program, and ultimately our plan of reorganization, will depend on our being able to achieve our budgeted operating results. We anticipate enhancing our margin for error by completing asset sale transactions and otherwise significantly reducing our expenses through announced programs but there can be no assurance that we will be successful in these efforts. In addition, our performance could be impacted to some degree by a number of factors, including general economic and capital market conditions; conditions in energy markets; regulatory approvals and developments; limitations imposed by our existing agreements; and other factors, many of which are beyond our control.

We may be unable to secure additional financing in the future. Our ability to arrange financing (including any extension or refinancing) and the cost of the financing are dependent upon numerous factors. Access to capital (including any extension or refinancing) for participants in the energy sector, including for us, has been significantly restricted since late 2001 and may be further restricted in the future as a result of our bankruptcy filings. Other factors include:


	•	general economic and capital market conditions;

	•	conditions in energy markets;

	•	regulatory developments;

	•	credit availability from banks or other lenders for us and our industry peers, as well as the economy in general;

	•	investor confidence in the industry and in us;

	•	the continued reliable operation of our current power generation facilities; and

	•	provisions of tax and securities laws that are conducive to raising capital.

We have financed our existing power generation facilities using a variety of leveraged financing structures, consisting of senior secured and unsecured indebtedness, including construction financing, project financing, revolving credit facilities, term loans and lease obligations. Each project financing and lease obligation was structured to be fully paid out of cash flow provided by the facility or facilities financed or leased. In the event of a default under a financing agreement which we do not cure, the lenders or lessors would generally have rights to the facility and any related assets. In the event of foreclosure after a default, we might not retain any interest in the facility. While we may utilize non-recourse or lease financing when appropriate, market conditions and other factors may prevent similar financing for future facilities. It is possible that we may be unable to obtain the financing required to develop our power generation facilities on terms satisfactory to us.

We have from time to time guaranteed certain obligations of our subsidiaries and other affiliates. Our lenders or lessors may also seek to have us guarantee the indebtedness for future facilities. Guarantees render our general corporate funds vulnerable in the event of a default by the facility or related subsidiary. Additionally, certain of our debt instruments may restrict our ability to guarantee future debt, which could adversely affect our ability to fund new facilities.

As a result of our impaired credit status due to our bankruptcy and earlier credit ratings downgrades, our operations may be restricted and our liquidity requirements increased. As a result of our bankruptcy and prior credit ratings downgrades, our credit status has been impaired. Such impairment has had a negative impact on our liquidity by reducing attractive financing opportunities and increasing the amount of collateral required by our trading counterparties. In addition, fewer trading counterparties are currently able to do business with us, which reduces our ability to negotiate more favorable terms with them. We expect that our perceived creditworthiness will continue to be impaired throughout the pendency of our bankruptcy cases, and we can make no assurances that our credit ratings will improve in the future. Our impaired credit has resulted in the requirement that we provide additional collateral, letters of credit or cash for credit support obligations, and has increased our cost of capital, made our efforts to raise capital more difficult and had an adverse impact on our subsidiaries’ and our business, financial condition and results of operations.

In particular, in light of our bankruptcy filings and our current credit ratings, many of our customers and counterparties are requiring that our and our subsidiaries’ obligations be secured by letters of credit or cash. Banks issuing letters of credit for our or our subsidiaries’ accounts are similarly requiring that the reimbursement obligations be cash-collateralized. In a typical commodities transaction, the amount of security that must be posted can change daily depending on the mark-to-market value of the transaction. These letter of credit and cash collateral requirements increase our cost of doing business and could have an adverse impact on our overall liquidity, particularly if there were a call for a large amount of additional cash or letter of credit collateral due to an unexpectedly large movement in the market price of a commodity. In addition, our CalBear transaction with Bear Stearns, which we had expected over time to reduce our cash and letter of credit collateral requirements as trades would be executed through Bear Stearns’ wholly owned subsidiary CalBear, has been terminated. Although our collateral requirements had not yet been significantly impacted as the CalBear transaction was in its initial stages, we will not be able to take advantage of the future benefits that the CalBear transaction was expected to have provided. We may use up to $300 million of the revolving credit facility under our DIP Facility for letters of credit, which in addition to cash available under the DIP Facility we believe will be sufficient to satisfy our collateral requirements; however, there can be no assurance that such amounts will be sufficient. While we are exploring with counterparties and financial institutions various alternative approaches to credit support, there can be no assurance that we will be able to provide alternative credit support in lieu of cash collateral or letter of credit posting requirements.

Our ability to generate cash depends upon the performance of our subsidiaries. Almost all of our operations are conducted through our subsidiaries and other affiliates. As a result, we depend almost entirely upon their earnings and cash flow to service our indebtedness, including our DIP Facility, and otherwise to fund our operations. The financing agreements of certain of our subsidiaries and other affiliates generally restrict their ability to pay dividends, make distributions, or otherwise transfer funds to us prior to the payment of their other obligations, including their outstanding debt, operating expenses, lease payments and reserves. While certain of our indentures and other debt instruments limit our ability to enter into agreements that

restrict our ability to receive dividends and other distributions from our subsidiaries, these limitations are subject to a number of significant exceptions (including exceptions permitting such restrictions arising out of subsidiary financings).

We may utilize project financing, preferred equity and other types of subsidiary financing transactions when appropriate in the future. Our indentures and other debt instruments place limitations on our ability and the ability of our subsidiaries to incur additional indebtedness. However, they permit our subsidiaries to incur additional construction/project financing indebtedness and to issue preferred stock to finance the acquisition and development of new power generation facilities and to engage in certain types of non-recourse financings and issuance of preferred stock. In addition, if any such financing were undertaken during the pendency of our bankruptcy cases, it would also require the approval of the applicable Bankruptcy Court [and potentially of certain of our other creditors or statutory committees]. If new subsidiary debt and preferred stock is added to our current debt levels, the risks associated with our substantial leverage could intensify.

Our senior notes and our other senior debt are effectively subordinated to all indebtedness and other liabilities of our subsidiaries and other affiliates and may be effectively subordinated to our secured debt to the extent of the assets securing such debt. Our subsidiaries and other affiliates are separate and distinct legal entities and, except in limited circumstances, have no obligation to pay any amounts due with respect to indebtedness of Calpine Corporation or indebtedness of other subsidiaries or affiliates, and do not guarantee the payment of interest on or principal of such indebtedness. In connection with our bankruptcy cases, we expect that such subsidiaries’ or other affiliates’ creditors, including trade creditors and holders of debt issued by such subsidiaries or affiliates, will generally be entitled to payment of their claims from the assets of those subsidiaries or affiliates before any of those assets are made available for distribution to Calpine Corporation or the holders of Calpine Corporation’s indebtedness. As a result, holders of Calpine Corporation indebtedness will be effectively subordinated to all present and future debts and other liabilities (including trade payables) of its subsidiaries and affiliates, and holders of debt of one of such subsidiaries or affiliates will effectively be so subordinated with respect to all other subsidiaries and affiliates. As of December 31, 2005, our subsidiaries had $5.8 billion of secured construction/project financing (including the CCFC and CalGen financings).

In addition, our unsecured notes and our other unsecured debt are effectively subordinated to all of our secured indebtedness to the extent of the value of the assets securing such indebtedness. Our secured indebtedness includes our $666.7 million in outstanding First Priority Notes and DIP Facility and our $3.7 billion in outstanding Second-Priority Notes and Term Loans. The First Priority Notes and Second-Priority Notes and Term Loans are secured by, respectively, first-priority and second-priority liens on, among other things, substantially all of the assets owned directly by Calpine Corporation, power plant assets and the equity in subsidiaries directly owned by Calpine Corporation. Our $784.5 million of CCFC term loans and notes outstanding as of December 31, 2005, are secured by the assets and contracts associated with the six natural gas-fired electric generating facilities owned by CCFC and its subsidiaries and the CCFC lenders’ and note holders’ recourse is limited to such security. Our $2.4 billion of CalGen secured institutional term loans, notes and revolving credit facility are secured, through a combination of direct and indirect stock pledges and asset liens, by CalGen’s 14 power generating facilities and related assets located throughout the United States, and the CalGen lenders’ and note holders’ recourse is limited to such security. We have additional non-recourse project financings, secured in each case by the assets of the project being financed.


	*Operations*

Revenue may be reduced significantly upon expiration or termination of our PPAs. Some of the electricity we generate from our existing portfolio is sold under long-term PPAs that expire at various times. We also sell power under short to intermediate term (one to five year) PPAs. When the terms of each of these various PPAs expire, it is possible that the price paid to us for the generation of electricity under subsequent arrangements may be reduced significantly.

Our power sales contracts have an aggregate value in excess of current market prices (measured over the next five years) of approximately $1.5 billion at December 31, 2005. Values for our long-term commodity contracts are calculated using discounted cash flows derived as the difference between contractually based

cash flows and the cash flows to buy or sell similar amounts of the commodity on market terms. Inherent in these valuations are significant assumptions regarding future prices, correlations and volatilities, as applicable. Because our power sales contracts are marked to market, the aggregate value of the contracts noted above could decrease in response to changes in the market. We are at risk of loss in margins to the extent that these contracts expire or are terminated and we are unable to replace them on comparable terms. We have four customers with which we have multiple contracts that, when combined, constitute greater than 10% of this value: CDWR $0.3 billion, PG&E $0.7 billion, Wisconsin Power & Light $0.2 billion, and Carolina Power & Light $0.2 billion. The values by customer are comprised of these multiple individual contracts that expire beginning in 2008 and contain termination provisions standard to contracts in our industry such as negligence, performance default or prolonged events of force majeure.

Use of commodity contracts, including standard power and gas contracts (many of which constitute derivatives), can create volatility in earnings and may require significant cash collateral. During 2005 we recognized $11.4 million in mark-to-market gains on electric power and natural gas derivatives after recognizing $13.4 million in gains in 2004 and $26.4 million in losses in 2003. Additionally, we recognized as a cumulative effect of a change in accounting principle, an after-tax gain of approximately $181.9 million from the adoption of DIG Issue No. C20, “Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature” on October 1, 2003. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Application of Critical Accounting Policies,” for a detailed discussion of the accounting requirements relating to electric power and natural gas derivatives. In addition, GAAP treatment of derivatives in general, and particularly in our industry, continues to evolve. We may enter into other transactions in future periods that require us to mark various derivatives to market through earnings. The nature of the transactions that we enter into and the volatility of natural gas and electric power prices will determine the volatility of earnings that we may experience related to these transactions.

Companies using derivatives, many of which are commodity contracts, are sensitive to the inherent risks of such transactions. Consequently (and for us, as a result of our bankruptcy and credit rating downgrades), many companies, including us, are required to post cash collateral for certain commodity transactions in excess of what was previously required. As of December 31, 2005 and 2004, to support commodity transactions, we had margin deposits with third parties of $287.5 million and $276.5 million, respectively; we made gas and power prepayments of $103.2 million and $80.5 million, respectively; and had letters of credit outstanding of $88.1 million and $115.9 million, respectively. Counterparties had deposited with us $27.0 million and $27.6 million as margin deposits at December 31, 2005 and 2004, respectively. We use margin deposits, prepayments and letters of credit as credit support for commodity procurement and risk management activities. Future cash collateral requirements may increase based on the extent of our involvement in standard contracts and movements in commodity prices and also based on our credit ratings and general perception of creditworthiness in this market. See also “— Capital Resources; Liquidity — As a result of our impaired credit status due to our bankruptcy and earlier credit ratings downgrades, our operations may be restricted and our liquidity requirements increased,” above.

We may be unable to obtain an adequate supply of natural gas in the future. To date, our fuel acquisition strategy has included various combinations of our own gas reserves, gas prepayment contracts, short-, medium-and long-term supply contracts, acquisition of gas in storage and gas hedging transactions. In our gas supply arrangements, we attempt to match the fuel cost with the fuel component included in the facility’s PPAs in order to minimize a project’s exposure to fuel price risk. In addition, the focus of CES is to manage the spark spread for our portfolio of generating plants and we actively enter into hedging transactions to lock in gas costs and spark spreads. We believe that there will be adequate supplies of natural gas available at reasonable prices for each of our facilities when current gas supply agreements expire. However, gas supplies may not be available for the full term of the facilities’ PPAs, and gas prices may increase significantly. Additionally, our credit ratings may inhibit our ability to procure gas supplies from third parties. If gas is not available, or if gas prices increase above the level that can be recovered in electricity prices, there could be a negative impact on our results of operations or financial condition.

For the year ended December 31, 2004, we obtained approximately 7% of our physical natural gas supply needs through owned natural gas reserves. Following the sale of our oil and natural gas assets in 2005, we no longer satisfied any of our natural gas supply needs through owned natural gas reserves. Since that time, we obtain our physical natural gas supply from the market and utilize the natural gas financial markets to hedge our exposures to natural gas price risk. Our current less than investment grade credit rating increases the amount of collateral that certain of our suppliers require us to post for purchases of physical natural gas supply and hedging instruments. To the extent that we do not have cash or other means of posting credit, we may be unable to procure an adequate supply of natural gas or natural gas hedging instruments. In addition, the fact that our deliveries of natural gas depend upon the natural gas pipeline infrastructure in markets where we operate power plants exposes us to supply disruptions in the unusual event that the pipeline infrastructure is damaged or disabled.

Our power project development and acquisition activities may not be successful. The development of power generation facilities is subject to substantial risks. In connection with the development of a power generation facility, we must generally obtain:


	•	necessary power generation equipment;

	•	governmental permits and approvals;

	•	fuel supply and transportation agreements;

	•	sufficient equity capital and debt financing;

	•	electrical transmission agreements;

	•	water supply and wastewater discharge agreements; and

	•	site agreements and construction contracts.

To the extent that our development activities continue or resume, we may be unsuccessful in accomplishing any of these matters or in doing so on a timely basis. In addition, project development is subject to substantial risks including various environmental, engineering and construction risks relating to equipment, permitting, financing, obtaining necessary construction and operating agreements (including related to fuel supply and transportation and electrical transmission), cost-overruns, delays and performance targets. Although we may attempt to minimize the financial risks in the development of a project by securing a favorable PPA, obtaining all required governmental permits and approvals, and arranging adequate financing prior to the commencement of construction, the development of a power project may require us to expend significant sums for preliminary engineering, permitting, legal and other expenses before we can determine whether a project is feasible, economically attractive or financeable. If we are unable to complete the development of a facility, we might not be able to recover our investment in the project and may be required to recognize additional impairments. The process for obtaining initial environmental, siting and other governmental permits and approvals is complicated and lengthy, often taking more than one year, and is subject to significant uncertainties. We cannot assure you that we will be successful in the development of power generation facilities in the future or that we will be able to successfully complete construction of our facilities currently in development, nor can we assure you that any of these facilities will be profitable or have value equal to the investment in them even if they do achieve commercial operation.

Our projects under construction may not commence operation as scheduled. The commencement of operation of a newly constructed power generation facility involves many risks, including:


	•	start-up problems;

	•	the breakdown or failure of equipment or processes; and

	•	performance below expected levels of output or efficiency.

New plants have no operating history and may employ recently developed and technologically complex equipment. Insurance (including a layer of insurance provided by a captive insurance subsidiary) is maintained to protect against certain risks, warranties are generally obtained for limited periods relating to the

construction of each project and its equipment in varying degrees, and contractors and equipment suppliers are obligated to meet certain performance levels. The insurance, warranties or performance guarantees, however, may not be adequate to cover lost revenues or increased expenses. As a result, a project may be unable to fund principal and interest payments under its financing obligations and may operate at a loss. A default under such a financing obligation, unless cured, could result in our losing our interest in a power generation facility.

In certain situations, PPAs entered into with a utility early in the development phase of a project may enable the utility to terminate the PPA or to retain security posted as liquidated damages under the PPA. The situations that could allow a utility to terminate a PPA or retain posted security as liquidated damages include:


	•	the cessation or abandonment of the development, construction, maintenance or operation of the facility;

	•	failure of the facility to achieve construction milestones by agreed upon deadlines, subject to extensions due to force majeure events;

	•	failure of the facility to achieve commercial operation by agreed upon deadlines, subject to extensions due to force majeure events;

	•	failure of the facility to achieve certain output minimums;

	•	failure by the facility to make any of the payments owing to the utility under the PPA or to establish, maintain, restore, extend the term of, or increase the posted security if required by the PPA;

	•	a material breach of a representation or warranty or failure by the facility to observe, comply with or perform any other material obligation under the PPA;

	•	failure of the facility to obtain material permits and regulatory approvals by agreed upon deadlines; or

	•	the liquidation, dissolution, insolvency or bankruptcy of the project entity.

Our power generation facilities may not operate as planned. Upon completion of our projects currently under construction, we will operate 95 of the 97 power plants in which we currently have an interest. The continued operation of power generation facilities, including, upon completion of construction, the facilities owned directly by us, involves many risks, including the breakdown or failure of power generation equipment, transmission lines, pipelines or other equipment or processes, and performance below expected levels of output or efficiency. From time to time our power generation facilities have experienced equipment breakdowns or failures, and in 2005 we recorded expenses totaling approximately $33.8 million for these breakdowns or failures compared to $54.3 million in 2004. Continued high failure rates of Siemens-Westinghouse provided equipment represent the highest risk for such breakdowns, although we have programs in place that we believe will eventually substantially reduce these failures and provide plants with Siemens-Westinghouse equipment availability factors competitive with plants using other manufacturers’ equipment.

Although our facilities contain various redundancies and back-up mechanisms, a breakdown or failure may prevent the affected facility from performing under any applicable PPAs. Although insurance is maintained to partially protect against operating risks, the proceeds of insurance may not be adequate to cover lost revenues or increased expenses. As a result, we could be unable to service principal and interest payments under our financing obligations which could result in losing our interest in one or more power generation facility.

Our geothermal energy reserves may be inadequate for our operations. The development and operation of geothermal energy resources are subject to substantial risks and uncertainties similar to those experienced in the development of oil and gas resources. The successful exploitation of a geothermal energy resource ultimately depends upon:


	•	the heat content of the extractable steam or fluids;

	•	the geology of the reservoir;


	•	the total amount of recoverable reserves;

	•	operating expenses relating to the extraction of steam or fluids;

	•	price levels relating to the extraction of steam or fluids or power generated; and

	•	capital expenditure requirements relating primarily to the drilling of new wells.

In connection with each geothermal power plant, we estimate the productivity of the geothermal resource and the expected decline in productivity. The productivity of a geothermal resource may decline more than anticipated, resulting in insufficient reserves being available for sustained generation of the electrical power capacity desired. An incorrect estimate by us or an unexpected decline in productivity could, if material, adversely affect our results of operations or financial condition.

Geothermal reservoirs are highly complex. As a result, there exist numerous uncertainties in determining the extent of the reservoirs and the quantity and productivity of the steam reserves. Reservoir engineering is an inexact process of estimating underground accumulations of steam or fluids that cannot be measured in any precise way, and depends significantly on the quantity and accuracy of available data. As a result, the estimates of other reservoir specialists may differ materially from ours. Estimates of reserves are generally revised over time on the basis of the results of drilling, testing and production that occur after the original estimate was prepared. We cannot assure you that we will be able to successfully manage the development and operation of our geothermal reservoirs or that we will accurately estimate the quantity or productivity of our steam reserves.

Seismic disturbances could damage our projects. Areas where we operate and are developing many of our geothermal and gas-fired projects are subject to frequent low-level seismic disturbances. More significant seismic disturbances are possible. Our existing power generation facilities are built to withstand relatively significant levels of seismic disturbances, and we believe we maintain adequate insurance protection. However, earthquake, property damage or business interruption insurance may be inadequate to cover all potential losses sustained in the event of serious seismic disturbances. Additionally, insurance for these risks may not continue to be available to us on commercially reasonable terms.

Our results are subject to quarterly and seasonal fluctuations. Our quarterly operating results have fluctuated in the past and may continue to do so in the future as a result of a number of factors, including:


	•	seasonal variations in energy prices;

	•	variations in levels of production;

	•	the timing and size of acquisitions; and

	•	the completion of development and construction projects.

Additionally, because we receive the majority of capacity payments under some of our PPAs during the months of May through October, our revenues and results of operations are, to some extent, seasonal.


	*Market*

Competition could adversely affect our performance. The power generation industry is characterized by intense competition, and we encounter competition from utilities, industrial companies, marketing and trading companies, and other IPPs. In recent years, there has been increasing competition among generators in an effort to obtain PPAs, and this competition has contributed to a reduction in electricity prices in certain markets. In addition, many states are implementing or considering regulatory initiatives designed to increase competition in the domestic power industry. For instance, the CPUC issued decisions that provided that all California electric users taking service from a regulated public utility could elect to receive direct access service commencing April 1998; however, the CPUC suspended the offering of direct access to any customer not receiving direct access service as of September 20, 2001, due to the problems experienced in the California energy markets during 2000 and 2001. As a result, uncertainty exists as to the future course for direct access in California in the aftermath of the energy crisis in that state. In Texas, legislation phased in a deregulated

power market, which commenced on January 1, 2001. This competition has put pressure on electric utilities to lower their costs, including the cost of purchased electricity, and increasing competition in the supply of electricity in the future will increase this pressure.


	*California Power Market*

The volatility in the California power market from mid-2000 through mid-2001 has produced significant unanticipated results, and as described in the following risk factors, the unresolved issues arising in that market, where 42 of our 99 power plants are located, could adversely affect our performance.

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

On December 12, 2002, an Administrative Law Judge issued a Certification of Proposed Finding on California Refund Liability (“December 12 Certification”) making an initial determination of refund liability. On March 26, 2003, FERC issued an order (the “March 26 Order”) adopting many of the findings set forth in the December 12 Certification. In addition, as a result of certain findings by the FERC staff concerning the unreliability or misreporting of certain reported indices for gas prices in California during the Refund Period, FERC ordered that the basis for calculating a party’s potential refund liability be modified by substituting a gas proxy price based upon gas prices in the producing areas plus the tariff transportation rate for the California gas price indices previously adopted in the California Refund Proceeding. We believe, based on the available information, that any refund liability that may be attributable to us could total approximately $10.1 million (plus interest, if applicable), after taking the appropriate set-offs for outstanding receivables owed by the CalPX and CAISO to Calpine. We believe we have appropriately reserved for the refund liability that by our current analysis would potentially be owed under the refund calculation clarification in the March 26 Order. The final determination of the refund liability and the allocation of payment obligations among the numerous buyers and sellers in the California markets is subject to further Commission proceedings to ascertain the allocation of payment obligations among the numerous buyers and sellers in the California markets. Furthermore, it is possible that there will be further proceedings to require refunds from certain sellers for periods prior to the originally designated Refund Period. In addition, the FERC orders concerning the Refund Period, the method for calculating refund liability and numerous other issues are pending on appeal before the U.S. Court of Appeals for the Ninth Circuit. At this time, we are unable to predict the timing of the completion of these proceedings or the final refund liability. Thus, the impact on our business is uncertain.

The energy payments made to us during a certain period under our QF contracts with PG&E may be retroactively adjusted downward as a result of a CPUC proceeding. Our qualifying facility, or QF, contracts with PG&E provide that the CPUC has the authority to determine the appropriate utility “avoided cost” to be used to set energy payments by determining the short run avoided cost (“SRAC”) energy price formula. In mid-2000 our QF facilities elected the option set forth in Section 390 of the California Public Utilities Code, which provided QFs the right to elect to receive energy payments based on the CalPX market clearing price instead of the SRAC price administratively determined by the CPUC. Having elected such option, our QF facilities were paid based upon the CalPX Price for various periods commencing in the summer of 2000 until January 19, 2001, when the CalPX ceased operating a day-ahead market. The CPUC has conducted proceedings (R.99-11-022) to determine whether the CalPX Price was the appropriate price for the energy component upon which to base payments to QFs which had elected the CalPX-based pricing option. In late 2000, the CPUC Commissioner assigned to the matter issued a proposed decision to the effect that the CalPX Price was the appropriate energy price to pay QFs who selected the pricing option then offered by Section 390, but the CPUC has yet to issue a final decision. Therefore, it is possible that the CPUC could order a payment adjustment based on a different energy price determination. On April 29, 2004, PG&E, the Utility Reform Network, a consumer advocacy group, and the Office of Ratepayer Advocates, an independent consumer advocacy department of the CPUC (collectively, the “PG&E Parties”), filed a Motion for Briefing

Schedule Regarding True-Up of Payments to QF Switchers (the “April 2004 Motion”). The April 2004 Motion requested that the CPUC set a briefing schedule in the R.99-11-022 docket to determine what is the appropriate price that should be paid to the QFs that had switched to the CalPX Price. The PG&E Parties allege that the appropriate price should be determined using the methodology that has been developed thus far in the California Refund Proceeding discussed above. Supplemental pleadings have been filed on the April 2004 Motion, but neither the CPUC nor the assigned administrative law judge has issued any rulings with respect to either the April 2004 Motion or the initial Emergency Motion. We believe that the CalPX Price was the appropriate price for energy payments for our QFs during this period, but there can be no assurance that this will be the outcome of the CPUC proceedings. On August 16, 2005, the Administrative Law Judge assigned to hear the April 2004 Motion issued a ruling setting October 11, 2005, as the date for filing prehearing conference statements and October 17, 2005, as the date of the prehearing conference. In our response, filed on October 11, 2005, we urged that the April 2004 Motion should be dismissed, but if dismissal were not granted, then discovery, testimony and hearings would be required. The assigned Administrative Law Judge has not yet issued a formal ruling following the October 17, 2005 prehearing conference. We believe that the PX Price was the appropriate price for energy payments and that the basis for any refund liability based on the interim determination by FERC in the California Refund Proceeding is unfounded, but there can be no assurance that this will be the outcome of the CPUC proceedings.

The availability payments made to us under our Geysers’ Reliability Must Run contracts have been challenged by certain buyers as having been not just and reasonable. CAISO, EOB, Public Utilities Commission of the State of California, PG&E, SDG&E, and Southern California Edison Company (collectively referred to as the “Buyers Coalition”) filed a complaint on November 2, 2001 at FERC requesting the commencement of a FPA Section 206 proceeding to challenge one component of a number of separate settlements previously reached on the terms and conditions of RMR contracts with certain generation owners, including Geysers Power Company, LLC, which settlements were also previously approved by FERC. RMR contracts require the owner of the specific generation unit to provide energy and ancillary services when called upon to do so by the ISO to meet local transmission reliability needs or to manage transmission constraints. The Buyers Coalition has asked FERC to find that the availability payments under these RMR contracts are not just and reasonable. On June 3, 2005, FERC issued an order dismissing the Buyers Coalition’s complaint against all named generation owners, including GPC. On August 2, 2005, FERC issued an order denying requests for rehearing of its order. On September 23, 2005, the Buyers Coalition (with the exclusion of the CAISO) filed a Petition for Review with the U.S. Court of Appeals for the D.C. Circuit, seeking review of FERC’s order dismissing the complaint.

RMR payments made to the Delta Energy Center have been challenged by certain parties as not being just and reasonable. Through our subsidiary Delta Energy Center, LLC, we are party to a recurring, yearly RMR contract with the CAISO originally entered into in 2003. When the Delta RMR contract was first offered by us, several issues about the contract were disputed, including whether the CAISO accepted Delta’s bid for RMR service; whether the CAISO was bound by Delta’s bid price; and whether Delta’s bid price was just and reasonable. The Delta RMR contract was filed and accepted by FERC effective February 10, 2003, subject to refund. On May 30, 2003, the CAISO, PG&E and Delta entered into a settlement regarding the Delta RMR contract (the “Delta RMR Settlement”). Under the terms of the Delta RMR Settlement, the parties agreed to interim RMR rates which Delta would collect, subject to refund, from February 10, 2003, forward. The parties agreed to defer further proceedings on the Delta RMR contract until a similar RMR proceeding (the “Mirant RMR Proceeding”) was resolved by FERC. Under the terms of the Delta RMR Settlement, Delta continued to provide services to the CAISO pursuant to the interim RMR rates, terms and conditions. Since the Delta RMR Settlement, Delta and CAISO have entered into RMR contracts for the years 2003, 2004 and 2005 pursuant to the terms of the Delta RMR Settlement.

RMR case. FERC set the proceeding for hearing, but has suspended hearing procedures pending settlement discussions among the parties with respect to the rates for both the February 10, 2003, through December 31, 2005, period and the calendar year 2006 period. In addition, to resolve credit concerns raised by certain intervening parties, Delta has begun to direct into an escrow account the difference between the previously-filed rate and the 2006 rate pending the determination by FERC as to whether Delta is obligated to refund some portion of the rate collected in 2006. We are unable at this time to predict the result of any settlement process or the ultimate ruling by the FERC on the rates for Delta’s RMR services for the period between February 10, 2003 and December 31, 2005 or for calendar year 2006.


	*Government Regulation*

We are subject to complex government regulation which could adversely affect our operations. Our activities are subject to complex and stringent energy, environmental and other governmental laws and regulations. The construction and operation of power generation facilities require numerous permits, approvals and certificates from appropriate foreign, federal, state and local governmental agencies, as well as compliance with environmental protection legislation and other regulations. While we believe that we have obtained the requisite approvals and permits for our existing operations and that our business is operated in accordance with applicable laws, we remain subject to a varied and complex body of laws and regulations that both public officials and private individuals may seek to enforce. Existing laws and regulations may be revised or reinterpreted, or new laws and regulations may become applicable to us that may have a negative effect on our business and results of operations. We may be unable to obtain all necessary licenses, permits, approvals and certificates for proposed projects, and completed facilities may not comply with all applicable permit conditions, statutes or regulations. In addition, regulatory compliance for the construction and operation of our facilities can be a costly and time-consuming process. Intricate and changing environmental and other regulatory requirements may necessitate substantial expenditures to obtain and maintain permits. If a project is unable to function as planned due to changing requirements, loss of required permits or regulatory status or local opposition, it may create expensive delays, extended periods of non-operation or significant loss of value in a project.

Environmental regulations have had and will continue to have an impact on our cost of doing business and our investment decisions. We are subject to complex and stringent energy, environmental and other governmental laws and regulations at the federal, state and local levels in connection with the development, ownership and operation of our energy generation facilities, and in connection with the purchase and sale of electricity and natural gas. Federal laws and regulations govern, among other things, transactions by electric and gas companies, the ownership of these facilities, and access to and service on the electric and natural gas transmission grids. There have been a number of federal legislative and regulatory actions that have recently changed, and will continue to change, how the energy markets are regulated. For example, in March 2005 the EPA adopted a significant air quality regulation, the Clean Air Interstate Rule, that will affect our fossil fuel-fired generating facilities located in the eastern half of the U.S. The Clean Air Interstate Rule addresses the interstate transport of NOx and SO₂ from fossil fuel power generation facilities. Individual states are responsible for developing a mechanism for assigning emissions rights to individual facilities. States’ allocation mechanisms, which will be complete in 2007, will ultimately determine the net impact to us. In addition, the potential for future regulation greenhouse gas emissions continues to be the subject of discussion. Our power generation facilities are significant sources of CO₂ emissions, a greenhouse gas. Our compliance costs with any future federal greenhouse gas regulation could be material. Additional legislative and regulatory initiatives may occur. We cannot provide assurance that any legislation or regulation ultimately adopted would not adversely affect our existing projects.

Complex electric regulations have a continuing impact on our business. Our operations are potentially subject to the provisions of various energy laws and regulations, including the FPA, PUHCA 2005, PURPA and state and local regulations. The FPA regulates wholesale sales of power, as well as electric transmission, in interstate commerce. See Government Regulation — Federal Power Act. PUHCA 2005, which repealed PUHCA 1935 as of February 8, 2006, subjects “holding companies,” as defined in PUHCA 2005, to certain FERC rights of access to the companies’ books and records that are determined by FERC to be relevant to the

companies’ respective FERC-jurisdictional rates See Government Regulation — Public Utility Holding Company Act of 1935. PURPA provides owners of QFs (as defined under PURPA (see Government Regulation — Public Utility Regulatory Policies Act of 1978)) exemptions from certain federal and state regulations, including rate and financial regulations. Each of these laws was created or amended by EPAct 2005, and FERC is still promulgating regulations to implement EPAct 2005’s provisions. We cannot predict what the final effects of these regulations will be on our business.

Under the FPA and FERC’s regulations, the wholesale sale of power at market-based or cost-based rates requires that the seller have authorization issued by FERC to sell power at wholesale pursuant to a FERC-accepted rate schedule. All of our affiliates that own power plants (except for those power plants that are QFs under PURPA or are located in ERCOT), as well as our power marketing companies (collectively referred to herein as “Market Based Rate Companies”), are currently authorized by FERC to make wholesale sales of power at market based rates. This authorization could possibly be revoked for any of our Market Based Rate Companies if they fail in the future to continue to satisfy FERC’s applicable criteria or future criteria as possibly modified by FERC; if FERC eliminates or restricts the ability of wholesale sellers of power to make sales at market-based rates; or if FERC institutes a proceeding, based upon its own motion or a complaint brought by a third party, and establishes that any of our Market Based Rate Companies’ existing rates have become either unjust and unreasonable or contrary to the public interest (the applicable standard is determined by the circumstances). FERC could also revoke a seller’s market-based rate authority if the seller does not comply with FERC’s quarterly and triennial reporting requirements or notify FERC of any change in the seller’s status that would reflect a departure from the characteristics FERC relied upon in granting market-based rate authority to the seller. If the seller’s market-based rate authority is revoked, the seller could be liable for refunds of certain sales made at market-based rates.

Our Market Based Rate Companies also must comply with FERC’s application, filing, and reporting requirements for persons holding or proposing to hold certain interlocking directorates. If the appropriate filings are not made, FERC can deny the person from holding the interlocking positions.

Under PUHCA 2005, we and certain companies within our organizational structure are holding companies otherwise subject to the books and records access requirements. However, we and our subsidiary holding companies are exempt from the books and records access requirement because we are holding companies solely with respect to one or more QFs, EWGs and FUCOs. If one of our subsidiary project companies were to lose their QF, EWG or FUCO status, we would lose this exemption. Consequently, all holding companies within our corporate structure would be subject to the books and records access requirement of PUHCA 2005, in addition to stringent holding company record-keeping and reporting requirements mandated by FERC’s rules. If we lose the exemption, we could seek a waiver of the record-keeping and reporting requirements, but we cannot provide assurance that we would obtain such waiver.

In order to avail ourselves of the benefits provided by PURPA, our project companies must own or, in some instances, operate a QF. For a cogeneration facility to qualify as a QF, FERC requires the QF to produce electricity as well as thermal energy in specified minimum proportions. The QF also must meet certain minimum energy efficiency standards. In addition, EPAct 2005 and FERC’s implementing regulations require new cogeneration QFs to demonstrate that their thermal output will be used in a “productive and beneficial manner” and that the facility’s electrical, thermal, chemical, and mechanical output will be used fundamentally for industrial, commercial, residential, or institutional purposes. Generally, any geothermal power facility which produces not more than 80 MW of electricity qualifies for QF status. FERC’s regulations implementing EPAct 2005 require QFs to obtain market-based rate authorization for wholesale sales that are made pursuant to a contract executed after March 17, 2006, and not under a state regulatory authority’s implementation of section 210 of PURPA.

Certain factors necessary to maintain QF status are subject to the risk of events outside our control. For example, some of our facilities have temporarily been rendered incapable of meeting FERC’s QF criteria due to the loss of a thermal energy customer. Such loss of a steam host could occur, for example, if the steam host, typically an industrial facility, fails for operating, permit or economic reasons to use sufficient quantities of the QF’s steam output. In these cases, we have obtained from FERC limited waivers (for up to two years) of the

applicable QF requirements. We cannot provide assurance that such waivers will in every case be granted. During any such waiver period, we would seek to replace the thermal energy customer or find another use for the thermal energy which meets PURPA’s requirements, but no assurance can be given that these remedial actions would be available. We also cannot provide assurance that all of our steam hosts will continue to take and use sufficient quantities of their respective QF’s steam output.

If any of our QFs lose their QF status, the owner of the QF would need to obtain FERC acceptance of a market-based or cost-based rate schedule to continue making wholesale power sales. To maintain our exemption from PUHCA 2005, the owner would also need to obtain EWG status. We cannot provide assurance that such FERC acceptance of a rate schedule or EWG status would be obtained. In addition, a loss of QF status could, depending on the facility’s particular power purchase agreement, allow the power purchaser to cease taking and paying for electricity or to seek refunds of past amounts paid and thus could cause the loss of some or all contract revenues or otherwise impair the value of a project. If a power purchaser were to cease taking and paying for electricity, there can be no assurance that the costs incurred in connection with the project could be recovered through sales to other purchasers.

FERC has proposed to eliminate prospectively electric utilities’ requirement under Section 210 of PURPA to purchase power from QFs at the utility’s “avoided cost,” to the extent FERC determines that such QFs have access to a competitive wholesale electricity market. FERC has also proposed procedures for utilities to file to obtain relief from mandatory purchase obligations on a service territory-wide basis, and provides procedures for affected QFs to file to reinstate the purchase obligation. Consistent with EPAct 2005, FERC proposes to leave intact existing rights under any contract or obligation in effect or pending approval involving QF purchases or sales. FERC has not taken any final action. We cannot predict what effect this proposal, and FERC’s final regulations, if any, implementing it, will have on our business.

For those other regulations that FERC will promulgate in the future in connection with EPAct 2005, we cannot predict what effect these future regulations may have on our business. Furthermore, we cannot predict what future laws or regulations may be promulgated. We do not know whether any other new legislative or regulatory initiatives will be adopted or, if adopted, what form they may take. We cannot provide assurance that any legislation or regulation ultimately adopted would not adversely affect the operation of and generation of electricity by our business.

State PUCs have historically had broad authority to regulate both the rates charged by, and the financial activities of, electric utilities operating in their states and to promulgate regulations for implementation of PURPA. Retail sales of electricity or thermal energy by an independent power producer may be subject to PUC regulation depending on state law. States may also assert jurisdiction over the siting and construction of electricity generating facilities including QFs and EWGs and, with the exception of QFs, over the issuance of securities and the sale or other transfer of assets by these facilities. We cannot predict what laws or rules will be enacted by states or PUCs or how these laws and rules would affect our business.

Natural gas regulations have a continuing impact upon our business. The cost of natural gas is ordinarily the largest operational expense of a gas fired project and is critical to the project’s economics. The risks associated with using natural gas can include the need to arrange gathering, processing, extraction, blending and storage, as well as transportation of the gas from great distances, including obtaining removal, export and import authority if the gas is imported from a foreign country; the possibility of interruption of the gas supply or transportation (depending on the quality of the gas reserves purchased or dedicated to the project, the financial and operating strength of the gas supplier, whether firm or nonfirm transportation is purchased, and the operations of the gas pipeline); regulatory diversion; and obligations to take a minimum quantity of gas and pay for it (i.e., take and pay obligations).

As the owner of more than 70 natural gas fired power plants, we rely on the natural gas pipeline grid for delivery of fuel. The use of pipelines for delivery of natural gas has proven to be an efficient and reliable method of meeting customers’ fuel needs. We believe that our risk of fuel supply disruption resulting from pipeline operation difficulties is limited, given the historical performance of pipeline operators and, in certain instances, multiple pipeline interconnections to the generation facilities. However, if a disruption were to

occur, the effect could be substantial, including outages at one of more of our plants until we were able to secure fuel supplies.

As a purchaser and seller of natural gas in the wholesale market, as well as a transportation customer on interstate pipelines, we are subject to FERC regulation regarding the sale of natural gas and the transportation of natural gas. We cannot predict what new regulations FERC may enact in the future or how these regulations would affect our business.


Item 1B.	*Unresolved Staff Comments*

None


Item 2.	*Properties*

Our principal executive office located in San Jose, California is held under leases that expire through 2014. We also lease offices, with leases expiring through 2013, in Sacramento and Folsom, California; Houston and Pasadena, Texas; Boston, Massachusetts; Washington, D.C.; Calgary, Alberta; and Boca Raton and Jupiter, Florida. We hold additional leases for other satellite offices. Subsequent to December 31, 2005, we filed motions in the U.S. Bankruptcy Court to reject certain of our office leases and have closed several of our offices, including our offices in Dublin, California and Tampa, Florida. We anticipate that it is more likely than not we will file further notices of rejection in connection with our bankruptcy cases. See Notes 3 and 34 of the Notes to Consolidated Financial Statements for more information on notices of rejection and the bankruptcy cases.

We either lease or own the land upon which our power-generating facilities are built. We believe that our properties are adequate for our current operations. A description of our power-generating facilities is included under Item 1. “Business.”

We have leasehold interests in 104 leases comprising approximately 25,826 acres of federal, state and private geothermal resource lands in The Geysers area in northern California. In the Glass Mountain and Medicine Lake areas in northern California, we hold leasehold interests in 41 leases comprising approximately 46,400 acres of federal geothermal resource lands.

In general, under these leases, we have the exclusive right to drill for, produce and sell geothermal resources from these properties and the right to use the surface for all related purposes. Each lease requires the payment of annual rent until commercial quantities of geothermal resources are established. After such time, the leases require the payment of minimum advance royalties or other payments until production commences, at which time production royalties are payable. Such royalties and other payments are payable to landowners, state and federal agencies and others, and vary widely as to the particular lease. The leases are generally for initial terms varying from 10 to 20 years or for so long as geothermal resources are produced and sold. Certain of the leases contain drilling or other exploratory work requirements. In certain cases, if a requirement is not fulfilled, the lease may be terminated and in other cases additional payments may be required. We believe that our leases are valid and that we have complied with all the requirements and conditions material to the continued effectiveness of the leases. A number of our leases for undeveloped properties may expire in any given year. Before leases expire, we perform geological evaluations in an effort to determine the resource potential of the underlying properties. We can make no assurance that we will decide to renew any expiring leases.

We sold substantially all of our remaining domestic oil and gas assets to Rosetta in July 2005. As of December 31, 2005, we continue to own certain oil and gas properties, including certain oil and gas properties yet to be transferred to Rosetta in connection with the July 2005 sale. Properties remaining to be transferred include (i) certain properties which are subject to ministerial governmental action approving Rosetta as a qualified assignee and operator and (ii) as described further in Note 13, certain other properties as to which approximately $75 million of the purchase price was withheld pending the transfer of such properties for which consents had not yet been obtained at the closing date. Accordingly, we currently retain ownership of such properties.


Item 3.	*Legal Proceedings*

See Note 31 of the Notes to Consolidated Financial Statements for a description of our legal proceedings.


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

None.

PART II


Item 5.	*Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities*

Public trading of our common stock commenced on September 20, 1996, on the NYSE under the symbol “CPN.” Prior to that, there was no public market for our common stock. On December 2, 2005, the NYSE notified us that it was suspending trading in our common stock prior to the opening of the market on December 6, 2005, and the SEC approved the application of the NYSE to delist our common stock effective March 15, 2006. Since December 6, 2005, our common stock has traded over-the-counter on the Pink Sheets under the symbol “CPNLQ.PK.” Certain restrictions in trading are imposed under a U.S. Bankruptcy Court order that requires certain direct and indirect holders (or persons who may become direct or indirect holders) of our common stock to provide the U.S. Debtors, their counsel and the Bankruptcy Court advance notice of their intent to buy or sell our common stock (including options to acquire common stock and other equity linked instruments) prior to effectuating any such transfer.

The following table sets forth the high and low sale price per share of our common stock as reported on the NYSE Composite Transactions Tape for the period January 1 to December 5, 2005, and January 1 to December 31, 2004, and on the over-the-counter market (as reported in the Pink Sheets) from December 6 to December 31, 2005. The stock price information is based on published financial sources. Over-the-counter market quotations reflect inter-dealer prices, without retail mark-up, mark-down or commissions, and may not necessarily reflect actual transactions.


	High		Low		Market

2004
First Quarter	$	6.42	$	4.35	NYSE
Second Quarter		4.98		3.04	NYSE
Third Quarter		4.46		2.87	NYSE
Fourth Quarter		4.08		2.24	NYSE
2005
First Quarter	$	3.80	$	2.64	NYSE
Second Quarter		3.60		1.45	NYSE
Third Quarter		3.88		2.26	NYSE
Fourth Quarter		3.05		0.20	NYSE (high)
					Pink Sheets (low)

As of December 31, 2005, there were approximately 2,345 holders of record of our common stock. On December 31, 2005, the last sale price reported on the Pink Sheets for our common stock was $0.21 per share.

We have not declared any cash dividends on our common stock during the past two fiscal years. We do not anticipate being able to pay any cash dividends on our common stock in the foreseeable future because of our bankruptcy filing and liquidity constraints. In addition, our ability to pay cash dividends is restricted under certain of our indentures and our other debt agreements. Future cash dividends, if any, will be at the discretion of our board of directors and will depend upon, among other things, our future operations and earnings, capital requirements, general financial condition, contractual restrictions and such other factors as our Board of Directors may deem relevant.

See “Securities Authorized for Issuance Under Equity Compensation Plans” in Item 12 below.


Item 6.	*Selected Financial Data*


	*Selected Consolidated Financial Data*


		Years Ended December 31,

		2005			2004			2003			2002		2001

		(In thousands, except earnings per share)
Statement of Operations data:
Total revenue		$	10,112,658		$	8,648,382		$	8,421,170		$	7,069,198	$	6,338,305

Income (loss) before discontinued operations and cumulative effect of a change in accounting principle		$	(9,880,954	)	$	(419,683	)	$	(13,272	)	$	1,463	$	470,557
Discontinued operations, net of tax			(58,254	)		177,222			114,351			117,155		151,899
Cumulative effect of a change in accounting principle(1)			—			—			180,943			—		1,036

Net income (loss)		$	(9,939,208	)	$	(242,461	)	$	282,022		$	118,618	$	623,492

Basic earnings (loss) per common share:
	Income (loss) before discontinued operations and cumulative effect of a change in accounting principle	$	(21.32	)	$	(0.97	)	$	(0.03	)	$	—	$	1.55
	Discontinued operations, net of tax		(0.12	)		0.41			0.29			0.33		0.50
	Cumulative effect of a change in accounting principle, net of tax		—			—			0.46			—		—

	Net income (loss)	$	(21.44	)	$	(0.56	)	$	0.72		$	0.33	$	2.05

Diluted earnings (loss) per common share:
	Income (loss) before discontinued operations and cumulative effect of a change in accounting principle	$	(21.32	)	$	(0.97	)	$	(0.03	)	$	—	$	1.32
	Discontinued operations, net of tax provision		(0.12	)		0.41			0.29			0.33		0.48
	Cumulative effect of a change in accounting principle, net of tax		—			—			0.45			—		—

	Net income (loss)	$	(21.44	)	$	(0.56	)	$	0.71		$	0.33	$	1.80

Balance Sheet data:
Total assets		$	20,544,797		$	27,216,088		$	27,303,932		$	23,226,992	$	21,937,227
Short-term debt and capital lease obligations			5,413,937			1,029,257			346,994			1,651,448		25,307
Long-term debt and capital lease obligations			2,462,462			16,940,809			17,324,284			12,456,259		12,490,175
Liabilities subject to compromise(2)			14,610,064			—			—			—		—
Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts(3)		$	—		$	—		$	—		$	1,123,969	$	1,122,924


(1)	The 2003 gain from the cumulative effect of a change in accounting principle included three items: (1) a gain of $181.9 million, net of tax effect, from the adoption of DIG Issue No. C20; (2) a loss of $1.5 million associated with the adoption of FIN 46, as revised and the deconsolidation of the Trusts which issued the HIGH TIDES and (3) a gain of $0.5 million, net of tax effect, from the adoption of SFAS No. 143 “Accounting for Asset Retirement Obligations.”

(2)	LSTC include unsecured and undersecured liabilities incurred prior to the Petition Date and exclude liabilities that are fully secured or liabilities of our subsidiaries or affiliates that have not made bankruptcy filings and other approved payments such as taxes and payroll. See Note 24 of the Notes to Consolidated Financial Statements for more information.


(3)	Included in long-term debt as of December 31, 2004 and 2003. See Note 14 of the Notes to Consolidated Financial Statements for more information.


	*Selected Operating Information*


			Years Ended December 31,

			2005		2004		2003		2002		2001

			(Dollars in thousands, except pricing data)
Power Plants(1):
Electricity and steam revenues:
	Energy		$	4,676,631	$	3,782,205	$	3,023,327	$	2,072,257	$	1,593,452
	Capacity			1,103,118		1,002,939		965,728		757,562		507,542
	Thermal and other			499,091		380,203		302,119		164,132		138,845

		Total electricity and steam revenues	$	6,278,840	$	5,165,347	$	4,291,174	$	2,993,951	$	2,239,839
MWh produced				87,431		83,412		70,856		63,172		38,445
Average electric price per MWh generated(2)			$	71.81	$	61.93	$	60.56	$	47.39	$	58.26


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

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

Set forth above is certain selected operating information for our power plants for which results are consolidated in our statements of operations. Electricity revenue is composed of fixed capacity payments, which are not related to production, and variable energy payments, which are related to production. Capacity revenues include, besides traditional capacity payments, other revenues such as Reliability Must Run and Ancillary Service revenues. The information set forth under thermal and other revenue consists of host steam sales and other thermal revenue.

Set forth below is a table summarizing the dollar amounts and percentages of our total revenue for the years ended December 31, 2005, 2004, and 2003, that represent purchased power and purchased gas sales for hedging and optimization and the costs we incurred to purchase the power and gas that we resold during these periods (in thousands, except percentage data):


	Years Ended December 31,

	2005			2004			2003

Total revenue	$	10,112,658		$	8,648,382		$	8,421,170
Sales of purchased power and gas for hedging and optimization(1)		3,667,992			3,376,293			4,033,193
As a percentage of total revenue		36.27	%		39.04	%		47.89	%
Total cost of revenue		12,057,581			8,268,433			7,814,343
Purchased power and gas expense for hedging and optimization(1)		3,417,153			3,198,690			3,962,613
As a percentage of total cost of revenue		28.34	%		38.69	%		50.71	%


(1)	On October 1, 2003, we adopted on a prospective basis EITF Issue No. 03-11 and netted certain purchases of power against sales of purchased power. See Note 2 of the Notes to Consolidated Financial Statements for a discussion of our application of EITF Issue No. 03-11.

The primary reasons for the significant levels of these sales and costs of revenue items include: (a) significant levels of hedging, balancing and optimization activities by our CES risk management organization; (b) particularly volatile markets for electricity and natural gas, which prompted us to frequently adjust our hedge positions by buying power and gas and reselling it; (c) the accounting requirements under

SAB No. 104, “Revenue Recognition,” and EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent,” under which we show most of our hedging contracts on a gross basis (as opposed to netting sales and cost of revenue); and (d) rules in effect associated with the NEPOOL market in New England, which require that all power generated in NEPOOL be sold directly to the ISO in that market; we then buy from the ISO to serve our customer contracts. GAAP required us to account for this activity, which applies to three of our merchant generating facilities, as the aggregate of two distinct sales and one purchase until our prospective adoption of EITF Issue No. 03-11 on October 1, 2003. This gross basis presentation increased revenues but not gross profit. The table below details the financial extent of our transactions with NEPOOL for financial periods prior to the adoption of EITF Issue No. 03-11. Our entrance into the NEPOOL market began with our acquisition of the Dighton, Tiverton and Rumford facilities on December 15, 2000.


		Nine Months
		Ended
		September 30,
		2003

		(In thousands)
Sales to NEPOOL from power we generated		$	258,945
Sales to NEPOOL from hedging and other activity			117,345

	Total sales to NEPOOL	$	376,290
Total purchases from NEPOOL		$	310,025

(The statement of operations data information and the balance sheet data information contained in the Selected Financial Data is derived from the audited Consolidated Financial Statements of Calpine Corporation and Subsidiaries. See the Notes to Consolidated Financial Statements and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations” for additional information.)


Item 7.	*Management’s Discussion and Analysis of Financial Condition and Results of Operations*


	*Overview*

Our core business and primary source of revenue is the generation and delivery of electric power. We provide power to our U.S. and Canadian customers through the integrated development, construction or acquisition, and operation of efficient and environmentally friendly electric power plants fueled primarily by natural gas and, to a much lesser degree, by geothermal resources. We protect and enhance the value of our electric assets and gas positions with a sophisticated risk management organization. We also protect our power generation assets and control certain of our costs by producing certain of the combustion turbine replacement parts that we use at our power plants, and we generate revenue by providing combustion turbine parts to third parties. Finally, through 2005, we offered services to third parties to capture value in the skills we have honed in building, commissioning, repairing and operating power plants; however, we are discontinuing this activity.

In 2005, we recorded material impairment charges totaling $4,530.3 million on power plants in development, construction and operations and reorganization items charges totaling $5,026.5 million related to our bankruptcy filing.

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

Our key opportunities and challenges include:


	•	developing and executing our new business plan, including enhancing the value of our core assets and businesses during the pendency of our bankruptcy cases;


	•	preserving and enhancing our liquidity while spark spreads (the differential between power revenues and fuel costs) are depressed;

	•	lowering our costs of production and overhead through various efficiency programs;


	•	developing, proposing, confirming and implementing our plan of reorganization; and

	•	emerging from bankruptcy as a stronger, more competitive company.


	Bankruptcy Considerations

Since December 20, 2005, we and 273 of our direct and indirect wholly owned subsidiaries in the United States filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code and, in Canada, 12 of our wholly owned Canadian subsidiaries have been granted creditor protection under the CCAA. See Note 3 of the Notes to Consolidated Financial Statements for more information regarding these proceedings.

Our bankruptcy filings were preceded by the convergence of a number of factors. Among other things, during that time we were continuing to experience a tight liquidity situation due in part to our obligations to service our debt and certain of our preferred equity securities. Our debt and preferred equity instruments also contained restrictions on our ability to raise further capital, whether through financings, asset sales or otherwise, or restricted the use of the proceeds of any such transactions. At the same time, market spark spreads were being adversely impacted by excess capacity in certain of our energy markets, which had resulted in our facilities running at a reduced average baseload capacity factor of 43.9% by 2005. Our fuel costs were also adversely impacted by historically high prices for natural gas in late 2005 at a time when we were more exposed to gas price volatility after the sale in July 2005 of substantially all of our remaining oil and gas reserves. Higher gas prices also increased our collateral support obligations to counter-parties. Also during that time, we experienced certain adverse litigation outcomes, particularly in a litigation we brought in the Delaware Chancery Court against the collateral agent and trustees representing our First and Second Priority Notes regarding our use of certain of the proceeds of the sale of our oil and natural gas reserves. Accordingly, as we brought new, partially uncontracted capacity into commercial operations, we were not able to realize sufficient incremental spark spread margins to meet our increased debt service and preferred equity obligations and to fund our operations, while restrictions in our debt and preferred equity instruments prevented us from pursuing alternative funding opportunities or reducing those obligations.

Through the bankruptcy process and reorganization, we intend to restructure the Company to strengthen our core power generation business while reducing activities and curtailing expenditures in certain non-core areas and business units. A fundamental aspect of the restructuring will be the establishment of a capital structure that is consistent with our refocused business, which will allow us to be able to successfully compete in the current environment where persistently low spark spreads and the effects of overcapacity and incomplete deregulation in the power generation business have resulted in reduced cash flows. While in bankruptcy, we expect our financial results to be volatile as asset impairments, asset dispositions, restructuring activities, lease and other contract terminations and rejections, and claims assessments will likely significantly impact our consolidated financial statements. As a result, our historical financial performance is likely not indicative of our financial performance during bankruptcy.

In addition, upon emergence from bankruptcy, the amounts reported in subsequent consolidated financial statements may materially change relative to historical consolidated financial statements as a result of revisions to our operating plans effected in connection with our bankruptcy reorganization and, if required to be applied, the impact of revaluing our assets and liabilities by applying fresh start accounting in accordance with the AICPA’s Statement of Position 90-7, “Financial Reporting by Entities in Reorganization under the Bankruptcy Code.”

We expect our bankruptcy cases to follow three general phases — stabilization, plan design and implementation. These phases are described below:


	•	Stabilization — During this initial phase, we are focused on stabilizing our business operations and adjusting to the changes caused by bankruptcy. Our activities during this period include securing the DIP Facility, establishing working relationships with our various creditor committees and their advisors and performing a comprehensive lease and executory contract review process. We have made significant progress in this phase and will continue our stabilization efforts during 2006, particularly with regard to the lease and executory contract review process.

	•	Plan Design — In this phase, we assess the business and prepare a business plan, evaluate claims made against the Calpine Debtors and prepare a plan of reorganization that is intended to maximize the value of the bankruptcy estate. We are in the early stages of this phase now and will likely be in this phase throughout 2006. The period during which we have the exclusive right to propose a plan or plans of reorganization has been extended by the U.S. Bankruptcy Court to December 31, 2006, and we have the exclusive right to solicit acceptances of any such plans until March 31, 2007.

	•	Implementation — In this phase, we will continue to negotiate our plan of reorganization with creditor committees with the expectation that an agreed plan of reorganization, supported by our official and ad hoc creditor committees, will be proposed and filed with the U.S. Bankruptcy Court, and an agreed plan, which may contemplate liquidation of the Canadian Debtors, filed with the Canadian Court. In addition, during this phase we will determine how the claims of various creditors and interests of equity holders, if any, will be satisfied. This is the final phase and we expect that it will result in our emergence from bankruptcy. However, we cannot be sure at this time when or if we will emerge from bankruptcy. It is possible that some or all of the assets of any one or more of the Calpine Debtors may be sold.

Among other things, we arranged, and the U.S. Bankruptcy Court approved, our DIP Facility, including related cash collateral and adequate assurance motions which has allowed our business activities to continue to function. We have also sought and obtained U.S. Bankruptcy Court approval through our “first day” and subsequent motions to continue to pay critical vendors, meet our payroll pre-petition and post-petition obligations, maintain our cash management systems, collateralize our gas supply contracts, enter into and collateralize trading contracts, pay our taxes, continue to provide employee benefits, maintain our insurance programs and implement an employee severance program, which has allowed us to continue to operate the existing business in the ordinary course. In addition, the U.S. Bankruptcy Court has approved certain trading notification and transfer procedures designed to allow us to restrict trading in our common stock (and related securities) which could negatively impact our accrued NOLs and other tax attributes, and granted us extensions of time to file and seek approval of a plan of reorganization and to assume or reject real property leases. See Item 1. “Business” and Notes 3 and 22 of the Notes to Consolidated Financial Statements for additional information regarding our DIP Facility and other bankruptcy matters.

We have established a systematic and comprehensive lease and executory contract review process to determine which leases and contracts we should assume and which we should reject in the bankruptcy process. As of December 31, 2005, we had sought to reject eight PPAs, which were significantly below market. On February 6, 2006, we filed a notice of rejection with the U.S. Bankruptcy Court to reject the Rumford and Tiverton power plant leases. We continue to review all leases and executory contracts, including office and power plant facility leases, and anticipate that we will seek to reject further leases or other contracts as we continue our efforts to strengthen and stabilize the Company’s financial condition. See Item 1. “Business” and Note 3 of the Notes to Consolidated Financial Statements for additional information regarding the contract rejections.

As part of the bankruptcy process, claims are filed with the applicable Bankruptcy Court related to amounts that claimants believe the Calpine Debtors owe them. The U.S. Bankruptcy Court has set August 1, 2006, as the bar date by which all claims against the U.S. Debtors are required to be filed, and the Canadian Court has set June 30, 2006, as the bar date by which all claims against the Canadian Debtors are required to be filed. An evaluation of actual or potential bankruptcy claims, which are not already reflected as a liability

on the balance sheet, must meet the SFAS No. 5, “Accounting for Contingencies,” criteria before an additional liability can be recorded. Due to the close proximity of our bankruptcy filing date to our fiscal year-end date, we have not yet been presented with significant additional claims that meet the SFAS No. 5 criteria (probable and can be reasonably estimated) to be accrued at December 31, 2005. However, if valid unrecorded claims are presented to the Company in future periods, we would need to accrue for them. See “ — Application of Critical Accounting Policies” for additional information. Calpine Corporation has issued redundant guarantees on approximately $2.0 billion of the debt of Canadian Debtor subsidiaries. Therefore, we expect that the amount of claims filed related to funded debt will be significantly greater than our total funded debt of approximately $17.4 billion as of December 31, 2005, which consists of approximately $7.9 billion classified as debt in our consolidated balance sheet, approximately $7.5 billion classified within LSTC, and approximately $2.0 billion of debt issued by deconsolidated Canadian entities.


	*Results of Operations*

Set forth below are the results of operations for the years ending December 31, 2005, 2004, and 2003 (in millions, except for unit pricing information, percentages and MW volumes); in the comparative tables below, increases in revenue/income or decreases in expense (favorable variances) are shown without brackets while decreases in revenue/income or increases in expense (unfavorable variances) are shown with brackets. Prior year amounts reflect reclassifications for discontinued operations. See Note 13 of the Notes to Consolidated Financial Statements for more information regarding our discontinued operations.

As indicated above, our historical financial performance is likely not indicative of our future financial performance during bankruptcy and beyond because, among other things: (1) we will not accrue interest expense on unsecured or under-secured debt during bankruptcy; (2) we expect to dispose of certain plants that do not generate positive cash flow or which are considered non-strategic; (3) we have begun to implement overhead reduction programs; and (4) we expect to reject certain unprofitable or burdensome contracts and leases. During bankruptcy we expect to incur substantial reorganization expenses and could record additional impairment charges albeit at different levels than we incurred in 2005. In addition, as part of our emergence from bankruptcy protection, we may be required to adopt fresh start accounting in a future period. If fresh start accounting is applicable, our assets and liabilities will be recorded at fair value as of the fresh start reporting date. The fair value of our assets and liabilities may differ materially from the recorded values of assets and liabilities on our consolidated balance sheets. In addition, if fresh start accounting is required, the financial results of the Company after the application of fresh start accounting may be different from historical trends.

In the past several years, as we have brought on-line new merchant (uncontracted) capacity, we have seen baseload capacity factors decline and have experienced faster growth in costs of ownership (depreciation, interest expense and plant operating expense) than we have realized in additional spark spreads (the margin between electricity sales and fuel costs). Consequently, our basic operating results have worsened.

We expect that through the programs implemented to date, together with those emanating from our plan of reorganization, once completed and approved, we will emerge from bankruptcy protection on a more financially sound and profitable basis.


	Year Ended December 31, 2005, Compared to Year Ended December 31, 2004


	*Revenue*


	2005		2004		$ Change		% Change

Total revenue	$	10,112.7	$	8,648.4	$	1,464.3		16.9%

The increase in total revenue is explained by category below.


	2005		2004		$ Change		% Change

Electricity and steam revenue	$	6,278.8	$	5,165.3	$	1,113.5		21.6%

E&S revenue increased as we completed construction and brought into operation four new baseload power plants in 2005, and our average consolidated operating capacity increased by 3,009 MW, or 13.6%, to 25,207 MW at December 31, 2005. We also realized a 16.0% increase in our average electric price before the effects of hedging, balancing and optimization, from $61.93/ MWh in 2004 to $71.81/ MWh in 2005. Generation increased by 4.8% to 87.4 million MWh. The increase in generation lagged behind the increase in average MW in operation as our baseload capacity factor dropped to 43.9% in 2005 from 48.5% in 2004 primarily due to the increased occurrence of unattractive off-peak market spark spreads in certain areas due in part to mild weather and also due to oversupply conditions in those markets, which caused us to cycle off certain of our merchants plants without contracts in off peak hours.


	2005		2004		$ Change			% Change

Transmission sales revenue	$	11.5	$	20.0	$	(8.5	)		(42.5)%

We purchase transmission capacity so that power can move from our plants to our customers. Transmission capacity can be purchased on a long-term basis and, in many of the markets in which we operate, can be resold if we do not need it and some other party can use it. If the generation from our plants is less than we anticipated when we purchased the transmission capacity, we can and do realize revenue by selling the unused portion of the transmission capacity.

We also, in many cases, bill our customers for transmission costs that we incur in serving their accounts. This is especially true in the case of many of our retail contracts. When we bill our customers for transmission expenses incurred on their behalf we recognize these billings as a component of transmission revenue. For the year ended December 31, 2005, as compared to the same period in 2004, transmission revenues have declined as we have seen a reduction in transmission billings related to our retail customers.


	2005		2004		$ Change		% Change

Sales of purchased power and gas for hedging and optimization	$	3,668.0	$	3,376.3	$	291.7		8.6	%

Sales of purchased power and gas for hedging and optimization increased during 2005 due primarily to higher volumes of gas purchased and higher prices of natural gas as compared to the same period in 2004.


		2005			2004			$ Change			% Change

Realized gain on power and gas mark-to-market transactions, net		$	106.5		$	48.1		$	58.4			121.4	%
Unrealized (loss) on power and gas mark-to-market transactions, net			(95.1	)		(34.7	)		(60.4	)		174.1	%

	Mark-to-market activities, net	$	11.4		$	13.4		$	(2.0	)		(14.9	)%

Mark-to-market activities, which are shown on a net basis, result from general market price movements against our open commodity derivative positions, including positions accounted for as trading under EITF Issue No. 02-03 and other mark-to-market activities. These commodity positions represent a small portion of our overall commodity contract position. Realized revenue represents the portion of contracts actually settled and is offset by a corresponding change in unrealized gains or losses as unrealized derivative values are converted from unrealized forward positions to cash at settlement. Unrealized gains and losses include the change in fair value of open contracts as well as the ineffective portion of our cash flow hedges. The increase in realized revenue is mostly due to amortization of prepayments for power at our Deer Park facility (see “Power Agreements” in Note 29 of the Notes to Consolidated Financial Statements). The increase in unrealized loss is due primarily to undesignated gas positions.


	2005		2004		$ Change		% Change

Other revenue	$	143.0	$	73.3	$	69.7		95.1%

Other revenue increased due primarily to higher revenues at PSM associated with sales of gas turbine components and at TTS for gas turbine maintenance services and the sale of spare turbine parts and components. Additionally in 2005 we recognized higher construction and O&M services contract revenue.


	*Cost of Revenue*


	2005		2004		$ Change			% Change

Cost of revenue	$	12,057.6	$	8,268.4	$	(3,789.2	)		(45.8)%

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


	2005		2004		$ Change		% Change

Plant operating expense	$	717.4	$	727.9	$	10.5		1.4%

Plant operating expense decreased even though four new baseload power plants and one expansion project were completed during 2005 due primarily to lower charges for equipment repair costs in 2005.


	2005		2004		$ Change			% Change

Royalty expense	$	36.9	$	28.4	$	(8.5	)		(29.9)%

Approximately 67% of the royalty expense for 2005 vs. 77% for 2004 is attributable to royalties paid to geothermal property owners at The Geysers, mostly as a percentage of geothermal electricity revenues. The increase in royalty expense in 2005 was due primarily to a $5.4 increase in the accrual of contingent purchase price payments to the previous owners of the Texas City and Clear Lake Power Plants based on a percentage of gross revenues at these two plants, and the remainder was due to an increase in royalties at The Geysers.


	2005		2004		$ Change			% Change

Transmission purchase expense	$	87.6	$	74.8	$	(12.8	)		(17.1)%

In many cases, we incur transmission costs that result from serving the accounts of our customers. This is especially true in the case of many of our retail contracts. When we incur transmission expenses on behalf of our customers we recognize these amounts as a component of transmission purchase expense. Transmission purchase expenses increased for the year ended December 31, 2005, as compared to the same period in 2004 as a result of additional power plants becoming operational in mid-2004 as well as transmission expense related to transmission rights acquired between the ERCOT and SPP electricity markets.


	2005		2004		$ Change			% Change

Purchased power and gas expense for hedging and optimization	$	3,417.2	$	3,198.7	$	(218.5	)		(6.8)%

Purchased power and gas expense for hedging and optimization increased during 2005 due primarily to higher gas volumes and higher prices for gas in 2005.


	2005		2004		$ Change			% Change

Fuel expense	$	4,623.3	$	3,587.4	$	(1,035.9	)		(28.9)%

Fuel expense increased during 2005, as compared to the same period in 2004 due primarily to higher natural gas prices and the sale of natural gas assets (which required us to purchase more from third parties) and an increase of 4.8% in generation due largely to the addition of four baseload power facilities and one expansion project to our consolidated operating portfolio in 2005. Our average fuel expense before the effects of hedging, balancing and optimization increased by 24.4% from $6.27/ MMBtu for the year ended December 31, 2004 to $7.80/ MMBtu for the same period in 2005.


	2005		2004		$ Change			% Change

Depreciation and amortization expense	$	506.4	$	446.0	$	(60.4	)		(13.5)%

Depreciation and amortization expense increased in 2005 primarily due to additional power plants achieving commercial operation subsequent to 2004.


	2005		2004		$ Change			% Change

Operating Plant Impairments	$	2,412.6	$	—	$	(2,412.6	)		— %

See Note 6 of the Notes to Consolidated Financial Statements for a discussion of the 2005 impairment charges.


	2005		2004		$ Change		% Change

Operating lease expense	$	104.7	$	105.9	$	1.2		1.1%

Operating lease expense decreased slightly during 2005 as the reduction in operating lease expense due to the reclassification of the King City lease from operating lease to capital lease was partially offset by higher contingent rent accruals on the Watsonville lease.


	2005		2004		$ Change			% Change

Other cost of revenue	$	151.5	$	99.3	$	(52.2	)		(52.6)%

Other cost of revenue increased during 2005 as compared to 2004 primarily due to higher cost of revenue at PSM and TTS and on construction and O&M services contracts.


	*(Income)/ Expense*


	2005			2004		$ Change		% Change

(Income) loss from unconsolidated investments in power projects and oil and gas properties	$	(12.1	)	$	14.1	$	26.2		185.8%

The more favorable 2005 results were primarily due to an increase in income (due mostly to lower major maintenance costs and decreased LTSA costs), from the Acadia PP investment prior to its consolidation in the latter part of 2005, and the non-recurrence of losses recorded in 2004 from our investment in the AELLC power plant. We ceased to recognize our share of the operating results of AELLC as we began to account for our investment in AELLC using the cost method following loss of effective control when AELLC filed for bankruptcy protection in November 2004. In September 2004 prior to AELLC filing for bankruptcy protection, we recognized our share of an adverse jury award related to a dispute with IP. Our share of that expense was $11.6.


	2005		2004		$ Change			% Change

Equipment, development project and other impairments	$	2,117.7	$	46.9	$	(2,070.8	)		(4,415.4)%

See Note 6 of the Notes to Consolidated Financial Statements for a discussion of the 2005 impairment charges related to equipment, project development and other assets. The 2004 impairment charges primarily resulted from cancellation costs of six heat recovery steam generators and component part orders and related component part impairments.


	2005		2004		$ Change			% Change

Long-term service agreement cancellation charge	$	34.1	$	7.7	$	(26.4	)		(342.9)%

During the year ended December 31, 2005, we recorded charges of $34.1 related to the cancellation of nine LTSAs with GE. In 2004 we recorded charges of $7.7 related to the cancellation of four LTSAs with Siemens-Westinghouse.


	2005		2004		$ Change			% Change

Project development expense	$	27.6	$	19.9	$	(7.7	)		(38.7)%

Project development expense increased by $8.5 during 2005 primarily due to higher preservation activity costs on suspended construction projects.


	2005		2004		$ Change			% Change

Research and development expense	$	19.2	$	18.4	$	(0.8	)		(4.3)%

Research and development expense was relatively flat in 2005 as compared to 2004 and relates to personnel expenses and consulting fees associated with new research and development programs and testing at PSM.


	2005		2004		$ Change			% Change

Sales, general and administrative expense	$	239.9	$	220.6	$	(19.3	)		(8.7)%

Sales, general and administrative expense increased in 2005 due primarily to an increase in legal fees related to an increase in litigation matters.


	2005		2004		$ Change			% Change

Interest expense	$	1,397.3	$	1,095.4	$	(301.9	)		(27.6)%

Interest expense increased primarily as a result of higher average interest rates and lower capitalization of interest expense. Our average interest rate increased from 8.4% for the year ended December 31, 2004, to 9.4% for the year ended December 31, 2005, primarily due to the impact of rising U.S. interest rates and their effect on our existing variable rate debt portfolio and higher average interest rates incurred on new debt instruments that were entered into to replace and/or refinance existing debt instruments during 2005. Interest capitalized decreased from $376.1 for the year ended December 31, 2004, to $196.1 for the year ended December 31, 2005, as new plants entered commercial operations (at which point capitalization of interest expense ceases) and because of suspended capitalization of interest on three partially completed construction projects.


	2005			2004			$ Change		% Change

Interest (income)	$	(84.2	)	$	(54.8	)	$	29.4		53.6%

Interest (income) increased during the year ended December 31, 2005, due primarily to higher interest earned on restricted cash as well as margin deposits and collateral posted to secure letters of credit and due to higher interest rates.


	2005		2004		$ Change			% Change

Minority interest expense	$	42.5	$	34.7	$	(7.8	)		(22.5)%

Minority interest expense increased during the year ended December 31, 2005, as compared to the same period in 2004 primarily due to an increase in income at CPLP prior to its deconsolidation, which is 70% owned by CPIF, and was largely caused by an increase in steam revenue at the Island Cogen plant which was driven by higher gas prices; the price of gas is a component of the steam revenue calculation.


	2005			2004			$ Change			% Change

(Income) from the repurchase of various issuances of debt	$	(203.3	)	$	(246.9	)	$	(43.6	)		(17.7)%

The decrease in income from repurchase of debt is due to considerably higher volumes of convertible Senior Notes repurchased during the year ended December 31, 2004, compared to the same period in 2005.


	2005		2004			$ Change			% Change

Other (income)/expense, net	$	72.4	$	(121.1	)	$	(193.5	)		(159.8)%

Other (income)/expense was less favorable for the year ended December 31, 2005, by $193.5 as compared with the same period in 2004. This was due mostly to non-recurrence of income that was recognized in 2004 (primarily $187.5 of income from the restructuring and sale of PPAs at two of our New Jersey plants and the restructuring of a gas contract at our Auburndale plant). There were also increased expenses in 2005 ($18.5 for an impairment charge for the Gray’s Ferry investment and $8.3 for letter of credit fees), offset by reduced foreign currency losses of $26.9.


	2005		2004		$ Change			% Change

Reorganization items	$	5,026.5	$	—	$	(5,026.5	)		— %

Reorganization items represent the direct and incremental costs of the bankruptcy cases, such as professional fees, pre-petition liability claim adjustments and losses that are probable and can be estimated

related to terminated contracts. In the fourth quarter of 2005 we recognized the following expenses as reorganization items:


		December 31, 2005

Provision for allowable claims		$	3,791.5
Impairment of investment in Canadian subsidiaries			879.1
Write-off of unamortized deferred financing costs and debt discounts			148.1
Loss on terminated contracts, net			139.4
Professional fees			36.4
Other reorganization items			32.0

	Total reorganization items	$	5,026.5

We determined it was necessary to deconsolidate most of our Canadian and other foreign entities due to our loss of control over these entities upon the filing by the Canadian Debtors for protection under the CCAA in Canada. These Canadian Debtor entities are not under the jurisdiction of the U.S. Bankruptcy Court and are separately administered under the CCAA by the Canadian Court. In conjunction with the deconsolidation, we reviewed all intercompany guarantees. We identified guarantees by U.S. parent entities of debt (and accrued interest payable) of approximately $5,026.5 issued by entities in the Canadian debtor chains as constituting probable allowable claims against the U.S. parent entities. Some of the guarantee exposures are redundant, such as the Calpine Corporation guarantee to ULC I security holders and the Calpine Corporation guarantee of QCH’s subscription agreement obligations associated with the hybrid notes structure in support of the ULC I Unsecured Notes. Under the guidance of SOP 90-7 “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code,” we determined the duplicative guarantees were probable of being allowed into the claim pool by the U.S. Bankruptcy Court. We accrued an additional amount of approximately $3,791.5 as reorganization items related to these duplicative guarantees.

As a result of the deconsolidation, we adopted the cost method of accounting for our investment in our Canadian and other foreign entities. Upon adoption of the cost method, we evaluated our investment balances and intercompany notes receivable from these entities for impairment. We determined that our entire investment in these entities had experienced other-than-temporary decline in value and was impaired. We also concluded that all intercompany notes receivable balances from these entities were uncollectible, as the notes were unsecured and protected by the automatic stay under the CCAA. Consequently, we fully impaired this investment and receivable assets at December 31, 2005, resulting in an $879.1 charge to reorganization items.

Deferred financing costs and debt discounts relate to our unsecured or under-secured pre-petition debt, which has been reclassified on the balance sheet to Liabilities Subject to Compromise following our bankruptcy filings on December 20, 2005, and were written-off to reorganization items as these capitalized costs were determined to have no future value.

Calpine Debtors recorded a loss on certain commodity contracts that were terminated by the counterparties to such contracts after our bankruptcy filings, in accordance with their claim that our bankruptcy filings constituted an event of default under the terms of those contracts. We recorded the fair value of those commodity contracts on the date of termination as a reorganization item. Calpine Debtors also have some commodity contracts that meet the accounting definition of a derivative, but we have elected to account for them under the normal purchase and sale exemption under the derivative accounting rules. If a normal contract is terminated, we may no longer be able to assert probability of physical delivery over the contract term, and therefore, such contract will no longer be eligible for the normal purchase and sale exemption. Once we lose our ability to continue normal purchase and sale treatment, we must record the fair value of such contracts in our balance sheet with the related offset to earnings. No amounts have been recorded as of December 31, 2005, for normal contracts for which we have filed motions to reject, as such motions are pending final approval or denial by the courts and regulators.

Professional fees relate primarily to expenses incurred to secure the DIP Facility and the fees of attorneys and consultants working directly on the bankruptcy filings and our plan of reorganization.

Other reorganization items consist primarily of non-cash charges related to certain interest rate swaps that no longer meet the hedge effectiveness criteria under SFAS No. 133 as a result of our payment default or expected payment default on the underlying debt instruments due to the bankruptcy filing.


	2005			2004			$ Change		% Change

Provision (benefit) for income taxes	$	(741.4	)	$	(235.3	)	$	506.1		215.1%

During the year ended December 31, 2005, our pre-tax loss increased by $9,967.3 and our tax benefit increased by $506.1 as compared to the benefit in the year ended December 31, 2004. The pre-tax loss increase resulted from the approximately $4,530.3 of impairment charges and approximately $5,026.5 of reorganization item charges recorded in the fourth quarter of 2005 as a result of our bankruptcy filing. The effective tax rate decreased to 7.0% in 2005 compared to 35.9% in the same period in 2004 primarily due to the recording of valuation allowances against deferred tax assets. The tax rates on continuing operations for the year ended December 31, 2005 reflect the reclassification to discontinued operations of certain tax expense related to the sale of the natural gas business, and the Saltend, and the Morris and Ontelaunee power plants. See Note 13 of the Notes to Consolidated Condensed Financial Statements for further information on discontinued operations.


	2005			2004		$ Change			% Change

Discontinued operations, net of tax	$	(58.2	)	$	177.2	$	(235.4	)		(132.8	)%

During the year ended December 31, 2005, discontinued operations activity primarily consisted of the pre-tax gain on the sale of Saltend of $22.2 and the pre-tax gain on the sale of substantially all of our remaining oil and gas assets of $340.1. Both dispositions closed in July 2005. Offsetting these gains were pre-tax losses of $136.8 related to the sale of Ontelaunee, and $106.2 related to the sale of Morris. On a pre-tax basis, we recorded income from discontinued operations for the year ended December 31, 2005 of $73.5. Our effective tax rate on discontinued operations for the year ended December 31, 2005, however, was 179% due primarily to the tax provision on the gains from the sale of Saltend and the oil and gas assets partially offset by the Morris loss. Additionally, no tax benefit was recognized on the Ontelaunee loss due to the valuation allowance established. As a consequence, we recorded an after-tax loss from discontinued operations of $58.3. Discontinued operations for the year ended December 31, 2004, net of tax, was $177.2 and consisted primarily of a pre-tax gain of $208.2 from the sale of our Canadian and U.S. Rocky Mountain oil and gas assets.


	*Net Income (Loss)*


	2005			2004			$ Change			% Change

Net income (loss)	$	(9,939.2	)	$	(242.5	)	$	(9,696.7	)		(3,998.6)%

In 2005 we experienced an increase in the loss from operations as we continued to see a drop in baseload capacity factor compared to 2004, and although total realized spark spread increased by $214.1, our ownership costs went up at a faster rate as new plants entered commercial operation; depreciation expense increased by $60.4, and interest expense increased by $301.9 as we capitalized less interest expense and experienced an increase in our average borrowing rate. Additionally, in 2005 we recorded material impairment charges totaling $4,530.3 on power plants in development, construction and operations and reorganization item charges totaling $5,026.5 related to our bankruptcy filing.


	*Results of Operations*


	Year Ended December 31, 2004, Compared to Year Ended December 31, 2003


	*Revenue*


	2004		2003		$ Change		% Change

Total revenue	$	8,648.4	$	8,421.2	$	227.2		2.7%

The increase in total revenue is explained by category below.


	2004		2003		$ Change		% Change

Electricity and steam revenue	$	5,165.3	$	4,291.2	$	874.1		20.4%

E&S revenue increased as we completed construction and brought into operation five new baseload power plants and two project expansions in 2004. Average MW in operation of our consolidated plants increased by 21.4% to 22,198 MW while generation increased by 17.7%. The increase in generation lagged behind the increase in average MW in operation as our baseload capacity factor dropped to 48.5% in 2004 from 50.9% in 2003, primarily due to the increased occurrence of unattractive off-peak market spark spreads in certain areas due in part to mild weather, which caused us to cycle off certain of our merchants plants without contracts in off peak hours, and also due to oversupply conditions in those markets. Average realized electricity prices, before the effects of hedging, balancing and optimization, increased to $61.93/ MWh in 2004 from $60.56/MWh in 2003.


	2004		2003		$ Change		% Change

Transmission sales revenue	$	20.0	$	15.3	$	4.7		30.7%

Transmission sales revenue increased in 2004 due to the increased emphasis on optimizing our portfolio through the resale of our underutilized transmission positions in the short- to mid-term markets.


	2004		2003		$ Change			% Change

Sales of purchased power and gas for hedging and optimization	$	3,376.3	$	4,033.2	$	(656.9	)		(16.3)%

Sales of purchased power and gas for hedging and optimization decreased during 2004 due primarily to netting of sales of purchased power with purchased power expense which reduced sales of purchased power by approximately $1,676.0 in 2004 compared to $256.6 in 2003 (netting in 2003 occurred only in the fourth quarter) in connection with the adoption of EITF Issue No. 03-11 on a prospective basis in the fourth quarter of 2003. This was partly offset by higher volumes and higher realized prices on both power and gas hedging, balancing and optimization activities.


		2004			2003			$ Change		% Change

Realized gain on power and gas mark-to-market transactions, net		$	48.1		$	24.3		$	23.8		97.9	%
Unrealized (loss) on power and gas mark-to-market transactions, net			(34.7	)		(50.7	)		16.0		31.6	%

	Mark-to-market activities, net	$	13.4		$	(26.4	)	$	39.8		150.8	%

During 2004, we recognized a net gain from mark-to-market activities compared to net losses in 2003. In 2004 our exposure to mark-to-market earnings volatility declined commensurate with a corresponding decline in the volume of open commodity positions underlying the exposure. As a result, the magnitude of earnings volatility attributable to changes in prices declined. We recorded a hedge ineffectiveness gain of approximately $7.6 in 2004 versus a hedge ineffectiveness loss of $1.8 for the corresponding period in 2003. Additionally, during 2004 we recorded a gain of $9.2 on a mark-to-market derivative contract that was terminated during 2004 versus a mark-to-market loss of $15.5 on the same contract in 2003.


	2004		2003		$ Change			% Change

Other revenue	$	73.3	$	107.9	$	(34.6	)		(32.1)%

Other revenue decreased during 2004 primarily due to a one-time pre-tax gain of $67.3 realized during 2003 in connection with our settlement with Enron, principally related to the final negotiated settlement of claims and amounts owed under terminated commodity contracts. This was partially offset by increases of

$13.3 and $12.0 from combustion turbine parts sales and repair and maintenance services performed by TTS and construction management and operating services performed by CPSI, respectively.


	*Cost of Revenue*


	2004		2003		$ Change			% Change

Cost of revenue	$	8,268.4	$	7,814.3	$	(454.1	)		(5.8)%

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


	2004		2003		$ Change			% Change

Plant operating expense	$	727.9	$	599.3	$	(128.6	)		(21.5)%

Plant operating expense increased as five new baseload power plants and two expansion projects were completed during 2004, and due to higher major maintenance expense on existing plants as many of our newer power plants performed their initial major maintenance work. In North America, 25 of our gas-fired plants performed major maintenance work, an increase of 67% over the number of plants that did so in 2003. In addition, during 2004 we incurred $54.3 for equipment failure costs compared to $11.0 in 2003.


	2004		2003		$ Change			% Change

Royalty expense	$	28.4	$	24.6	$	(3.8	)		(15.4)%

Approximately 77% of the royalty expense for 2004 vs. 78% for 2003 is attributable to royalties paid to geothermal property owners at The Geysers, mostly as a percentage of geothermal electricity revenues. The increase in royalty expense in 2004 was due primarily to a $2.5 increase in royalties at The Geysers, and the remainder was due to an increase in the accrual of contingent purchase price payments to the previous owners of the Texas City and Clear Lake Power Plants based on a percentage of gross revenues at these two plants.


	2004		2003		$ Change			% Change

Transmission purchase expense	$	74.8	$	34.7	$	(40.1	)		(115.6)%

Transmission purchase expense increased primarily due to additional power plants achieving commercial operation in 2004.


	2004		2003		$ Change		% Change

Purchased power and gas expense for hedging and optimization	$	3,198.7	$	3,962.6	$	763.9		19.3%

Purchased power and gas expense for hedging and optimization decreased during 2004 as compared to 2003 due primarily to netting of purchased power expense against sales of purchased power which decreased purchased power expense by approximately $1,676.0 in 2004 compared to a decrease of $256.6 in 2003, in connection with the adoption on a prospective basis of EITF Issue No. 03-11 in the fourth quarter of 2003. This was partly offset by higher volumes and higher realized prices on both power and gas hedging, balancing and optimization activities.


	2004		2003		$ Change			% Change

Fuel expense	$	3,587.4	$	2,636.7	$	(950.7	)		(36.1)%

Cost of oil and gas burned by power plants increased during 2004 as compared to 2003 due to an 18.1% increase in gas consumption as we increased our MW production and due to higher prices for gas.


	2004		2003		$ Change			% Change

Depreciation and amortization expense	$	446.0	$	382.0	$	(64.0	)		(16.8)%

Depreciation and amortization expense increased in 2004 primarily due to additional power plants achieving commercial operation during or subsequent to 2003.


	2004		2003		$ Change		% Change

Operating lease expense	$	105.9	$	112.1	$	6.2		5.5%

Operating lease expense decreased during 2004 as compared to 2003 primarily because the King City lease terms were restructured, and the lease began to be accounted for as a capital lease. As a result, we ceased incurring operating lease expense on that lease and instead began to incur depreciation and interest expense.


	2004		2003		$ Change			% Change

Other cost of revenue	$	99.3	$	62.3	$	(37.0	)		(59.4)%

Other cost of revenue increased during 2004 as compared to 2003 primarily due to $29.0 of amortization expense in 2004 versus $10.6 in 2003 incurred from the adoption of DIG Issue No. C20. In the fourth quarter of 2003, we recorded a pre-tax mark-to-market gain of $293.4 as a cumulative effect of a change in accounting principle. This gain is amortized as expense over the respective lives of the two power sales contracts from which the mark-to-market gains arose. We also incurred $11.3 of additional expense from TTS in 2004, as the entity had a full year of activity (we acquired TTS in late February of 2003). Additionally, CPSI cost of revenue increased $10.8 in 2004 compared to 2003 due to an increase in services contract activity.


	*(Income)/ Expense*


	2004		2003			$ Change			% Change

(Income) loss from unconsolidated investments in power projects and oil and gas properties	$	14.1	$	(75.7	)	$	(89.8	)		(118.6)%

The unfavorable change was primarily due to a non-recurring $52.8 gain in 2003, representing our 50% share, on the termination of the tolling arrangement with AMS at the Acadia Energy Center and a loss of $11.6 realized in 2004, representing our share of a jury award to IP in a litigation relating to AELLC together with a $5.0 impairment charge recorded when Androscoggin filed for bankruptcy protection in the fourth quarter of 2004. Also, we did not have any income on our Gordonsville investment in 2004, compared to $12.0 in 2003, as we sold our interest in this facility in November 2003.


	2004		2003		$ Change		% Change

Equipment, development projects and other impairment cost	$	46.9	$	68.0	$	21.1		31.0%

In 2004, the pre-tax equipment cancellation and impairment charge was primarily a result of charges of $33.7 related to cancellation costs of six HRSG orders and HRSG component parts cancellations and impairments. In 2003 the pre-tax equipment cancellation and impairment charge was primarily a result of cancellation costs related to three turbines and three HRSGs and impairment charges related to four turbines.


	2004		2003		$ Change		% Change

Long-term service agreement cancellation charge	$	7.7	$	16.3	$	8.6		52.8%

LTSA cancellation charges decreased primarily due to $14.1 in cancellation costs incurred in 2003 associated with LTSAs with General Electric related to our Rumford, Tiverton and Westbrook facilities. In 2004 the decrease was offset by a $7.7 adjustment as a result of settlement negotiations related to the cancellation of LTSAs with Siemens-Westinghouse at our Hermiston, Ontelaunee, South Point and Sutter facilities and a $3.8 adjustment as a result of LTSA cancellation settlement negotiations with General Electric regarding cancellation charges at our Los Medanos facility.


	2004		2003		$ Change			% Change

Project development expense	$	19.9	$	18.2	$	(1.7	)		(9.3)%

Project development expense decreased during 2004 primarily due to lower new development activity.


	2004		2003		$ Change			% Change

Research and development expense	$	18.4	$	10.6	$	(7.8	)		(73.6)%

Research and development expense increased in 2004 as compared to 2003 primarily due to increased personnel expense related to gas turbine component research and development programs at our PSM subsidiary.


	2004		2003		$ Change			% Change

Sales, general and administrative expense	$	220.6	$	204.1	$	(16.5	)		(8.1)%

Sales, general and administrative expense increased in 2004 due primarily to an increase of $20.4 of Sarbanes-Oxley 404 internal control project costs.


	2004		2003		$ Change			% Change

Interest expense	$	1,095.4	$	695.5	$	(399.9	)		(57.5)%

Interest expense increased as a result of higher average debt balances, higher average interest rates and lower capitalization of interest expense. Interest capitalized decreased from $412.2 in 2003 to $375.3 in 2004 as a result of new plants that entered commercial operations (at which point capitalization of interest expense ceases). We expect that the amount of interest capitalized will continue to decrease in future periods as our plants in construction are completed. Interest expense related to our CalGen financing was responsible for an increase of $113.7, and interest expense related to our preferred interests increased $28.7. The majority of the remaining increase relates to an increase in average indebtedness due primarily to the deconsolidation of the Calpine Capital Trusts which had issued the HIGH TIDES I, II and III, and recording of debt to the Calpine Capital Trusts due to the adoption of FIN 46, “Consolidation of Variable Interest Entities, an interpretation of ARB 51” prospectively on October 1, 2003. See Note 2 of the Notes to Consolidated Financial Statements for a discussion of our adoption of FIN 46. Interest expense related to the notes payable to the Calpine Capital Trusts during 2004 was $58.6. The distributions were excluded from the interest expense caption on our Consolidated Statements of Operations through the nine months ended September 30, 2003, while $15.1 of interest expense related to the Calpine Capital Trusts was recorded for the quarter ending December 31, 2003. The HIGH TIDES I and II and the related convertible debentures payable to the Calpine Capital Trusts were redeemed in October 2004.


	2004		2003		$ Change		% Change

Distributions on trust preferred securities	$	—	$	46.6	$	46.6		100.0%

As a result of the deconsolidation of the Calpine Capital Trusts upon adoption of FIN 46 as of October 1, 2003, the distributions paid on the HIGH TIDES I, II and III during 2004 were no longer recorded on our books and were replaced prospectively by interest expense on our debt to the Trusts.


	2004			2003			$ Change		% Change

Interest (income)	$	(54.8	)	$	(39.2	)	$	15.6		39.8%

The increase in interest (income) in 2004 is due to an increase in cash and cash equivalents and restricted cash balances during the year. Additionally, we generated interest income on the repurchases of our HIGH TIDES I, II and III. For further information, see Note 5 of the Notes to Consolidated Financial Statements.


	2004		2003		$ Change			% Change

Minority interest expense	$	34.7	$	27.3	$	(7.4	)		(27.1)%

Minority interest expense increased during 2004 as compared to 2003 due to our reduced ownership percentage in CPLP following the sale of our interest in CPIF, which owns 70% of CPLP. Our 30% interest is subordinate to CPIF’s interest.


	2004			2003			$ Change			% Change

(Income) from the repurchase of various issuances of debt	$	(246.9	)	$	(278.6	)	$	(31.7	)		(11.4)%

Income from repurchases of various issuances of debt during 2004 decreased by $31.7 from the corresponding period primarily as a result of lower face amounts of debt repurchased in open market and privately negotiated transactions.


	2004			2003			$ Change		% Change

Other (income), net	$	(121.1	)	$	(46.6	)	$	74.5		159.9%

Other income increased in 2004 as compared to 2003 primarily due to (a) pre-tax income in 2004 in the amount of $171.5 associated with the restructuring of PPAs for our Newark and Parlin power plants and the sale of Utility Contract Funding II, LLC, net of transaction costs and the write-off of unamortized deferred financing costs, (b) $16.4 pre-tax gain from the restructuring of a long-term gas supply contract net of transaction costs and (c) $12.3 pre-tax gain from the King City restructuring transaction related to the sale of our debt securities that had served as collateral under the King City lease, net of transaction costs. In addition, during 2004, foreign currency transaction losses totaled $41.6, compared to losses of $34.5 in the corresponding period in 2003.

In 2003, we recorded a gain of $62.2 on the sale of oil and gas properties and a gain of $57.0 from a contract termination of the RockGen facility.


	2004			2003			$ Change		% Change

Provision (benefit) for income taxes	$	(235.3	)	$	(26.4	)	$	208.9		791.3%

For 2004, the effective rate was 35.9% as compared to 66.6% for 2003. This effective rate variance is due to the inclusion of certain permanent items in the calculation of the effective rate, which are fixed in amount and have a significant effect on the effective tax rates depending on the materiality of such items to taxable income.


	2004		2003		$ Change		% Change

Discontinued operations, net of tax	$	177.2	$	114.4	$	62.8		54.9%

The 2004 discontinued operations activity includes the reclassification to discontinued operations of operating results related to the commitments to plans of divestiture of our remaining oil and gas assets in the U.S. and of our Saltend, Ontelaunee and Morris power facilities, the effects of the 2004 sale of our 50% interest in the Lost Pines 1 Power Project, the 2004 sale of the oil and gas reserves in the Colorado Piceance Basin and New Mexico San Juan Basin and the remaining natural gas reserves and petroleum assets in Canada, all of which resulted in a gain on sale, pre-tax, of $243.5. The 2003 discontinued operations activity includes the operational reclassification to discontinued operations related to the 2005 commitment to a plan of divestiture of the assets listed above, the 2004 sales of oil and gas assets in the U.S. and Canada, the 2004 sale of our 50% of interest in the Lost Pines 1 Power Project, and the 2003 sale of our specialty data center engineering business. For more information about discontinued operations, see Note 13 of the Notes to Consolidated Financial Statements.


	2004		2003		$ Change			% Change

Cumulative effect of a change in accounting principle, net of tax	$	—	$	180.9	$	(180.9	)		(100.0)%

The 2003 gain from the cumulative effect of a change in accounting principle included three items: (1) a gain of $181.9, net of tax effect, from the adoption of DIG Issue No. C20; (2) a loss of $1.5 associated with the adoption of FIN 46-R, and the deconsolidation of the Trusts which issued the HIGH TIDES. The loss of $1.5 represents the reversal of a gain, net of tax effect, recognized prior to the adoption of FIN 46-R on our repurchase of $37.5 of the value of certain HIGH TIDES by issuing shares of our common stock valued at $35.0; and (3) a gain of $0.5, net of tax effect, from the adoption of SFAS No. 143 “Accounting for Asset Retirement Obligations”.


	*Net Income (Loss)*


	2004			2003		$ Change			% Change

Net income (loss)	$	(242.5	)	$	282.0	$	(524.5	)		(186.0)%


	*Liquidity and Capital Resources*

Currently, we are operating our business as debtors-in-possession under the jurisdiction of the Bankruptcy Courts. 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 applicable Bankruptcy Court. Accordingly, the matters described in this section may be significantly affected by our bankruptcy, the other factors described in “Forward-Looking Statements” and the risk factors included in Item 1A. “Risk Factors.”

Ultimately, whether we will have sufficient liquidity from cash flow from operations and borrowings available under our DIP Financing sufficient to fund our operations, including anticipated capital expenditures and working capital requirements, as well as satisfy our current obligations under our outstanding indebtedness while we remain in bankruptcy will depend, to some extent, on whether our business plan is successful, including whether we are able to realize expected cost savings from implementing that plan, as well as the other factors noted in “Forward-Looking Statements” and Item 1A. “Risk Factors.” On December 31, 2005, our liquidity totaled approximately $2.2 billion. This includes the immediately available portion of cash and cash equivalents on hand of $0.2 billion and approximately $1.975 billion of borrowing capacity under our DIP Facility (based on the full amount of the facility as amended and restated on February 23, 2006).

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


	Bankruptcy Proceedings and Financing Activities

Our business is capital intensive. Our ability to successfully reorganize and emerge from bankruptcy protection, while continuing to operate our current fleet of power plants, including completing our remaining plants under construction and maintaining our relationships with vendors, suppliers, customers and others with whom we conduct or seek to conduct business, is dependent on the continued availability of capital on attractive terms. As described below, we have entered into, and obtained U.S. Bankruptcy Court approval of, a $2 billion DIP Facility which we believe will be sufficient to support our operations for the anticipated duration of our bankruptcy cases. In addition, we have obtained U.S. Bankruptcy Court approval of several other matters that we believe are important to maintaining our ability to operate in the ordinary course during our bankruptcy cases, including (i) our cash management program (as described below), (ii) payments to our employees, vendors and suppliers necessary in order to keep our facilities operational and (iii) procedures for the rejection of certain leases and executory contracts. In order to improve our liquidity position, we also expect to continue our efforts to reduce overhead and discontinue activities without compelling profit potential, particularly in the near term. In addition, development activities will continue to be further reduced, and we expect that certain power plants or other of our assets will be sold (or that we will surrender certain leased power plants to the lessors of such plants), and that commercial operations may be suspended at certain of our power plants during our reorganization effort.

Prior to our bankruptcy filing, we obtained cash from our operations; borrowings under credit facilities; issuances of debt, equity, trust preferred securities and convertible debentures and contingent convertible notes; proceeds from sale/leaseback transactions; sale or partial sale of certain assets; contract monetizations; and project financings. We utilized this cash to fund our operations, service or prepay debt obligations, fund acquisitions, develop and construct power generation facilities, finance capital expenditures, support our hedging, balancing and optimization activities, and meet our other cash and liquidity needs. We reinvested any cash from operations into our business development and construction program or used it to reduce debt, rather than to pay cash dividends. Our outstanding debt obligations, including our DIP Facility, are summarized below under “ — Contractual Obligations.” In general, we continue to pay current interest on the first priority and other fully secured debt of the Calpine Debtors, to make periodic cash payments through June 30, 2006, to the second priority secured debt of the Calpine Debtors and to make payments of interest or principal, as applicable, on the debt of our subsidiaries that have not filed for bankruptcy protection. However, we do not currently pay interest or make other debt service payments on the unsecured debt of the Calpine Debtors which has resulted in a reduction of our cash outflow related to debt service of approximately $17.9 million of unpaid contractual interest. No principal payments were due in the ten-day period between our bankruptcy filing and December 31, 2005. Annual contractual interest expense related to LSTC is expected to be approximately $650 million. As discussed in Item 1. “Business — Strategy” we have initiated a comprehensive program designed to stabilize, improve and strengthen our core power generation business and our financial health by reducing activities and curtailing expenditures in certain non-core areas and business units. As part of this program, we have begun to implement staff reductions of approximately 1,100 positions, or over one third of our workforce which is expected to be completed by the end of 2006. We expect that the staff reductions, together with non-core office closures and reductions in controllable overhead costs, will reduce annual operating costs by approximately $150 million, significantly improving the Company’s financial and liquidity positions.

DIP Facility. On December 22, 2005, we 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 Corporation is the borrower under the DIP Facility, which is guaranteed by all of the other U.S. Debtors. The U.S. Bankruptcy Court granted interim approval of the DIP Facility on December 21, 2005, but initially limited our access under the DIP Facility to $500 million under the revolving credit facility. On January 26, 2006, the Bankruptcy Court entered a final order approving the DIP Facility and removing the limitation on our 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. 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 U.S. Debtors, including The Geysers, 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.

Pursuant to the DIP Facility, we are subject to a number of affirmative and restrictive covenants, reporting requirements and financial covenants. We were in compliance with the DIP Facility covenants (or had received extensions or affirmative waivers of compliance where compliance was not attained), as of each of December 31, 2005, and the date of filing of this Report with the SEC. In particular, the DIP Facility was amended on May 3, 2006, to, among other things, provide us with extensions of time (i) to provide certain financial information to the DIP Facility lenders, including financial statements for the year ended December 31, 2005 (which are included in this Report), and for the quarter ended March 31, 2006 and (ii) to cause Geysers Power Company to file for protection under Chapter 11 of the Bankruptcy Code.

In connection with and as a condition to closing the DIP Facility, on February 3, 2006, our subsidiary GPC acquired ownership of The Geysers, which had previously been leased by GPC from Geysers Statutory Trust (which is not an affiliate of ours) pursuant to a leveraged lease. The purchase price for The Geysers was approximately $157.6 million, plus certain costs and expenses. Immediately following the acquisition, we redeemed certain notes issued by Geysers Statutory Trust in connection with the leveraged lease structure at a

cost of approximately $109.3 million. As noted above, The Geysers were then pledged as part of the collateral securing the DIP Facility.

Cash Management. We have received U.S. Bankruptcy Court approval to continue to manage our cash in accordance with our pre-existing intercompany cash management system during the pendency of the Chapter 11 cases. This program allows us to maintain our existing bank and other investment accounts and to continue to manage our cash on an integrated basis through Calpine Corporation. Such cash management systems are subject to the requirements of the DIP Facility and Cash Collateral Order. Pursuant to the cash management system, and in accordance with our cash collateral requirements in connection with the DIP Facility and relevant U.S. Bankruptcy Court orders, intercompany transfers are generally recorded as intercompany loans. Upon the closing of the DIP Facility, the cash balances of the United States 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 cash of the U.S. Debtors and certain other subsidiaries be maintained in a concentration account at Deutsche Bank upon the DIP Facility agents.

Expedited Procedures for the Rejection of Executory Contracts and Unexpired Leases. On December 21, 2005, the U.S. Bankruptcy Court approved expedited procedures for the rejection of executory contracts and unexpired leases of personal and non-residential real property. In general, unless otherwise agreed by the parties or approved by the U.S. Bankruptcy Court, interested parties have ten days after we have filed a notice seeking to reject a lease or executory contract to file objections. If no objections are filed, the lease or executory contract will be rejected. If an objection is filed, a hearing will be conducted by the Bankruptcy Court to determine whether or not to approve the rejection and any other matters raised by the objection. In accordance with these procedures, we are seeking to reject certain facility leases, including the leases for the Tiverton and Rumford power plants, as described in Item 1. “Business — Recent Developments.”

In addition, on December 21, 2005, we filed a motion with the U.S. Bankruptcy Court to reject eight PPAs and to enjoin FERC from asserting jurisdiction over the rejections. The U.S. Bankruptcy Court issued a temporary restraining order against FERC and set the matter for a hearing on January 5, 2006. Under most of the PPAs sought to be rejected, we are obligated to sell power at prices that are significantly lower than currently-prevailing market prices. At the time of filing the motion, we forecasted that it would cost us in excess of $1.2 billion if we were required to continue to perform under these PPAs rather than to sell the contracted energy at current market prices. On December 29, 2005, certain counterparties to the various PPAs filed an action in the SDNY Court arguing that the U.S. Bankruptcy Court did not have jurisdiction over the dispute. On January 5, 2006, the SDNY Court entered an order that had the effect of transferring our motion seeking to reject the eight PPAs and our related request for an injunction against FERC to the SDNY Court from the U.S. Bankruptcy Court. Earlier, however, on December 19, 2005, CDWR, a counterparty to one of the eight PPAs, had filed a complaint with FERC seeking to obtain injunctive relief to prevent us from rejecting our PPA with CDWR and contending that FERC had exclusive jurisdiction over the matter. On January 3, 2006, FERC determined that it did not have exclusive jurisdiction, and that the matter could be heard by the U.S. Bankruptcy Court. However, despite the FERC ruling, on January 27, 2006, the SDNY Court determined that FERC had jurisdiction over whether the contracts could be rejected. We appealed the SDNY Court’s decision to the United States Court of Appeals for the Second Circuit. The appeal was heard on April 10, 2006 and we have not yet received a decision. We cannot determine at this time whether the SDNY Court, the U.S. Bankruptcy Court or FERC will ultimately determine whether we may reject any or all of the eight PPAs, or when such determination will be made. In the meantime, three of the PPAs have been terminated by the applicable counterparties, and we continue to perform under those PPAs that remain in effect.

Factors that could affect our liquidity and capital resources are also discussed below in “Capital Spending” and above in Item 1A. “Risk Factors.”

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


				Years Ended December 31,

				2005			2004			2003

				(In thousands)
Beginning cash and cash equivalents				$	718,023		$	954,828		$	567,371

Net cash provided by:
	Operating activities			$	(708,361	)	$	9,895		$	290,559
	Investing activities				917,457			(401,426	)		(2,515,365	)
	Financing activities				(159,929	)		167,052			2,623,986
	Effect of exchange rates changes on cash and cash equivalents, including discontinued operations cash				(181	)		16,101			13,140

		Net increase (decrease) in cash and cash equivalents including discontinued operations cash		$	48,986		$	(208,378	)	$	412,320
Change in discontinued operations cash classified as current assets held for sale					18,628			(28,427	)		(24,863	)

Net increase (decrease) in cash and cash equivalents				$	67,614		$	(236,805	)	$	387,457

			Ending cash and cash equivalents	$	785,637		$	718,023		$	954,828

Operating activities for the year ended December 31, 2005 used net cash of $708.4 million, compared to providing $9.9 million for the same period in 2004. In 2005, there was a $332.0 million use of funds from net changes in operating assets and liabilities comprised of decreases in accounts payable, payroll and other liabilities of $170.6 million, an increase in accounts receivable of $42.4 million and an increase in net margin deposits posted to support CES contracting activity of $11.6 million. Cash operating lease payments in 2005 also exceeded recognized expense by $91.4 million. Operating cash flows in 2004 benefited from the receipt of $100.6 million from the termination of PPAs for two of our New Jersey power plants and $16.4 million from the restructuring of a long-term gas supply contract.

Investing activities for the year ended December 31, 2005, provided net cash of $917.5 million, as compared to using $401.4 million in the same period of 2004. Capital expenditures, including capitalized interest, for the completion of our power facilities decreased from $1,545.5 million in 2004 to $774.0 million 2005, as there were fewer projects under construction. Investing activities in 2005 reflect the receipt of $897.4 million from the sale of our oil and natural gas assets, $862.9 million from the sale of our Saltend power plant in the UK, $212.3 million from the sale of our Ontelaunee power plant, $84.5 million from the sale of our Morris power plant, $37.4 million from the sale of our investment in Grays Ferry power plant, and $30.4 million from the sale of our Inland Empire development project. Additional investing activities in 2005 reflect the receipt of $132.5 million from the disposition of our investment in HIGH TIDES III, offset by a $535.6 million increase in restricted cash, including $406.9 million of proceeds from the sale of our oil and gas assets, and a $90.9 million decrease in cash due to the deconsolidation of our Canadian and foreign entities. Investing activities in 2004 reflected the receipt of $148.6 million from the sale of our 50% interest in the Lost Pines I Power Plant, $626.4 million from the sale of our Canadian oil and gas reserves, $218.7 million from the sale of our Rocky Mountain oil and gas reserves, plus $85.4 million of proceeds from the sale of a subsidiary holding PPAs for two of our New Jersey power plants. In 2004, we also used the proceeds from the Lost Pines sale and cash to purchase the Los Brazos Power Plant, and we used cash on hand to purchase the remaining 50% interest in the Aries Power Plant and the remaining 20% interest in Calpine Cogen. Also, we used $110.6 million to purchase a portion of HIGH TIDES III outstanding and provided $210.8 million by decreasing restricted cash during 2004.

Financing activities for the year ended December 31, 2005 used net cash of $159.9 million, as compared to providing $167.1 million in the prior year. We continued our refinancing program in 2005 by raising $260.0, $155.0 and $450.0 million (of which $150.0 million was repurchased on October 14, 2005) from preferred securities offerings by Calpine Jersey II, Metcalf and CCFCP, respectively, $650.0 million from the 2015

Convertible Notes offering, $750.5 million from various project financings, $263.6 million from a prepaid commodity derivative contract at our Deer Park facility, we received funding on a $123.1 million non-recourse project finance facility to complete the 79.9-MW Bethpage Energy Center 3, and $25.0 million from our DIP Facility. We used $389.8 million to repay notes payable and project financing debt, $778.6 million to repay preferred security offerings (including the Calpine Jersey II mentioned above) in addition to using $880.1 million to repay or repurchase Senior Notes and $517.5 million to repay HIGH TIDES III. Additionally, we incurred $117.3 million in financing and transaction costs. Financing activities in 2004 raised $2.6 billion to refinance $2.5 billion of CalGen project financing before payment for fees and expenses of the refinancing. In 2004 we also raised $250 million from the issuance of the 2023 Convertible Notes pursuant to an option exercise by one of the initial purchasers and $617.5 million from the issuance of the 2014 Convertible Notes. We raised $878.8 million from the issuance of Senior Notes, $360.0 million from a preferred security offering and $1,179.4 million from various project financings. Also, we repaid $635.4 million in project financing debt, and we used $658.7 million to repurchase most of the outstanding 2006 Convertible Notes that could be put to us in December 2004. We used $177.0 million to repurchase a portion of the 2023 Convertible Notes, $871.3 million to repay and repurchase various Senior Notes and $483.5 million to redeem the remainder of HIGH TIDES I and II.

Negative Working Capital — At December 31, 2005, we had negative working capital of $3.7 billion which is primarily due to technical defaults under certain of our indentures and other financing instruments requiring us to record approximately $5.1 billion of additional debt as current. We are in the process of obtaining waivers on the technical defaults in the case of Non-Debtor entities. Generally, the lenders’ or noteholders’ rights to acceleration of repayment is stayed by the bankruptcy cases for the Calpine Debtor entities.

Counterparties and Customers — Our customer and supplier base is concentrated within the energy industry. Additionally, we have exposure to trends within the energy industry, including declines in the creditworthiness of our marketing counterparties. Currently, multiple companies within the energy industry have below investment grade credit ratings. However, we do not currently have any significant exposures to counterparties that are not paying on a current basis.

In addition, as a result of our bankruptcy and prior credit ratings downgrades, our credit status has been impaired. Our impaired credit has, among other things, generally resulted in an increase in the amount of collateral required by our trading counterparties and also reduced the number of trading counterparties currently able to do business with us, which reduces our ability to negotiate more favorable terms with them. We expect that our perceived creditworthiness will continue to be impaired at least for the duration of our bankruptcy cases.

Letter of Credit Facilities — At December 31, 2005 and 2004, we had approximately $370.3 million and $596.1 million, respectively, in letters of credit outstanding under various credit facilities to support our risk management and other operational and construction activities. Of the total letters of credit outstanding, $140.3 million and $233.3 million at December 31, 2005 and 2004, respectively, were in aggregate issued under our credit facilities.

Commodity Margin Deposits and Other Credit Support — As of December 31, 2005 and 2004, to support commodity transactions, we had margin deposits with third parties of $287.5 million and $276.5 million, respectively; we made gas and power prepayments of $103.2 million and $80.5 million, respectively; and had letters of credit outstanding of $88.1 million and $115.9 million, respectively. Counterparties had deposited with us $27.0 million and $27.6 million as margin deposits at December 31,2005 and 2004, respectively. We use margin deposits, prepayments and letters of credit as credit support for commodity procurement and risk management activities. Future cash collateral requirements may increase based on the extent of our involvement in standard contracts and movements in commodity prices and also based on our credit ratings and general perception of creditworthiness in this market. While we believe that we have adequate liquidity to support our operations at this time, it is difficult to predict future developments and the amount of credit support that we may need to provide as part of our business operations.

Asset Sales — Prior to filing for bankruptcy on December 20, 2005, we had adopted a strategy of conserving our core strategic assets and selectively disposing of certain less strategically important assets, through which we sought to strengthen our balance sheet by using the proceeds of such asset sales to repay or otherwise reduce our debt. Prior to our bankruptcy filing, we completed the following dispositions.


Date		Description

7/7/05		Completed the sale of substantially all of our remaining oil and gas assets for $1.05 billion, less approximately $60 million of estimated transaction fees and expenses
7/8/05		Completed the sale of our 50% interest in the 175-MW Grays Ferry Power Plant for gross proceeds of $37.4 million
7/28/05		Completed the sale of our 1,200-MW Saltend Energy Centre for approximately $862.9 million
7/29/05		Completed the sale of our Inland Empire development project for approximately $30.9 million
8/2/05		Completed the sale of our 156-MW Morris Energy Center for $84.5 million
10/06/05		Complete the sale of the 561-MW Ontelaunee Energy Center for $212.3 million

Our financial statements reflect reclassifications to record certain of these assets as discontinued operations. See Note 13 of the Notes to Consolidated Financial Statements for more information regarding our discontinued operations and our asset sales completed in 2005.

As discussed above and in Item 1. “Business — Strategy” we are continuing to reduce activities and curtail expenditures in certain non-core areas and business units. Among other things, we have begun to implement staff reductions of approximately 1,100 positions, or over one third of our workforce, which are expected to be completed by the end of 2006. Other cost reduction measures include the closure of non-core offices and the sales of non-strategic assets.

Among other things, on March 3, 2006, pursuant to the Cash Collateral Order, we, together with the Official Committee of Unsecured Creditors of Calpine Corporation and the Ad Hoc Committee of Second Lien Holders of Calpine Corporation agreed, in consultation with the indenture trustee for our First Priority Notes, on the designation of nine projects that, absent the consent of such Committees or unless ordered by the Bankruptcy Court, may not receive funding, other than certain limited amounts. The nine designated projects are: Clear Lake Power Plant, Dighton Power Plant, Fox Energy Center, Newark Power Plant, Parlin Power Plant, Pine Bluff Energy Center, Rumford Power Plant, Texas City Power Plant, and Tiverton Power Plant. In accordance with the Cash Collateral Order, it is possible that additional power plants will be added (or certain of the listed plants may be removed) as designated projects. As described above, we are seeking to reject the Rumford and Tiverton leases and have tendered surrender of those power plants to their lessor. We have not yet determined what actions we will take with respect to the other power plants; however, it is possible that we could seek to sell those facilities or, as applicable, reject the related leases.

Credit Considerations — On December 21, 2005, Standard and Poor’s lowered its corporate credit rating on Calpine Corporation to D (default) from CCC-. In addition, the ratings on Calpine’s debt and the ratings of debt of its subsidiaries have been lowered to D, with a few exceptions.

On December 2, 2005, Moody’s Investor Service lowered its Long Term Corporate Family on Calpine Corporation to Caa1 from B3. In addition, the ratings on Calpine’s debt and the ratings on the debt of its subsidiaries were also lowered to Ca. On March 1, 2006, Moody’s withdrew all of the ratings of Calpine Corporation.

On November 4, 2005, Fitch Ratings lowered Calpine’s senior unsecured notes two notches to CCC- from CCC+. In addition, the ratings on Calpine’s first and second priority notes were also lowered by two notches. On December 21, 2005, Fitch lowered its Long Term Default Ratings on Calpine to D and the ratings on Calpine’s senior unsecured notes were lowered to CC from CCC-.

Bankruptcy and credit rating downgrades have had a negative impact on our liquidity by increasing the amount of collateral required by trading counterparties. We believe that as we implement the steps of our business plan and then emerge from bankruptcy, our credit rating will be reestablished and will gradually improve.

Performance Indicators — We believe the following factors are important in assessing our ability to continue to fund our operations and to successfully reorganize and emerge from bankruptcy as a sustainable, competitive and profitable power company: (a) reducing our activities in certain non-core areas and lowering overhead and operating expenses; (b) reducing our anticipated capital requirements over the coming quarters and years; (c) improving the profitability of our operations and our performance as measured by the non-GAAP financial measures and other performance metrics discussed in “Performance Metrics” below; (d) complying with the covenants in our DIP Facility; (e) gaining access to new or replacement capital upon emergence from bankruptcy; and (f) stabilizing and increasing future contractual cash flows.

Off-Balance Sheet Commitments — In accordance with SFAS No. 13, “Accounting for Leases” and SFAS No. 98, “Accounting for Leases,” our operating leases, which include certain sale/leaseback transactions, are not reflected on our balance sheet. All counterparties in these transactions are third parties that are unrelated to us except as disclosed for Acadia PP in Note 10 of the Notes to Consolidated Financial Statements. The sale/leaseback transactions utilize special-purpose entities formed by the equity investors with the sole purpose of owning a power generation facility. Some of our operating leases contain customary restrictions on dividends, additional debt and further encumbrances similar to those typically found in project finance debt instruments. We guarantee $1.6 billion of the total future minimum lease payments of our consolidated subsidiaries related to our operating leases. We have no ownership or other interest in any of these special-purpose entities. See Note 31 of the Notes to Consolidated Financial Statements for the future minimum lease payments under our power plant operating leases.

In accordance with APB Opinion No. 18, “The Equity Method of Accounting For Investments in Common Stock” and FIN 35, “Criteria for Applying the Equity Method of Accounting for Investments in Common Stock (An Interpretation of APB Opinion No. 18),” the debt on the books of our unconsolidated investments in power projects is not reflected on our balance sheet. See Note 10 of the Notes to Consolidated Financial Statements. At December 31, 2005, investee debt was approximately $2.2 billion. Of the $2.2 billion, $2.0 billion related to our deconsolidated Canadian and other foreign subsidiaries. Based on our pro rata ownership share of each of the investments, our share of such debt would be approximately $2.1 billion. Except for the debt of the deconsolidated Canadian and other foreign subsidiaries, all such debt is non-recourse to us. See Note 10 of the Notes to Consolidated Financial Statements for additional information on our equity method and cost method unconsolidated investments in power projects and oil and gas properties.

Commercial Commitments — Our primary commercial obligations as of December 31, 2005, are as follows (in thousands):


		Amounts of Commitment Expiration per Period

														Total
														Amounts
Commercial Commitments		2006		2007		2008		2009		2010		Thereafter		Committed

Guarantee of subsidiary debt		$	24,425	$	198,859	$	1,592,342	$	22,131	$	11,040	$	590,287	$	2,439,084
Standby letters of credit			361,104		8,298		898		—		—		—		370,300
Surety bonds			—		—		—		—		—		11,395		11,395
Guarantee of subsidiary operating lease payments			81,772		82,487		115,604		113,977		263,041		900,742		1,557,623

	Total	$	467,301	$	289,644	$	1,708,844	$	136,108	$	274,081	$	1,502,424	$	4,378,402

Our commercial commitments primarily include guarantees of subsidiary debt, standby letters of credit and surety bonds to third parties and guarantees of subsidiary operating lease payments. The debt guarantees consist of parent guarantees for the finance subsidiaries and project financing for the Broad River Energy Center and the Pasadena Power Plant. The debt guarantees and operating lease payments are also included in the commercial commitments table above. We also issue guarantees for normal course of business activities.

We have guaranteed the repayment of Senior Notes (original principal amount of $2,597.2 million) for two wholly owned finance subsidiaries of ours, ULC I and ULC II. However, amounts outstanding under these two entities have been reduced to $1,943.0 million and $2,139.7 million, at December 31, 2005 and 2004, respectively, due to repurchases of such Senior Notes which are held by subsidiaries of ours. King City Cogen, a wholly owned subsidiary of ours, has guaranteed to Calpine Commercial Trust, an unaffiliated entity, a loan made by the Calpine Commercial Trust to our wholly owned subsidiary, Calpine Canada Power Limited. Outstanding balances of the loan at December 31, 2005 and 2004, were $28.7 million and $37.7 million, respectively. As of December 31, 2005, we have guaranteed $265.2 million and $76.6 million, respectively, of project financing for the Broad River Energy Center and Pasadena Power Plant and $275.1 million and $72.4 million, respectively, as of December 31, 2004, for these power plants. In 2004, we had debenture obligations related to the HIGH TIDES III in the amount of $517.5 million. In 2005 we repaid these convertible debentures. (See Note 5 for more information.) With respect to our Hidalgo facility, we agreed to indemnify Duke Capital Corporation in the amount of $101.4 million as of December 31, 2005 and 2004, in the event Duke Capital Corporation is required to make any payments under its guarantee of the Hidalgo Lease. As of December 31, 2005 and 2004, we have also guaranteed $24.2 million and $31.7 million, respectively, of other miscellaneous debt. In addition, as a result of the deconsolidation of our Canadian and other foreign subsidiaries, we deconsolidated approximately $2.0 billion of debt that is guaranteed by Calpine Corporation (or a consolidated subsidiary thereof) through, in some cases, redundant guarantee structures that are expected to give rise to allowable claims in excess of the amount of debt outstanding to third party securities holders. Accordingly, we recorded approximately $3.8 billion of additional LSTC related to the ULC I, ULC II, and the King City Cogen loan guarantees, some of which, as in the case of ULC I guarantees, were redundant. As of December 31, 2005, all of the guaranteed debt is recorded on our Consolidated Balance Sheet, except for ULC I, ULC II and the Calpine Commercial Trust loan, which were deconsolidated on December 20, 2005. As of December 31, 2004, all of the guaranteed debt was recorded on our Consolidated Balance Sheet.

Contractual Obligations — Our contractual obligations related to continuing operations as of December 31, 2005, are as follows (in thousands):


				2006		2007		2008		2009		2010		Thereafter		Total

Other contractual obligations				$	31,846	$	7,148	$	8,148	$	5,880	$	5,837	$	45,652	$	104,511

Total operating lease obligations(1)				$	198,967	$	184,284	$	180,015	$	174,696	$	318,751	$	1,122,140	$	2,178,853

Debt:
	Notes payable and other borrowings(3)(4)				179,597		134,447		97,901		104,003		111,464		1,443		628,855
	Preferred interests(3)				9,479		8,990		12,236		16,228		175,144		370,819		592,896
	Capital lease obligations(3)				8,133		7,940		9,875		10,952		16,057		233,800		286,757
	CCFC (3)				3,208		3,208		3,209		365,349		—		409,539		784,513
	CALGEN(3)				—		44,974		12,050		829,875		721,083		830,000		2,437,982
	Construction/project financing(3)(5)				79,594		100,069		95,502		99,518		190,630		1,795,712		2,361,025
	DIP Facility				—		25,000		—		—		—		—		25,000
	Senior Notes and term loans(2)				—		—		—		—		—		641,652		641,652

			Total debt not subject to compromise		280,011		324,628		230,773		1,425,925		1,214,378		4,282,965		7,758,680
	Liabilities subject to compromise(8):
		Construction/project financing(3)(5)			—		—		—		—		—		166,506		166,506
		Contingent Convertible Senior Notes Due 2006, 2014, 2015 and 2023(2)			—		—		—		—		—		1,823,460		1,823,460
		Second priority senior secured Notes(2)			—		—		—		—		—		3,671,875		3,671,875
		Unsecured senior notes(2)			—		—		—		—		—		1,879,989		1,879,989
		Notes payable and other liabilities — related party			—		—		—		—		—		1,078,045		1,078,045
		Provision for claims under parent guarantees			—		—		—		—		—		5,132,349		5,132,349
		Other			—		—		—		—		—		857,840		857,840

			Total liabilities subject to compromise		—		—		—		—		—		14,610,064		14,610,064
Total debt and liabilities subject to compromise(4)(8)				$	280,011	$	324,628	$	230,773	$	1,425,925	$	1,214,378	$	18,893,029	$	22,368,744

Interest payments on debt not subject to compromise(8)				$	911,607	$	737,843	$	730,605	$	679,207	$	548,177	$	1,588,891	$	5,196,330

Interest rate swap agreement payments				$	1,153	$	795	$	907	$	677	$	1,197	$	1,327	$	6,056

Purchase obligations:
	Turbine commitments				17,578		4,432		2,699		—		—		—		24,709
	Commodity purchase obligations(6)				965,934		476,431		455,114		446,363		440,038		1,821,912		4,605,792
	Land leases				4,394		4,585		5,122		5,616		5,744		361,700		387,161
	Long-term service agreements				35,036		53,420		36,637		39,649		34,692		204,711		404,145
	Costs to complete construction projects				215,213		—		—		—		—		—		215,213
	Other purchase obligations(9)				54,624		32,886		27,190		26,945		27,559		446,677		615,881

		Total purchase obligations(7)		$	1,292,779	$	571,754	$	526,762	$	518,573	$	508,033	$	2,835,000	$	6,252,901


	(1)	Included in the total are future minimum payments for power plant operating leases, and office and equipment leases. See Note 31 of the Notes to Consolidated Financial Statements for more information.

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


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

	(4)	A note payable totaling $117.7 million associated with the sale of the PG&E note receivable to a third party is excluded from notes payable and other borrowings for this purpose as it is a noncash liability. If the $117.7 million is summed with the $628.9 million (total notes payable and other) from the table above, the total notes payable and other would be $746.6 million, which agrees to the sum of the current and long-term notes payable and other borrowings balances on the Consolidated Balance Sheet. See Note 14 of the Notes to Consolidated Financial Statements for more information concerning this note. Total debt not subject to compromise of $7,758.7 million from the table above summed with the $117.7 million totals $7,876.4 million, which agrees to the total debt not subject to compromise amount in Note 14 of the Notes to Consolidated Financial Statements.

	(5)	Included in the total are guaranteed amounts of $275.1 million and $72.4 million, respectively, of project financing for the Broad River Energy Center and Pasadena Power Plant.

	(6)	The amounts presented here include contracts for the purchase, transportation, or storage of commodities accounted for as executory contracts or normal purchase and sales and, therefore, not recognized as liabilities on our Consolidated Balance Sheet. See “Financial Market Risks” for a discussion of our commodity derivative contracts recorded at fair value on our Consolidated Balance Sheet.

	(7)	The amounts included above for purchase obligations include the minimum requirements under contract. Also included in purchase obligations are employee agreements. Agreements that we can cancel without significant cancellation fees are excluded.

	(8)	In accordance with SOP 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code,” and as a result of the automatic stay provisions of Chapter 11 and the uncertainty of the amount approved by the court as allowed claims, we are unable to determine the maturity date of the LSTC. Accordingly, only the total contractual amounts due related to these instruments is noted above. Also, we ceased accruing and recognizing interest expense on debt that is considered to be subject to compromise, except that being paid pursuant to the Cash Collateral Order. Consequently, interest payable does not include contractual interest due on LSTC.

(9)

The amounts include obligations under employment agreements. They do not include success fees which are contingent on the employment status if and when a plan of reorganization is confirmed by the bankruptcy court. Also, any claim by Mr. Cartwright for severance benefits is not included in the table above and would be a pre-petition claim and processed accordingly in the Chapter 11 cases. See Item 11. “Executive Compensation — Employment Agreements, Termination of Employment and Change in Control Arrangements” for a discussion of Messrs. May, Davido and Cartwright’s employment contracts.

Debt Extinguishments — Senior Notes extinguished through open market repurchases and unscheduled payments by Calpine during 2005 and 2004 totaled $917.1 million and $1,668.3 million, respectively, in aggregate outstanding principal amount for a repurchase price of $685.5 million and $1,394.0 million, respectively, plus accrued interest. In 2005, we recorded a pre-tax gain on these transactions in the amount of $220.1 million, which was $231.6 million, net of write-offs of $9.3 million of unamortized deferred financing costs and $2.2 million of unamortized premiums or discounts and legal costs. In 2004 we recorded a pre-tax gain on these transactions in the amount of $254.8 million, which was $274.4 million, net of write-offs of $19.1 million of unamortized deferred financing costs and $0.5 million of unamortized premiums or discounts. HIGH TIDES III repurchased by Calpine during 2004 totaled $115.0 million in aggregate outstanding principle amount at a repurchase price of $111.6 million plus accrued interest. These repurchased HIGH TIDES III are reflected on the balance sheets for December 31, 2004, as an asset, versus being netted against the balance outstanding, due to the deconsolidation of the Calpine Capital Trusts, which issued the HIGH TIDES, upon the adoption of FIN 46-R. On July 13, 2005, we repaid the convertible debentures payable to Trust III, the issuer of the HIGH TIDES III. Trust III then used the proceeds to redeem the outstanding HIGH TIDES III totaling $517.5 million, including the $115.0 million held by Calpine. See Note 16 of the Notes to Consolidated Financial Statements. The following table summarizes the total debt securities repurchased (in millions):


	2005				2004

	Principal		Amount		Principal		Amount
Debt Security and HIGH TIDES	Amount		Paid		Amount		Paid

2006 Convertible Notes	$	—	$	—	$	658.7	$	657.7
2023 Convertible Notes		—		—		266.2		177.0
First Priority Notes		138.9		138.9		—		—
8¹/4 % Senior Notes Due 2005		4.0		4.0		38.9		34.9
10¹/2 % Senior Notes Due 2006		13.5		12.4		13.9		12.4
7⁵/8 % Senior Notes Due 2006		9.4		8.7		103.1		96.5
8³/4 % Senior Notes Due 2007		5.0		3.2		30.8		24.4
7⁷/8 % Senior Notes Due 2008		53.5		39.6		78.4		56.5
8¹/2 % Senior Notes Due 2008		159.8		102.6		344.3		249.4
8³/8 % Senior Notes Due 2008		—		—		6.1		4.0
7³/4 % Senior Notes Due 2009		41.0		24.8		11.0		8.1
8⁵/8 % Senior Notes Due 2010		86.2		59.1		—		—
8¹/2 % Senior Notes Due 2011		405.8		292.2		116.9		73.1

	$	917.1	$	685.5	$	1,668.3	$	1,394.0

In addition to the amounts shown in the above table:


	•	During 2004 we exchanged 24.3 million shares of Calpine common stock in privately negotiated transactions for a total of approximately $115.0 million par value of HIGH TIDES I and HIGH TIDES II.

	•	On October 20, 2004, we repaid $636 million of convertible debentures held by Trust I and Trust II, respectively, which then used those proceeds to redeem the outstanding HIGH TIDES I and II. The redemption included the $115.0 million par value HIGH TIDES I and II previously purchased and held by us and resulted in a net loss of $7.8 million, comprised of a gain of $6.1 million against a write-off of $13.9 million of unamortized deferred financing costs.

	•	On June 28, 2005, we exchanged 27.5 million shares of Calpine common stock in privately negotiated transactions for $94.3 million in aggregate principal amount at maturity of our 2014 Convertible Notes. This resulted in a pre-tax loss of $8.3 million, comprised of a gain of $8.9 million, net of write-offs of $2.8 million unamortized deferred financing costs and $14.4 unamortized discount and legal costs.


	•	On July 13, 2005, we repaid $517.5 million of convertible debentures held by Trust III, which then used those proceeds to redeem the outstanding HIGH TIDES III. The redemption included the $115 million of HIGH TIDES III previously purchased and held by us and resulted in a net loss of $8.5 million, comprised of a gain of $4.4 million against a write-off of $12.9 million of unamortized deferred financing costs.

The following table summarizes the total debt securities and HIGH TIDES exchanged for common stock in 2005 and 2004 (in millions):


	2005				2004

			Common				Common
	Principal		Stock		Principal		Stock
Debt Securities and HIGH TIDES	Amount		Issued		Amount		Issued

2014 Convertible Notes	$	94.3		27.5	$	—		—
HIGH TIDES I		—		—		40.0		8.5
HIGH TIDES II		—		—		75.0		15.8

	$	94.3		27.5	$	115.0		24.3

See Notes 14-24 of the Notes to Consolidated Financial Statements below for a description of each of our debt obligations.

Debt, Lease and Indenture Covenant Compliance — See Note 14 of the Notes to Consolidated Financial Statements for compliance information.

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

The following table sets forth selected balance sheet information of Calpine Corporation and restricted subsidiaries and of such unrestricted subsidiaries at December 31, 2005, and selected income statement information for the year ended December 31, 2005 (in thousands):


		Calpine
		Corporation
		and Restricted			Unrestricted
		Subsidiaries			Subsidiaries			Eliminations			Total

Assets		$	20,184,479		$	360,318		$	—		$	20,544,797

Liabilities not subject to compromise		$	10,962,473		$	204,961		$	—		$	11,167,434

Liabilities subject to compromise		$	14,581,425		$	28,639		$	—		$	14,610,064

Total revenue		$	10,108,178		$	12,822		$	(8,342	)	$	10,112,658
Total (cost) of revenue			(12,050,108	)		(20,341	)		12,868			(12,057,581	)
Equipment, development project and other impairments			(2,117,665	)		—			—			(2,117,665	)
Interest income			74,334			16,681			(6,789	)		84,226
Interest (expense)			(1,384,345	)		(12,943	)		—			(1,397,288	)
Reorganization items			(5,026,510	)		—			—			(5,026,510	)
Other			517,896			(54,944	)		—			462,952

	Net income (loss)	$	(9,878,220	)	$	(58,725	)	$	(2,263	)	$	(9,939,208	)

Special Purpose Subsidiaries — Pursuant to applicable transaction agreements, we have established certain of our entities separate from Calpine and our other subsidiaries. At December 31, 2005, these entities included: Rocky Mountain Energy Center, LLC, Riverside Energy Center, LLC, Calpine Riverside Holdings, LLC, Calpine Energy Management, L.P., CES GP, LLC, PCF, PCF III, Calpine Northbrook Energy Marketing, LLC, CNEM Holdings, LLC, Gilroy Energy Center, LLC, Calpine Gilroy Cogen, L.P., Calpine Gilroy 1, Inc., Calpine King City Cogen, LLC, Calpine Securities Company, L.P. (a parent company of Calpine King City Cogen, LLC), Calpine King City, LLC (an indirect parent company of Calpine Securities Company, L.P.), Calpine Fox Holdings, LLC, Calpine Fox LLC, Calpine Deer Park Partner, LLC, Calpine Deer Park, LLC, Deer Park Energy Center Limited Partnership, CCFC Preferred Holdings, LLC and Metcalf Energy Center, LLC. The following disclosures are required under certain applicable agreements and pertain to some of these entities.

On May 15, 2003, our wholly owned indirect subsidiary, CNEM, completed an offering of $82.8 million secured by an existing PPA with the BPA. CNEM borrowed $82.8 million secured by the BPA contract, a spot market PPA, a fixed price swap agreement and the equity interest in CNEM. The $82.8 million loan is recourse only to CNEM’s assets and the equity interest in CNEM and is not guaranteed by us. CNEM was determined to be a VIE in which we were the primary beneficiary. Accordingly, the entity’s assets and liabilities are consolidated into our accounts.

Pursuant to the applicable transaction agreements, each of CNEM and its parent, CNEM Holdings, LLC, have been established as an entity with its existence separate from us and other subsidiaries of ours. In accordance with FIN 46-R, “Consolidation of Variable Interest Entities,” — revised, we consolidate these entities. See Note 2 of the Notes to Consolidated Financial Statements for more information on FIN 46-R. The PPA with BPA has been acquired by CNEM from CES and the spot market PPA with a third party and the swap agreement that has been entered into by CNEM, together with the $82.8 million loan, are assets and liabilities of CNEM, separate from our assets and liabilities and other subsidiaries of ours. The only significant asset of CNEM Holdings, LLC is its equity interest in CNEM. The proceeds of the $82.8 million loan were primarily used by CNEM to purchase the PPA with BPA.

The following table sets forth selected financial information of CNEM as of and for the year ended December 31, 2005 (in thousands):


	2005

Assets	$	21,985
Liabilities not subject to compromise	$	37,275
Total revenue(1)	$	22,575
Total cost of revenue	$	—
Interest expense	$	4,679
Net income (loss)	$	17,817


(1)	CNEM’s contracts are derivatives and are recorded on a net mark-to-market basis on our financial statements under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” notwithstanding that economically they are fully hedged.

See Note 15 of the Notes to Consolidated Financial Statements for further information.

On June 13, 2003, PCF, a wholly owned stand-alone subsidiary of ours, completed an offering of two tranches of Senior Secured Notes due 2006 and 2010 (collectively called the “PCF Notes”), totaling $802.2 million original principal amount. PCF’s assets and liabilities consist of cash (maintained in a debt reserve fund), a power sales agreement with Morgan Stanley Capital Group Inc., a PPA with CDWR, and the PCF Notes. PCF was determined to be a VIE in which we were the primary beneficiary. Accordingly, the entity’s assets and liabilities are consolidated into our accounts.

Pursuant to the applicable transaction agreements, PCF has been established as an entity with its existence separate from us and other subsidiaries of ours. In accordance with FIN 46-R, we consolidate this entity. See Note 2 of the Notes to Consolidated Financial Statements for more information on FIN 46-R. The above-mentioned power sales agreement and PPA, which were acquired by PCF from CES, and the PCF Notes (a portion of which have been repaid pursuant to the PCF Notes’ amortization schedule) are assets and liabilities of PCF, separate from the assets and liabilities of us and other subsidiaries of ours. The following table sets forth selected financial information of PCF as of and for the year ended December 31, 2005 (in thousands):


	2005

Assets	$	469,305
Liabilities	$	581,616
Total revenue	$	512,405
Total cost of revenue	$	435,018
Interest expense	$	54,654
Net income (loss)	$	26,490

See Note 15 of the Notes to Consolidated Financial Statements for further information.

On September 30, 2003, GEC, a wholly owned subsidiary of our subsidiary GEC Holdings, LLC, completed an offering of $301.7 million of 4% Senior Secured Notes Due 2011. See Note 17 of the Notes to Consolidated Financial Statements for more information on this secured financing. In connection with the issuance of the secured notes, we received funding on a third party preferred equity investment in GEC Holdings, LLC totaling $74.0 million. This preferred interest meets the criteria of a mandatorily redeemable financial instrument and has been classified as debt under the guidance of SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity,” due to certain preferential distributions to the third party. The preferential distributions are due semi-annually beginning in March 2004 through September 2011 and total approximately $113.3 million over the eight-year period. As of December 31, 2005 and 2004, there was $59.8 and $67.4 million, respectively, outstanding under the preferred interest.

Pursuant to the applicable transaction agreements, GEC has been established as an entity with its existence separate from us and other subsidiaries of ours. We consolidate this entity. A long-term PPA between CES and the CDWR has been acquired by GEC by means of a series of capital contributions by CES and certain of its affiliates and is an asset of GEC, and the secured notes and the preferred interest are liabilities of GEC, separate from the assets and liabilities of Calpine and our other subsidiaries. In addition to the PPA and seven peaker power plants owned directly by GEC, GEC’s assets include cash and a 100% equity interest in each of Creed and Goose Haven, each of which is a wholly owned subsidiary of GEC and a guarantor of the secured notes. Each of Creed and Goose Haven has been established as an entity with its existence separate from us and other subsidiaries of ours. GEC consolidates these entities. Creed and Goose Haven each have assets consisting of various power plants and other assets. The following table sets forth selected financial information of GEC as of and for the year ended December 31, 2005 (in thousands):


	2005

Assets	$	601,681
Liabilities	$	255,906
Total revenue	$	96,816
Total cost of revenue	$	35,688
Interest expense	$	17,735
Net income	$	45,614

See Note 15 of the Notes to Consolidated Financial Statements for further information.

On December 4, 2003, we announced that we had sold to a group of institutional investors our right to receive payments from PG&E under an Agreement between PG&E and Calpine Gilroy Cogen, L.P. regarding the termination and buy-out of a Standard Offer contract between PG&E and Gilroy (the “Gilroy Receivable”) for $133.4 million in cash. Because the transaction did not satisfy the criteria for sales treatment under SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities — a Replacement of FASB Statement No. 125,” it is reflected in the consolidated financial statements as a secured financing, with a note payable of $133.4 million. The receivable balance and note payable balance are both reduced as PG&E makes payments to the buyer of the Gilroy Receivable. The $24.1 million difference between the $157.5 million book value of the Gilroy Receivable at the transaction date and the cash received will be recognized as additional interest expense over the repayment term. We will continue to record interest income over the repayment term, and interest expense will be accreted on the amortizing note payable balance.

Pursuant to the applicable transaction agreements, each of Gilroy and Calpine Gilroy 1, Inc. (the general partner of Gilroy), has been established as an entity with its existence separate from us and other subsidiaries of ours. We consolidate these entities. The following table sets forth the assets and liabilities of Gilroy as of December 31, 2005 (in thousands):


	2005

Assets	$	362,761
Liabilities	$	118,701
Liabilities subject to compromise	$	2,514

See Notes 11 and 15 of the Notes to Consolidated Financial Statements for further information.

On June 2, 2004, our wholly owned indirect subsidiary, PCF III, issued $85.0 million aggregate principal amount at maturity of notes collateralized by PCF III’s ownership of PCF. PCF III owns all of the equity interests in PCF, the assets of which include a debt reserve fund, which had a balance of approximately $94.4 million and $94.4 million at December 31, 2005 and 2004, respectively. We received cash proceeds of approximately $49.8 million from the issuance of the notes, which accrete in value up to $85 million at maturity in accordance with the accreted value schedule for the notes.

Pursuant to the applicable transaction agreements, PCF III has been established as an entity with its existence separate from us and other subsidiaries of ours. We consolidate this entity. The following table sets forth the assets and liabilities of PCF III as of December 31, 2005, which does not include the balances of PCF III’s subsidiary, PCF (in thousands):


	2005

Assets	$	1,576
Liabilities	$	57,117

See Note 15 of the Notes to Consolidated Financial Statements for further information.

On August 5, 2004, our wholly owned indirect subsidiary, CEM, entered into a $250.0 million letter of credit facility with Deutsche Bank whereby Deutsche Bank supported CEM’s power and gas obligations by issuing letters of credit. The facility expired in the fourth quarter of 2005.

Pursuant to the applicable transaction agreements, CEM had been established as an entity with its existence separate from us and other subsidiaries of ours. We consolidated this entity.

On June 29, 2004, Rocky Mountain Energy Center, LLC and Riverside Energy Center, LLC, wholly owned subsidiaries of the Company’s Calpine Riverside Holdings, LLC subsidiary, received funding in the aggregate amount of $661.5 million comprising $633.4 million of First Priority Secured Floating Rate Term Loans Due 2011 and a $28.1 million letter of credit-linked deposit facility.

Pursuant to the applicable transaction agreements, each of Rocky Mountain Energy Center, LLC, Riverside Energy Center, LLC, and Calpine Riverside Holdings, LLC has been established as an entity with

its existence separate from Calpine and our other subsidiaries. We consolidate these entities. The following tables set forth the assets and liabilities of these entities as of December 31, 2005 (in thousands):


	Rocky Mountain		Riverside Energy		Calpine Riverside
	Energy Center, LLC		Center, LLC		Holdings, LLC
	2005		2005		2005

Assets	$	431,408	$	690,554	$	284,782
Liabilities	$	279,521	$	421,820	$	—

See Note 21 of the Notes to Consolidated Financial Statements for further information.

On November 19, 2004, we entered into a $400 million, 25-year, non-recourse sale/leaseback transaction with affiliates of GECF for the 560-megawatt Fox Energy Center under construction by GECF in Wisconsin. Due to significant continuing involvement, as defined in SFAS No. 98, “Accounting for Leases,” the transaction does not currently qualify for sale/leaseback accounting under that statement and has been accounted for as a financing. The proceeds received from GECF are recorded as debt in our consolidated balance sheet. The power plant assets will be depreciated over their estimated useful life, and the lease payments will be applied to principal and interest expense using the effective interest method until such time as our continuing involvement is removed, expires or is otherwise eliminated. Once we no longer have significant continuing involvement in the power plant assets, the legal sale will be recognized for accounting purposes and the underlying lease will be evaluated and classified in accordance with SFAS No. 13, “Accounting for Leases.”

Pursuant to the applicable transaction agreements, each of Calpine Fox, LLC and Calpine Fox Holdings, LLC, has been established as an entity with its existence separate from us and our other subsidiaries. We consolidate these entities. The following tables set forth the assets and liabilities of Calpine Fox, LLC and Calpine Fox Holdings, LLC, respectively, as of December 31, 2005 (in thousands):


	Calpine Fox, LLC and
	Calpine Fox Holdings, LLC
	2005

Assets	$	429,412
Liabilities	$	365,985

See Note 21 of the Notes to Consolidated Financial Statements for further information.

On March 31, 2005, Deer Park, our indirect, wholly owned subsidiary, entered into an agreement to sell power to and buy gas from MLCI. To assure performance under the agreements, Deer Park granted MLCI a collateral interest in the Deer Park Energy Center. The agreement covers 650 MW of Deer Park’s capacity, and deliveries under the agreement began on April 1, 2005 and will continue through December 31, 2010. Under the terms of the agreements, Deer Park sells power to MLCI at a discount to prevailing market prices at the time the agreements were executed. Deer Park received an initial cash payment of $195.8 million, net of $17.3 million in transaction costs during the first quarter of 2005, and subsequently received additional cash payments of $76.4 million, net of $2.9 million in transaction costs, as additional power transactions were executed with discounts to prevailing market prices. Under the terms of the gas agreements, Deer Park will receive quantities of gas such that, when combined with fuel supply provided by Deer Park’s steam host, Deer Park will have sufficient contractual fuel supply to meet the fuel needs required to generate the power under the power agreements.

Pursuant to the applicable transaction agreements, Deer Park has been established as an entity with its existence separate from us and other subsidiaries of ours. We consolidate this entity. The following table sets forth the assets and liabilities of Deer Park as of December 31, 2005 (in thousands):


	2005

Assets	$	560,805
Liabilities	$	366,032

See Note 29 of the Notes to Consolidated Financial Statements for further information.

On October 14, 2005, our indirect subsidiary, CCFCP, issued $300.0 million of 6-Year redeemable preferred shares. The CCFCP redeemable preferred shares are mandatorily redeemable on the maturity date and are accounted for as long-term debt and any related preferred dividends will be accounted for as interest expense in accordance with SFAS No. 150.

Pursuant to the applicable transaction agreements, CCFCP has been established as an entity with its existence separate from us and our other subsidiaries. We consolidate this entity. The following table sets forth the assets and liabilities of CCFCP as of December 31, 2005 (in thousands):


	2005

Assets	$	2,111,301
Liabilities	$	1,158,751

See Note 34 of the Notes to Consolidated Financial Statements for further information.

Metcalf Energy Center, LLC — On June 20, 2005, Metcalf consummated the sale of $155.0 million of 5.5-Year redeemable preferred shares. Concurrent with the closing Metcalf entered into a five-year, $100.0 million senior term loan. Proceeds from the senior term loan were used to refinance all outstanding indebtedness under the existing $100.0 million non-recourse construction credit facility.

Pursuant to the applicable transaction agreements, Metcalf has been established as an entity with its existence separate from us and other subsidiaries of ours. We consolidate this entity. The following table sets forth the assets and liabilities of Metcalf as of December 31, 2005 (in thousands):


	2005

Assets	$	652,985
Liabilities	$	275,762

See Note 21 of the Notes to Consolidated Financial Statements for further information.


	*Capital Spending — Development and Construction*

See Notes 6 and 7 of the Notes to Consolidated Financial Statements for a discussion of our development and construction projects at December 31, 2005.


	*Performance Metrics*

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


	•	MWh generated. We generate power that we sell to third parties. These sales are recorded as E&S revenue. The volume in MWh is a key indicator of our level of 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 average baseload capacity factor is thus a measure of total actual generation as a percent of total potential generation. If we elect not to generate during periods when electricity pricing is too low or gas prices too high to operate profitably, the baseload capacity factor will reflect that decision as well as both scheduled and unscheduled outages due to maintenance and repair requirements.

	•	Average heat rate for gas-fired fleet of power plants expressed in Btus of fuel consumed per KWh generated. We calculate the average heat rate for our gas-fired power plants (excluding peakers) by dividing (a) fuel consumed in Btu by (b) KWh generated. The resultant heat rate is a measure of fuel efficiency, so the lower the heat rate, the better. We also calculate a “steam-adjusted” heat rate, in which we adjust the fuel consumption in Btu down by the equivalent heat content in steam or other


		thermal energy exported to a third party, such as to steam hosts for our cogeneration facilities. Our goal is to have the lowest average heat rate in the industry.

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

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

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

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

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


			Years Ended December 31,

			2005			2004			2003

			(In thousands)
Operating Performance Metrics;
	MWh generated			87,431			83,412			70,856
	Average availability			91.5	%		92.6	%		91.1	%
	Average baseload capacity factor:
		Average total MW in operation		25,207			22,198			18,283
		Less: Average MW of pure peakers		2,965			2,951			2,672

		Average baseload MW in operation		22,242			19,247			15,611
		Hours in the period		8,760			8,784			8,760
		Potential baseload generation (MWh)		194,840			169,066			136,752
		Actual total generation (MWh)		87,431			83,412			70,856
		Less: Actual pure peakers’ generation (MWh)		1,893			1,453			1,290

		Actual baseload generation (MWh)		85,538			81,959			69,566
		Average baseload capacity factor		43.9	%		48.5	%		50.9	%
	Average heat rate for gas-fired power plants (excluding peakers)(Btu’s/ KWh):
		Not steam adjusted		8,369			8,303			8,081
		Steam adjusted		7,187			7,172			7,335


		Years Ended December 31,

		2005		2004			2003

		(In thousands)
Average all-in realized electric price:
	Electricity and steam revenue	$	6,278,840	$	5,165,347		$	4,291,173
	Spread on sales of purchased power for hedging and optimization		307,759		166,016			29,246
	Revenue related to power generation in mark-to-market activity, net		243,405		—			—

	Adjusted electricity and steam revenue	$	6,830,004	$	5,331,363		$	4,320,419
	MWh generated		87,431		83,412			70,856
	Average all-in realized electric price per MWh	$	78.12	$	63.92		$	60.97
Average cost of natural gas:
	Fuel expense	$	4,623,286	$	3,587,417		$	2,636,744
	Fuel cost elimination		8,395		18,028			61,423
	Spread on sales of purchased gas for hedging and optimization		56,921		(11,587	)		(41,334	)
	Fuel expense related to power generation in mark-to-market activity, net		189,770		—			—

	Adjusted fuel expense	$	4,878,372	$	3,593,858		$	2,656,833
	MMBtu of fuel consumed by generating plants		592,962		571,869			484,050
	Average cost of natural gas per MMBtu	$	8.23	$	6.28		$	5.49
	MWh generated		87,431		83,412			70,856
	Average cost of adjusted fuel expense per MWh	$	55.80	$	43.09		$	37.50
Average spark spread:
	Adjusted electricity and steam revenue	$	6,830,004	$	5,331,363		$	4,320,419
	Less: Adjusted fuel expense		4,878,372		3,593,858			2,656,833

	Spark spread	$	1,951,632	$	1,737,505		$	1,663,586
	MWh generated		87,431		83,412			70,856
	Average spark spread per MWh	$	22.32	$	20.83		$	23.48
Average plant operating expense (POX) per actual MWh:
	Plant operating expense (POX)	$	717,393	$	727,911		$	599,325
	POX per actual MWh	$	8.21	$	8.73		$	8.46

The table below provides additional detail of total mark-to-market activity. For the years ended December 31, 2005, 2004 and 2003, mark-to-market activity, net consisted of (dollars in thousands):


					Years Ended December 31,

					2005			2004			2003

					(In thousands)
Realized:
	Power activity
		“Trading Activity” as defined in EITF Issue No. 02-03			$	297,893		$	52,262		$	52,559
		Other mark-to-market activity(1)				(13,372	)		(12,158	)		(26,059	)

			Total realized power activity		$	284,521		$	40,104		$	26,500

	Gas activity
		“Trading Activity” as defined in EITF Issue No. 02-03			$	(177,752	)	$	8,025		$	(2,166	)
		Other mark-to-market activity(1)				(286	)		—			—

			Total realized gas activity		$	(178,038	)	$	8,025		$	(2,166	)

Total realized activity:
	“Trading Activity” as defined in EITF Issue No. 02-03				$	120,141		$	60,287		$	50,393
		Other mark-to-market activity(1)				(13,658	)		(12,158	)		(26,059	)

			Total realized activity		$	106,483		$	48,129		$	24,334

Unrealized:
	Power activity
		“Trading Activity” as defined in EITF Issue No. 02-03			$	(85,860	)	$	(18,075	)	$	(55,450	)
		Ineffectiveness related to cash flow hedges				(4,638	)		1,814			(5,001	)
		Other mark-to-market activity(1)				6,393			(13,591	)		(1,243	)

			Total unrealized power activity		$	(84,105	)	$	(29,852	)	$	(61,694	)

	Gas activity
		“Trading Activity” as defined in EITF Issue No. 02-03			$	(9,042	)	$	(10,700	)	$	7,768
		Ineffectiveness related to cash flow hedges				(1,951	)		5,827			3,153
		Other mark-to-market activity(1)				—			—			—

			Total unrealized gas activity		$	(10,993	)	$	(4,873	)	$	10,921

Total unrealized activity:
	“Trading Activity” as defined in EITF Issue No. 02-03				$	(94,902	)	$	(28,775	)	$	(47,682	)
	Ineffectiveness related to cash flow hedges					(6,589	)		7,641			(1,848	)
	Other mark-to-market activity(1)					6,393			(13,591	)		(1,243	)

				Total unrealized activity	$	(95,098	)	$	(34,725	)	$	(50,773	)

Total mark-to-market activity:
	“Trading Activity” as defined in EITF Issue No. 02-03				$	25,239		$	31,512		$	2,711
	Ineffectiveness related to cash flow hedges					(6,589	)		7,641			(1,848	)
	Other mark-to-market activity(1)					(7,265	)		(25,749	)		(27,302	)

			Total mark-to-market activity		$	11,385		$	13,404		$	(26,439	)


(1)	Activity related to our assets but does not qualify for hedge accounting.


	*Strategy*

For a discussion of our strategy and management’s outlook, see “Item 1 — Business — Strategy.”


	*Financial Market Risks*

As we are primarily focused on generation of electricity using gas-fired turbines, our natural physical commodity position is “short” fuel (i.e., natural gas consumer) and “long” power (i.e., electricity seller). To manage forward exposure to price fluctuation in these and (to a lesser extent) other commodities, we enter into derivative commodity instruments as discussed in Item 1. “Business — Marketing, Hedging, Optimization and Trading Activities.”

The change in fair value of outstanding commodity derivative instruments from January 1, 2005, through December 31, 2005, is summarized in the table below (in thousands):


Fair value of contracts outstanding at January 1, 2005	$	37,863
Cash losses recognized or otherwise settled during the period(1)		79,265
Non-cash gains recognized or otherwise settled during the period(2)		44,979
Changes in fair value attributable to new contracts(3)		(344,520	)
Changes in fair value attributable to price movements		(267,112	)
Terminated derivatives		9,711

Fair value of contracts outstanding at December 31, 2005(4)	$	(439,814	)

Realized cash flow from fair value hedges(5)	$	346,733


(1)	Realized losses from cash flow hedges and mark-to-market activity are reflected in the tables below (in millions):


Realized value of commodity cash flow hedges reclassified from OCI(a)		$	(384.4	)
Net of:
	Terminated and monetized derivatives		(29.2	)
	Equity method hedges		—
	Hedges reclassified to discontinued operations		(199.4	)

	Cash losses realized from cash flow hedges		(155.8	)

Realized value of mark-to-market activity(b)			106.5
Net of:
	Non-cash realized mark-to-market activity		30.0

	Cash gains realized on mark-to-market activity		76.5

	Cash losses recognized or otherwise settled during the period	$	(79.3	)


	(a)	Realized value as disclosed in Note 29 of the Notes to Consolidated Condensed Financial Statements.

	(b)	Realized value as reported in Management’s discussion and analysis of operating performance metrics.


(2)	This represents the non-cash amortization of deferred items embedded in our derivative assets and liabilities.

(3)	The change attributable to new contracts includes the $284.2 million derivative liability associated with a transaction by our Deer Park facility as discussed in Note 29 of the Notes to Consolidated Condensed Financial Statements.


(4)	Net commodity derivative liabilities reported in Note 29 of the Notes to Consolidated Condensed Financial Statements.

(5)	Not included as part of the roll-forward of net derivative assets and liabilities because changes in the hedge instrument and hedged item move in equal and offsetting directions to the extent the fair value hedges are perfectly effective.

The fair value of outstanding derivative commodity instruments at December 31, 2005, based on price source and the period during which the instruments will mature, are summarized in the table below (in thousands):


Fair Value Source		2006			2007-2008			2009-2010			After 2010			Total

Prices actively quoted		$	(31,275	)	$	1,483		$	—		$	—		$	(29,792	)
Prices provided by other external sources			(206,744	)		(90,747	)		(34,418	)		—			(331,909	)
Prices based on models and other valuation methods			—			(30,707	)		(47,383	)		(23	)		(78,113	)

	Total fair value	$	(238,019	)	$	(119,971	)	$	(81,801	)	$	(23	)	$	(439,814	)

Our risk managers maintain fair value price information derived from various sources in our risk management systems. The propriety of that information is validated by our Risk Control group. Prices actively quoted include validation with prices sourced from commodities exchanges (e.g., New York Mercantile Exchange). Prices provided by other external sources include quotes from commodity brokers and electronic trading platforms. Prices based on models and other valuation methods are validated using quantitative methods. See “Critical Accounting Policies” for a discussion of valuation estimates used where external prices are unavailable.

The counterparty credit quality associated with the fair value of outstanding derivative commodity instruments at December 31, 2005, and the period during which the instruments will mature are summarized in the table below (in thousands):


Credit Quality
(Based on Standard & Poor’s Ratings as of
December 31, 2005)		2006			2007-2008			2009-2010			After 2010			Total

Investment grade		$	(217,717	)	$	(115,588	)	$	(80,475	)	$	(23	)	$	(413,803	)
Non-investment grade			(18,324	)		(2,715	)		(1,326	)		—			(22,365	)
No external ratings			(1,978	)		(1,668	)		—			—			(3,646	)

	Total fair value	$	(238,019	)	$	(119,971	)	$	(81,801	)	$	(23	)	$	(439,814	)

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


						Fair Value After
						10% Adverse
			Fair Value			Price Change

At December 31, 2005:
	Electricity		$	(628,386	)	$	(760,216	)
	Natural gas			188,572			163,509

		Total	$	(439,814	)	$	(596,707	)

Derivative commodity instruments included in the table are those included in Note 29 of the Notes to Consolidated Financial Statements. The fair value of derivative commodity instruments included in the table is based on present value adjusted quoted market prices of comparable contracts. The fair value of electricity derivative commodity instruments after a 10% adverse price change includes the effect of increased power prices versus our derivative forward commitments. Conversely, the fair value of the natural gas derivatives after a 10% adverse price change reflects a general decline in gas prices versus our derivative forward

commitments. Derivative commodity instruments offset the price risk exposure of our physical assets. None of the offsetting physical positions are included in the table above.

Price changes were calculated by assuming an across-the-board ten percent adverse price change regardless of term or historical relationship between the contract price of an instrument and the underlying commodity price. In the event of an actual ten percent change in prices, the fair value of our derivative portfolio would typically change by more than ten percent for earlier forward months and less than ten percent for later forward months because of the higher volatilities in the near term and the effects of discounting expected future cash flows.

The primary factors affecting the fair value of our derivatives at any point in time are (1) the volume of open derivative positions (MMBtu and MWh), and (2) changing commodity market prices, principally for electricity and natural gas. The total volume of open gas derivative positions increased 16% from December 31, 2004, to December 31, 2005, and the total volume of open power derivative positions increased 64% for the same period. In that prices for electricity and natural gas are among the most volatile of all commodity prices, there may be material changes in the fair value of our derivatives over time, driven both by price volatility and the changes in volume of open derivative transactions. Under SFAS No. 133, the change since the last balance sheet date in the total value of the derivatives (both assets and liabilities) is reflected either in OCI, net of tax, or in the statement of operations as an item (gain or loss) of current earnings. As of December 31, 2005, a significant component of the balance in accumulated OCI represented the unrealized net loss associated with commodity cash flow hedging transactions. As noted above, there is a substantial amount of volatility inherent in accounting for the fair value of these derivatives, and our results during the year ended December 31, 2005, have reflected this. See Note 29 of the Notes to Consolidated Financial Statements for additional information on derivative activity.

Interest Rate Swaps — From time to time, we use interest rate swap agreements to mitigate our exposure to interest rate fluctuations associated with certain of our debt instruments and to adjust the mix between fixed and floating rate debt in our capital structure to desired levels. We do not use interest rate swap agreements for speculative or trading purposes. The following tables summarize the fair market values of our existing interest rate swap agreements as of December 31, 2005 (dollars in thousands):


	Variable to Fixed Swaps


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

2007		$	56,757		4.5	%		3-month US$LIBOR	$	451
2007			284,768		4.5	%		3-month US$LIBOR		2,289
2009			38,454		4.4	%		3-month US$LIBOR		420
2009			192,937		4.4	%		3-month US$LIBOR		2,105
2009			50,000		4.8	%		3-month US$LIBOR		(60	)
2011			37,563		4.9	%		3-month US$LIBOR		(155	)
2011			24,695		4.8	%		3-month US$LIBOR		(72	)
2011			18,802		4.8	%		3-month US$LIBOR		(36	)
2011			18,782		4.9	%		3-month US$LIBOR		(77	)
2011			18,782		4.9	%		3-month US$LIBOR		(77	)
2011			18,802		4.8	%		3-month US$LIBOR		(36	)
2011			18,782		4.9	%		3-month US$LIBOR		(77	)
2011			18,802		4.8	%		3-month US$LIBOR		(36	)
2012			100,926		6.5	%		3-month US$LIBOR		(6,486	)
2016			20,100		7.3	%		3-month US$LIBOR		(2,592	)

	Total	$	918,952		4.8	%			$	(4,439	)

Certain of our interest rate swaps were designated as cash flow hedges of debt instruments that became subject to compromise as a result of our bankruptcy filings beginning on December 20, 2005. Consequently, such interest rate swaps no longer were effective hedges and we began to recognize changes in their fair value through earnings rather than through OCI.

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


	Fair Value After a 1.0%
	(100 Basis Points) Adverse
Net Fair Value as of December 31, 2005	Interest Rate Change

$(4,439)	$	(38,848	)

Variable Rate Debt Financing — We have used debt financing to meet the significant capital requirements needed to fund our growth. Certain debt instruments related to our non-debtor entities and debt instruments not considered subject to compromise at December 31, 2005, may affect us adversely because of changes in market conditions. Our variable rate financings are indexed to base rates, generally LIBOR, as shown below. Significant LIBOR increases could have a negative impact on our future interest expense.

On December 20, 2005, we entered into a $2.0 billion DIP Facility, which, as amended, is comprised of a $1.0 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; and a $600 million second-priority term loan, priced at LIBOR plus 400 basis points. The DIP Facility will be used to fund our operations during our Chapter 11 restructuring. It will remain in place until the earlier of an effective plan of reorganization or December 20, 2007. At December 31, 2005, the DIP Facility had a balance of $25.0 million. See Note 22 of the Notes to Consolidated Financial Statements for more information.

See Note 21 of the Notes to Consolidated Financial Statements for information on our construction/project financing instruments.

The following table summarizes our variable-rate debt, by repayment year, exposed to interest rate risk as of December 31, 2005. All outstanding balances and fair market values are shown net of applicable premium or discount, if any (dollars in thousands):


													Fair Value
											2010 and		December 31,
			2006		2007		2008		2009		Thereafter		2005

3-month US $LIBOR weighted average interest rate basis(3)
	Riverside Energy Center project financing		$	3,685	$	3,685	$	3,685	$	3,685	$	340,553	$	355,293
	Rocky Mountain Energy Center project financing			2,649		2,649		2,649		2,649		235,276		245,872

		Total of 3-month US $LIBOR rate debt		6,334		6,334		6,334		6,334		575,829		601,165
1-month US $LIBOR interest rate basis(3)
	Freeport Energy Center, LP project financing			—		2,528		2,323		2,054		156,698		163,603
	Mankato Energy Center, LLC project financing			—		2,222		2,292		1,969		144,747		151,230

		Total of 1-month US $LIBOR interest rate		—		4,750		4,615		4,023		301,445		314,833

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														Fair Value
												2010 and		December 31,
				2006		2007		2008		2009		Thereafter		2005

(1)(3)
	Metcalf Energy Center, LLC preferred interest				—		—		—		—		155,000		155,000
	Third Priority Secured Floating Rate Notes Due 2011 (CalGen)				—		—		—		—		680,000		680,000
	Second Priority Senior Secured Floating Rate Notes Due 2011 (CCFC)				—		—		—		—		409,539		409,539
	CCFC Preferred Holdings, LLC preferred interest				—		—		—		—		300,000		300,000

		Total of variable rate debt as defined at(1) below			—		—		—		—		1,544,539		1,544,539
(2)(3)
	Blue Spruce Energy Center project financing				3,750		3,750		3,750		3,750		81,395		96,395

		Total of variable rate debt as defined at(2) below			3,750		3,750		3,750		3,750		81,395		96,395
(4)(3)
	First Priority Secured Floating Rate Notes Due 2009 (CalGen)				—		1,175		2,350		231,475		—		235,000
	First Priority Secured Institutional Term Loans Due 2009 (CalGen)				—		3,000		6,000		591,000		—		600,000
	First Priority Senior Secured Institutional Term Loan Due 2009 (CCFC)				3,208		3,208		3,208		365,350		—		374,974
	DIP Facility				—		25,000		—		—		—		25,000
	Second Priority Secured Institutional Floating Rate Notes Due 2010 (CalGen)				—		—		3,200		6,400		623,639		633,239
	Second Priority Secured Term Loans Due 2010 (CalGen)				—		—		500		1,000		97,444		98,944
	Metcalf Energy Center, LLC project financing				—		—		—		—		100,000		100,000

		Total of variable rate debt as defined at (4) below			3,208		32,383		15,258		1,195,225		821,083		2,067,157
(5)(4)
	Contra Costa				171		179		187		196		1,381		2,114

		Total of variable rate debt as defined at (5) below			171		179		187		196		1,381		2,114

			Grand total variable-rate debt instruments	$	13,463	$	47,396	$	30,144	$	1,209,528	$	3,325,672	$	4,626,203


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

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

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

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

(5)	Bankers Acceptance Rate.

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	*Application of Critical Accounting Policies*

Our financial statements reflect the selection and application of accounting policies which require management to make significant estimates and judgments. See Note 2 of the Notes to Consolidated Financial Statements, “Summary of Significant Accounting Policies.” We believe that the following reflect the more critical accounting policies that currently affect our financial condition and results of operations.


	Financial Reporting Under Bankruptcy

GAAP reporting for debtor entities during bankruptcy is governed by AICPA Statement of Position 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code,” which provides for:


	•	Reclassification of unsecured or under-secured pre-petition liabilities to a separate line item in the balance sheet which we have called Liabilities Subject to Compromise or LSTC;

	•	Non-accrual of interest expense for financial reporting purposes, to the extent not paid during bankruptcy and not expected to be an allowed claim. However, unpaid contractual interest is calculated for disclosure purposes.

	•	Adjust any unamortized deferred financing costs and discounts/premiums associated with debt classified as LSTC to reflect the expected amount of the probable allowed claim. As a result of applying this guidance, we have written off approximately $148.1 million for the year ended December 31, 2005, as a charge to reorganization items related to certain debt instruments deemed subject to compromise, in order to reflect this debt at the amount of the probable allowed claim;

	•	Segregation of reorganization items (direct and incremental costs, such as professional fees, of being in bankruptcy) as a separate line item in the statement of operations outside of income from continuing operations;

	•	Evaluation of actual or potential bankruptcy claims, which are not already reflected as a liability on the balance sheet, under SFAS No. 5, “Accounting for Contingencies.” Due to the close proximity of our bankruptcy filing date to our fiscal year-end date, we have been presented with only a limited number of significant claims meeting the SFAS No. 5 criteria (probable and can be reasonably estimated) to be accrued at December 31, 2005, the most significant of which we expect could total approximately $3.8 billion related to U.S. parent guarantees of our deconsolidated Canadian subsidiary debt. If valid unrecorded claims, including parent guarantees of subsidiary debt, meeting the SFAS No. 5 criteria are presented to us in future periods, we would accrue for these amounts, also at the expected amount of the allowed claim rather than at the expected settlement amount.

	•	Disclosure of condensed combined debtor entity financial information, if the consolidated financial statements include material subsidiaries that did not file for bankruptcy protection.

	•	Upon confirmation by the Bankruptcy Court of our plan of reorganization, and our emergence from Chapter 11 reorganization, “fresh-start reporting” must be adopted if the reorganization value of our assets immediately before the date of confirmation is less than the total of all post-petition liabilities and allowed claims, and if holders of existing voting shares immediately before confirmation receive less than 50 percent of the voting shares of the emerging entity. Essentially, the reorganization value of the entity, as mutually agreed to by the debtor-in-possession and its creditors, would be allocated to the entity’s assets in conformity with the procedures specified by SFAS No. 141, “Business Combinations”.

We are required to exercise considerable judgment in the evaluation of potential claims that will ultimately be allowable against the Company while in bankruptcy. Such claims remain subject to future adjustments. Adjustments may result from negotiations, actions of the Bankruptcy Courts, rejection of executory contracts and unexpired leases, and the determination as to the value of any collateral securing claims, proofs of claim or other events. We expect that the liabilities of the Calpine Debtors will exceed the fair value of their assets. This is expected to result in claims being paid at less than 100% of their face value, and the equity of Calpine’s stockholders could be diluted or eliminated entirely. In addition, the claims bar date — the date by which claims against the Calpine Debtors must be filed with the Bankruptcy Courts — have been scheduled for August 1, 2006, by the U.S. Bankruptcy Court with respect to claims against

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U.S. Debtors and June 30, 2006, by the Canadian Court with respect to claims against the Canadian Debtors. Accordingly, not all potential claims would have been filed as of December 31, 2005. We expect that additional claims will be filed against the U.S. and Canadian Debtors prior to the applicable claims bar date, however, the amounts of such claims cannot be estimated at this time. Any claims filed may result in additional liabilities, some or all of which may be subject to compromise, and the amounts of which may be material to us. In addition, it is likely that certain creditors may assert claims on multiple bases against multiple Calpine Debtor entities, resulting in a total overall claims pool significantly in excess of the amount of the Calpine Debtors’ potential liabilities. However, despite the likelihood that there will be bankruptcy claims asserted against the collective Calpine Debtors in excess of their potential liabilities, no individual creditor should receive more than 100% recovery on account of such multiple claims.

The most significant judgments that we have made in preparing the financial statements for the year ended December 31, 2005, have related to the evaluation of potential claims by our deconsolidated entities in Canada and their respective creditors. Many of these deconsolidated Canadian entities were granted relief in Canada under the CCAA at the same time that Calpine and many of its U.S. based subsidiaries filed for bankruptcy protection in the United States. We determined that pursuant to direct guarantees by Calpine (and a U.S. subsidiary) of funded debt owed by Canadian subsidiaries, or pursuant to other related support obligations, there were approximately $5.1 billion of probable allowable claims against the U.S. parent entities. While some of the guarantee exposures are redundant, SOP 90-7 specifies that “liabilities that may be affected by the plan should be reported at the amounts expected to be allowed, even if they may be settled for lesser amounts.” We concluded that, at this early stage in the proceedings, we should assume that it was probable that such claims would be allowed into the claim pool by the U.S. Bankruptcy Court notwithstanding that we may object to the presentation of multiple claims that we believe are essentially related to a single obligation.

We also were required to exercise judgment in evaluating which of our consolidated pre-petition debt instruments were under-secured. Based on the guidance in SOP 90-7 the Calpine Debtors are required to record as LSTC unsecured and under-secured liabilities incurred prior to the Petition Date and exclude liabilities that are fully secured or liabilities of our subsidiaries or affiliates that have not made bankruptcy filings. Based upon our assessment of the value of our assets compared to our liabilities, we concluded that our second priority senior notes, which have an aggregate outstanding pre-petition balance of approximately $3.7 billion, were under-secured. We also evaluated all of our subsidiaries with project financings and concluded that only our Aries subsidiary, which is a U.S. Debtor and has an outstanding pre-petition project financing balance of approximately $0.2 billion, has under-secured debt. Consequently, both that project financing and our second priority senior notes were classified as LSTC at December 31, 2005.


	Fair Value of Energy Marketing and Risk Management Contracts and Derivatives

Accounting for derivatives at fair value requires us to make estimates about future prices during periods for which price quotes are not available from sources external to us. As a result, we are required to rely on internally developed price estimates when external quotes are unavailable. We derive our future price estimates, during periods, where external price quotes are unavailable, based on extrapolation of prices from prior periods where external price quotes are available. We perform this extrapolation by using liquid and observable market prices and extending those prices to an internally generated long-term price forecast based on a generalized equilibrium model.


	*Credit Reserves*

In estimating the fair value of our derivatives, we must take into account the credit risk that our counterparties will not have the financial wherewithal to honor their contract commitments.

In establishing credit risk reserves we take into account historical default rate data published by the rating agencies based on the credit rating of each counterparty where we have realization exposure, as well as other published data and information.

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	*Liquidity Reserves*

We value our forward positions at the mid-market price, or the price in the middle of the bid-ask spread. This creates a risk that the value reported by us as the fair value of our derivative positions will not represent the realizable value or probable loss exposure of our derivative positions if we are unable to liquidate those positions at the mid-market price. Adjusting for this liquidity risk states our derivative assets and liabilities at their most probable value. We use a two-step quantitative and qualitative analysis to determine our liquidity reserve.

In the first step we calculate the net notional volume exposure at each location by commodity and multiply the result by one half of the bid-ask spread by applying the following assumptions: (1) where we have the capability to cover physical positions with our own assets, we assume no liquidity reserve is necessary because we will not have to cross the bid-ask spread in covering the position; (2) we record no reserve against our hedge positions because a high likelihood exists that we will hold our hedge positions to maturity or cover them with our own assets; and (3) where reserves are necessary, we base the reserves on the spreads observed using broker quotes as a starting point.

The second step involves a qualitative analysis where the initial calculation may be adjusted for factors such as liquidity spreads observed through recent trading activity, strategies for liquidating open positions, and imprecision in or unavailability of broker quotes due to market illiquidity. Using this information, we estimate the amount of probable liquidity risk exposure to us and we record this estimate as a liquidity reserve.


	Accounting for Commodity Contracts

Commodity contracts are evaluated to determine whether the contract is (1) accounted for as a lease (2) accounted for as a derivative (3) or accounted for as an executory contract and additionally whether the financial statement presentation is gross or net.

Accounting for Leases — We account for commodity contracts as leases per SFAS No. 13, “Accounting for Leases,” and EITF Issue No. 01-08, “Determining Whether an Arrangement Contains a Lease.” EITF Issue No. 01-08 clarifies the requirements of identifying whether an arrangement should be accounted for as a lease at its inception. The guidance therein is designed to broaden the scope of arrangements, such as PPAs, accounted for as leases. EITF Issue No. 01-08 requires both parties to an arrangement to determine whether a service contract or similar arrangement is, or includes, a lease within the scope of SFAS No. 13, “Accounting for Leases.” The guidance is applied prospectively to arrangements agreed to, modified, or acquired in business combinations on or after July 1, 2003. Prior to adopting EITF Issue No. 01-08, we had accounted for certain contractual arrangements as leases under existing industry practices, and the adoption of EITF Issue No. 01-08 did not materially change our accounting for leases. Per SFAS No. 13, “Accounting for Leases,” operating leases with minimum lease rentals which vary over time must be levelized over the term of the contract. We levelize these contracts on a straight-line basis. See Note 31 for additional information on our operating leases. For income statement presentation purposes, income from arrangements accounted for as leases is classified within E&S revenue in our consolidated statements of operations.

Accounting for Derivatives — On January 1, 2001, we adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 137, “Accounting for Derivative Instruments and Hedging Activities — Deferral of the Effective Date of FASB Statement No. 133 — an Amendment of FASB Statement No. 133,” SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities — an Amendment of FASB Statement No. 133,” and SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” We currently hold six classes of derivative instruments that are impacted by the new pronouncements — foreign currency swaps, interest rate swaps, forward interest rate agreements, commodity financial instruments, commodity contracts, and physical options.

Consistent with the requirements of SFAS No. 133, we evaluate all of our contracts to determine whether or not they qualify as derivatives under the accounting pronouncements. For a given contract, there are typically three steps we use to determine its proper accounting treatment. First, based on the terms and

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conditions of the contract, as well as the applicable guidelines established by SFAS No. 133, we identify the contract as being either a derivative or non-derivative contract. Second, if the contract is not a derivative, we account for it as an executory contract. Alternatively, if the contract does qualify as a derivative under the guidance of SFAS No. 133, we evaluate whether or not it qualifies for the “normal” purchases and sales exception (as described below). If the contract qualifies for the exception, we may elect to apply the normal exception and account for it as an executory contract. Finally, if the contract is a derivative, we apply the accounting treatment required by SFAS No. 133, which is outlined below in further detail.


	*Normal Purchases and Sales*

When we elect normal purchases and sales treatment, as defined by paragraph 10b of SFAS No. 133 and amended by SFAS No. 138 and SFAS No. 149, the normal contracts are exempt from SFAS No. 133 accounting treatment. As a result, these contracts are not required to be recorded on the balance sheet at their fair values and any fluctuations in these values are not required to be reported within earnings. Probability of physical delivery from our generation plants, in the case of electricity sales, and to our generation plants, in the case of natural gas contracts, is required over the life of the contract within reasonable tolerances.

Two of our contracts that had been accounted for as normal contracts were subject to the special transition adjustment for their estimated future economic benefits upon adoption of DIG Issue No. C20, and we amortize the corresponding asset recorded upon adoption of DIG Issue No. C20 through a charge to earnings. Accordingly on October 1, 2003, the date we adopted DIG Issue No. C20, we recorded other current assets and other assets of approximately $33.5 million and $259.9 million, respectively, and a gain due to the cumulative effect of a change in accounting principle of approximately $181.9 million, net of $111.5 million of tax. For periods subsequent to October 1, 2003, we again account for these two contracts as normal purchases and sales under the provisions of DIG Issue No. C20.


	*Fair Value Hedges*

As further defined in SFAS No. 133, fair value hedge transactions hedge the exposure to changes in the fair value of either all or a specific portion of a recognized asset or liability or of an unrecognized firm commitment. The accounting treatment for fair value hedges requires reporting both the changes in fair values of a hedged item (the underlying risk) and the hedging instrument (the derivative designated to offset the underlying risk) on both the balance sheet and the income statement. On that basis, when a firm commitment is associated with a hedge instrument that attains 100% effectiveness (under the effectiveness criteria outlined in SFAS No. 133), there is no net earnings impact because the earnings caused by the changes in fair value of the hedged item will move in an equal, but opposite, amount as the earnings caused by the changes in fair value of the hedging instrument. In other words, the earnings volatility caused by the underlying risk factor will be neutralized because of the hedge. For example, if we want to manage the price-induced fair value risk (i.e. the risk that market electric rates will rise, making a fixed price contract less valuable) associated with all or a portion of a fixed price power sale that has been identified as a “normal” transaction (as described above), we might create a fair value hedge by purchasing fixed price power. From that date and time forward until delivery, the change in fair value of the hedged item and hedge instrument will be reported in earnings with asset/liability offsets on the balance sheet. If there is 100% effectiveness, there is no net earnings impact. If there is less than 100% effectiveness, the fair value change of the hedged item (the underlying risk) and the hedging instrument (the derivative) will likely be different and the “ineffectiveness” will result in a net earnings impact.


	*Cash Flow Hedges*

As further defined in SFAS No. 133, cash flow hedge transactions hedge the exposure to variability in expected future cash flows (i.e., in our case, the price variability of forecasted purchases of gas and sales of power, as well as interest rate and foreign exchange rate exposure). In the case of cash flow hedges, the hedged item (the underlying risk) is generally unrecognized (i.e., not recorded on the balance sheet prior to delivery), and any changes in this fair value, therefore, will not be recorded within earnings. Conceptually, if a cash flow hedge is effective, this means that a variable, such as movement in power prices, has been effectively

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fixed, so that any fluctuations will have no net result on either cash flows or earnings. Therefore, if the changes in fair value of the hedged item are not recorded in earnings, then the changes in fair value of the hedging instrument (the derivative) must also be excluded from the income statement, or else a one-sided net impact on earnings will be reported, despite the fact that the establishment of the effective hedge results in no net economic impact. To prevent such a scenario from occurring, SFAS No. 133 requires that the fair value of a derivative instrument designated as a cash flow hedge be recorded as an asset or liability on the balance sheet, but with the offset reported as part of OCI, to the extent that the hedge is effective. Similar to fair value hedges, any ineffectiveness portion will be reflected in earnings.


	*Undesignated Derivatives*

The fair values and changes in fair values of undesignated derivatives are recorded in earnings, with the corresponding offsets recorded as derivative assets or liabilities on the balance sheet. We have the following types of undesignated transactions:


	•	transactions executed at a location where we do not have an associated natural long (generation capacity) or short (fuel consumption requirements) position of sufficient quantity for the entire term of the transaction (e.g., power sales where we do not own generating assets or intend to acquire transmission rights for delivery from other assets for any portion of the contract term),

	•	transactions executed with the intent to profit from short-term price movements,

	•	discontinuance (de-designation) of hedge treatment prospectively consistent with paragraphs 25 and 32 of SFAS No. 133; in circumstances where we believe the hedge relationship is no longer necessary, we will remove the hedge designation and close out the hedge positions by entering into an equal and offsetting derivative position. Prospectively, the two derivative positions should generally have no net earnings impact because the changes in their fair values are offsetting, and

	•	any other transactions that do not qualify for hedge accounting.

Our mark-to-market Activity includes realized settlements of and unrealized mark-to-market gains and losses on both power and gas derivative instruments not designated as cash flow hedges, including those held for trading purposes. Our gains and losses due to ineffectiveness on hedging instruments are also included in unrealized mark-to-market gains and losses. We present trading activity net in accordance with EITF Issue No. 02-03.

Accounting for Executory Contracts — Where commodity contracts do not qualify as leases or derivatives, the contracts are classified as executory contracts. These contracts apply traditional accrual accounting treatment unless the revenue must be levelized per EITF Issue No. 91-06, “Revenue Recognition of Long Term Power Sales Contracts.” We currently account for one commodity contract under EITF 91-06 which is levelized over the term of the agreement.

Accounting for Financial Statement Presentation — Where our derivative instruments are subject to a netting agreement and the criteria of FIN 39 “Offsetting of Amounts Related to Certain Contracts (An Interpretation of APB Opinion No. 10 and SFAS No. 105)” are met, we present the derivative assets and liabilities on a net basis in our balance sheet. We chose this method of presentation because it is consistent with the way related mark-to-market gains and losses on derivatives are recorded in Consolidated Statements of Operations and within Other Comprehensive Income.

We account for certain of our power sales and purchases on a net basis under EITF Issue No. 03-11 “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to SFAS No. 133 and Not ‘Held for Trading Purposes’ As Defined in 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,’ ” which we adopted on a prospective basis on October 1, 2003. Transactions with either of the following characteristics are presented net in our consolidated financial statements: (1) transactions executed in a back-to-back buy and sale pair, primarily because of market protocols; and (2) physical power purchase and sale transactions where our power schedulers net the physical flow of the power purchase

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against the physical flow of the power sale (or “book out” the physical power flows) as a matter of scheduling convenience to eliminate the need for actual power delivery. These book out transactions may occur with the same counterparty or between different counterparties where we have equal but offsetting physical purchase and delivery commitments.


	*Accounting for Long-Lived Assets*


	Plant Useful Lives

Property, plant and equipment is stated at cost. The cost of renewals and betterments that extend the useful life of property, plant and equipment are also capitalized. Depreciation is recorded utilizing the straight line method over the estimated original composite useful life, generally 35 years for baseload power plants and 40 years for peaking facilities, exclusive of the estimated salvage value, typically 10%.


	Impairment of Long-Lived Assets, Including Intangibles and Investments

We evaluate long-lived assets, such as property, plant and equipment, equity method investments, patents, and specifically identifiable intangibles, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Factors which could trigger an impairment include determination that a suspended project is not likely to be completed, significant underperformance relative to historical or projected future operating results, significant changes in the manner of our use of the acquired assets or the strategy for our overall business and significant negative industry or economic trends. Certain of our generating assets are located in regions with depressed demand and market spark spreads. Our forecasts assume that spark spreads will increase in future years in these regions as the supply and demand relationships improve.

Capitalized development and construction project costs are charged to expense if we determine that a development or construction project is no longer probable of being completed such that all capitalized costs will be recovered through future operations or to the extent it is impaired under the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” We evaluate the impairment of long-lived assets, including construction and development projects, based on the projection of undiscounted pre-interest expense and pre-tax expense cash flows over the expected lifetime of the asset whenever events or changes in circumstances indicate that the carrying amounts of such assets may not be recoverable. The significant assumptions that we use in our undiscounted future cash flow estimates include the future supply and demand relationships for electricity and natural gas, the expected pricing for those commodities, likelihood of continued development and the resultant spark spreads in the various regions where we generate electricity. If management concludes that it is more likely than not that an operating power plant will be disposed of or abandoned, we do an evaluation of the probability-weighted expected future cash flows, giving consideration to both (1) the continued ownership and operation of the power plant and (2) consummating a sale disposition or abandonment of the plant. In the event such cash flows are not expected to be sufficient to recover the recorded value of the assets, the assets are written down to their estimated fair values. Certain of our generating assets are located in regions with depressed demands and market spark spreads. Our forecasts assume that spark spreads will increase in future years in these regions as the supply and demand relationships improve.

For equity method investments and assets identified as held for sale, the book value is compared to the estimated fair value to determine if an impairment loss is required. For equity method investments, we would record a loss when the decline in value is other than temporary.

Our assessment regarding the existence of impairment factors is based on market conditions, operational performance and legal factors of our businesses. Our review of factors present and the resulting appropriate carrying value of our intangibles, and other long-lived assets are subject to judgments and estimates that management is required to make. Future events could cause us to conclude that impairment indicators exist and that our intangibles, and other long-lived assets might be impaired.

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See Note 6 of the Notes to the Consolidated Financial Statements for a complete discussion of impairment charges recorded for the year ended December 31, 2005.


	Turbine Impairment Charges

A significant portion of our overall cost of constructing a power plant is the cost of the gas turbine-generators, steam turbine-generators and related equipment (which we collectively refer to here as the “turbines”). The turbines are ordered primarily from three large manufacturers under long-term, build to order contracts. Payments are generally made over a two to four year period for each turbine. The turbine prepayments are included as a component of construction-in-progress if the turbines are assigned to specific projects probable of being built, and interest is capitalized on such costs. Turbines assigned to specific projects are not evaluated for impairment separately from the project as a whole. Prepayments for turbines that are not assigned to specific projects that are probable of being built are carried in other assets, and interest is not capitalized on such costs. Additionally, our commitments relating to future turbine payments are discussed in Note 31 of the Notes to Consolidated Financial Statements.

In assessing the impairment of turbines, we must determine both the realizability of the progress payments to date that have been capitalized, as well as the probability that at future decision dates, we will cancel the turbines and apply the prepayments to the cancellation charge, or will proceed and pay the remaining progress payments in accordance with the original payment schedule.

We apply SFAS No. 5, “Accounting for Contingencies,” to evaluate potential future cancellation obligations. We apply SFAS No. 144 to evaluate turbine progress payments made to date for, and the carrying value of, delivered turbines not assigned to projects. At the reporting date, if we believe that it is probable that we will elect the cancellation provisions on future decision dates, then the expected future termination payment is also expensed.

See Note 6 of the Notes to the Consolidated Financial Statements for a complete discussion of impairment charges recorded for the year ended December 31, 2005.


	Capitalized Interest

We capitalize interest using two methods: (1) capitalized interest on funds borrowed for specific construction projects and (2) capitalized interest on general corporate funds. For capitalization of interest on specific funds, we capitalize the interest cost incurred related to debt entered into for specific projects under construction or in the advanced stage of development. The methodology for capitalizing interest on general funds, consistent with paragraphs 13 and 14 of SFAS No. 34, “Capitalization of Interest Cost,” begins with a determination of the borrowings applicable to our qualifying assets. The basis of this approach is the assumption that the portion of the interest costs that are capitalized on expenditures during an asset’s acquisition period could have been avoided if the expenditures had not been made. This methodology takes the view that if funds are not required for construction then they would have been used to pay off other debt. We use our best judgment in determining which borrowings represent the cost of financing the acquisition of the assets. Historically, the primary debt instruments included in the rate calculation of interest incurred on general corporate funds have been our Senior Notes, our term loan facilities and our secured working capital revolving credit facility with adjustments made as debt is retired or new debt is issued. We filed for protection under the Bankruptcy Code on December 20, 2005, and subsequent to that date the debt instruments included in the rate calculation were the First Priority Notes and the DIP Facility. At the Petition Date, unsecured and undersecured Senior Notes and Term Loans were classified to “Liabilities Subject to Compromise” and were removed from the rate calculation for the period subsequent to the Petition Date. See Note 3 of the Notes to Consolidated Financial Statements for more information on the bankruptcy cases. The interest rate is derived by dividing the total interest cost by the average borrowings. This weighted average interest rate is applied to

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our average qualifying assets in excess of specific debt on which interest is capitalized. To qualify for interest capitalization, we must continue to make significant progress on the construction of the assets. See Note 7 of the Notes to Consolidated Financial Statements for additional information about the capitalization of interest expense.


	Accounting for Income and Other Taxes

To arrive at our worldwide income tax provision and other tax balances, significant judgment is required. In the ordinary course of a global business, there are many transactions and calculations where the ultimate tax outcome is uncertain. Some of these uncertainties arise as a consequence of the treatment of capital assets, financing transactions, multistate taxation of operations and segregation of foreign and domestic income and expense to avoid double taxation. Although we believe that our estimates are reasonable, no assurance can be given that the final tax outcome of these matters will not be different than that which is reflected in our historical tax provisions and accruals. Such differences could have a material impact on our income tax provision, other tax accounts and net income in the period in which such determination is made.

SFAS 109 requires all available evidence, both positive and negative, to be considered 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. We considered all possible sources of taxable income that may be available under the tax law to realize a tax benefit for deductible temporary differences and loss carryforwards including future reversals of existing taxable temporary differences. Under SFAS No. 109, “Accounting for Income Taxes,” deferred tax assets and liabilities are determined based on differences between the financial reporting and tax basis of assets and liabilities, and are measured using enacted tax rates and laws that will be in effect when the differences are expected to reverse. SFAS No. 109 provides for the recognition of deferred tax assets if realization of such assets is more likely than not. Based on the weight of available evidence, we have provided a valuation allowance against certain deferred tax assets. The valuation allowance was based on the historical earnings patterns within individual tax jurisdictions that make it uncertain that we will have sufficient income in the appropriate jurisdictions to realize the full value of the assets. We will continue to evaluate the realizability of the deferred tax assets on a quarterly basis.

For the year ended December 31, 2005, we determined it is more likely than not a portion of our deferred tax assets will not be realized as the planned sale of certain appreciated assets to generate taxable income is no longer feasible due to our bankruptcy filings, imposed restrictions on our entering into such transactions and other tax planning strategies. Given our current financial condition, management determined it was appropriate to record a valuation allowance on all deferred tax assets to the extent not offset by taxable income generated by reversing taxable temporary differences of the appropriate character within the carryback or carryforward periods.

We provide for United States income taxes on the earnings of foreign subsidiaries unless they are considered permanently invested outside the United States. At December 31, 2005, we had no cumulative undistributed earnings of foreign subsidiaries.

Our effective income tax benefit rates for continuing operations were 7.0%, 35.9% and 66.6% in fiscal 2005, 2004 and 2003, respectively. The effective tax rate in all periods is the result of profits (losses) that we and our subsidiaries earned in various tax jurisdictions, both foreign and domestic, that apply a broad range of income tax rates. The provision for income taxes differs from the tax computed at the federal statutory income tax rate due primarily to state taxes, tax credits, other permanent differences and earnings considered as permanently reinvested in foreign operations. Future effective tax rates could be adversely affected if earnings are lower than anticipated in countries where we have lower statutory rates, if unfavorable changes in tax laws and regulations occur, or if we experience future adverse determinations by taxing authorities after any related litigation. Our foreign taxes at rates other than statutory include the benefit of cross border financings as well as withholding taxes and foreign valuation allowance.

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At December 31, 2005, we had credit carryforwards of $63.3 million. These credits relate to Energy Credits, Research and Development Credits, and Alternative Minimum Tax Credits. The NOL carryforward consists of federal carryforwards of approximately $2.9 billion which expire between 2023 and 2025. The federal NOL carryforwards available are subject to limitations on their annual usage. We provided a valuation allowance on certain state and foreign tax jurisdiction deferred tax assets to reduce the gross amount of these assets to the extent necessary to result in an amount that is more likely than not of being realized. Realization of the deferred tax assets and NOL carryforwards is dependent, in part, on generating sufficient taxable income prior to expiration of the loss carryforwards. The amount of the deferred tax asset considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carryforward period are reduced.


	Variable Interest Entities and Primary Beneficiary

In determining whether an entity is a VIE and whether or not we are the “Primary Beneficiary” as defined under FIN 46-R, we use significant judgment regarding the adequacy of an entity’s equity relative to maximum expected losses, amounts and timing of estimated cash flows, discount rates and the probability of achieving a specific expected future cash flow outcome for various cash flow scenarios. Due to the long-term nature of our investment in a VIE and its underlying assets, our estimates of the probability-weighted future expected cash flow outcomes are complex and subjective, and are based, in part, on our assessment of future commodity prices based on long-term supply and demand forecasts for electricity and natural gas, operational performance of the underlying assets, legal and regulatory factors affecting our industry, long-term interest rates and our current credit profile and cost of capital. As a result of applying the complex guidance outlined in FIN 46-R, we may be required to consolidate assets we do not legally own and liabilities that we are not legally obligated to satisfy. Also, future changes in a VIE’s legal or capital structure may cause us to reassess whether or not we are the Primary Beneficiary and may result in our consolidation or deconsolidation of that entity.

We adopted FIN 46-R for our equity method joint ventures, our wholly owned subsidiaries that are subject to long-term PPAs and tolling arrangements, our wholly owned subsidiaries that have issued mandatorily redeemable non-controlling preferred interests and operating lease arrangements containing fixed price purchase options as of March 31, 2004, and for our investments in SPEs as of December 31, 2003.


	Joint Venture Investments

On application of FIN 46-R, we evaluated our investments in joint venture investments and concluded that, in some instances, these entities were VIEs. However, in these instances, we were not the Primary Beneficiary, as we would not absorb a majority of these entities’ expected variability. An enterprise that holds a significant variable interest in a VIE is required to make certain disclosures regarding the nature and timing of its involvement with the VIE and the nature, purpose, size and activities of the VIE. The joint ventures in which we invested, and which did not qualify for the definition of a business scope exception outlined in paragraph 4(h) of FIN 46-R, were considered significant variable interests and the required disclosures have been made in Note 10 of the Notes to Consolidated Financial Statements for these joint venture investments.

In the second half of 2005, CES restructured its tolling arrangement with Acadia PP to include additional payments from CES to Acadia Power Holdings, a Cleco subsidiary that holds its investment in Acadia PP. This restructuring of the tolling agreement caused us to re-evaluate our economic interest in the joint venture. Based on our reassessment, we determined that these additional payments caused us to become the primary beneficiary of this VIE. As a result, in the fourth quarter of 2005, we began consolidating Acadia PP into our consolidated financial statements, which include the assets and liabilities of Acadia PP at December 31, 2005, and its revenue and expenses for the period beginning August 1, 2005, through December 31, 2005. We have also reflected Cleco’s 50% interest in the joint venture as a minority interest in our balance sheet at December 31, 2005.

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	Significant Long-Term Power Sales and Tolling Agreements

An analysis was performed for our wholly owned subsidiaries with significant long-term power sales or tolling agreements. Certain of our 100% owned subsidiaries were deemed to be VIEs by virtue of the power sales and tolling agreements which meet the definition of a variable interest under FIN 46-R. However, in all cases, we absorbed a majority of the entity’s variability and did not deconsolidate any of such wholly owned subsidiaries for this reason. As part of our quantitative assessment, a fair value methodology was used to determine whether we or the power purchaser absorbed the majority of the subsidiary’s variability. As part of our analysis, we qualitatively determined that power sales or tolling agreements with a term for less than one third of the facility’s remaining useful life or for less than 50% of the entity’s capacity would not cause the power purchaser to be the Primary Beneficiary, due to the length of the economic life of the underlying assets. Also, power sales and tolling agreements meeting the definition of a lease under EITF Issue No. 01-08, “Determining Whether an Arrangement Contains a Lease,” were not considered variable interests, since lease payments create rather than absorb variability, and therefore, do not meet the definition of a variable interest.


	Preferred Interests Issued from Wholly Owned Subsidiaries

A similar analysis was performed for our wholly owned subsidiaries that have issued mandatorily redeemable non-controlling preferred interests. These entities were determined to be VIEs in which we absorb the majority of the variability, primarily due to the debt characteristics of the preferred interest, which are classified as debt in accordance with SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” in our Consolidated Condensed Balance Sheets. As a result, we continue to consolidate these wholly owned subsidiaries.


	Operating Leases with Fixed Price Options

On application of FIN 46-R, we evaluated our operating lease arrangements containing fixed price purchase options and concluded that, in some instances, the lessor entities were VIEs. However, in these instances, we were not the Primary Beneficiary, as we would not absorb a majority of these entities’ expected variability. An enterprise that holds a significant variable interest in a VIE is required to make certain disclosures regarding the nature and timing of its involvement with the VIE and the nature, purpose, size and activities of the VIE. The fixed price purchase options under our operating lease arrangements were not considered significant variable interests.


	Investments in Special-Purpose Entities

Significant judgment is required in making an assessment of whether or not our SPEs were VIEs for purposes of adopting and applying FIN 46, as originally issued at December 31, 2003. Since the current accounting literature does not provide a definition of an SPE, our assessment was primarily based on the degree to which the entity aligned with the definition of a business outlined in FIN 46-R. Entities that meet the definition of a business outlined in FIN 46-R and that satisfy other formation and involvement criteria are not subject to the FIN 46-R consolidation guidelines. The definitional characteristics of a business include having: inputs such as long-lived assets; the ability to obtain access to necessary materials and employees; processes such as strategic management, operations and resource management; and the ability to obtain access to the customers that purchase the outputs of the entity. Based on this assessment, we determined that six investments were in SPEs requiring further evaluation and were subject to the application of FIN 46, as originally issued, as of October 1, 2003: CNEM, PCF, PCF III and the Calpine Capital Trusts.

On May 15, 2003, our wholly owned subsidiary, CNEM, completed the $82.8 million monetization of an existing PPA with BPA. CNEM borrowed $82.8 million secured by the spread between the BPA contract and certain fixed power purchase contracts. CNEM was established as a special purpose subsidiary and the $82.8 million loan is recourse only to CNEM’s assets and is not guaranteed by us. CNEM was determined to be a VIE in which we were the Primary Beneficiary. Accordingly, the entity’s assets and liabilities were consolidated into our accounts as of June 30, 2003.

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On June 13, 2003, PCF, a wholly owned stand-alone subsidiary of CES, completed the offering of the PCF Notes, totaling $802.2 million. To facilitate the transaction, we formed PCF as a wholly owned, special purpose subsidiary with assets and liabilities consisting of certain transferred power purchase and sales contracts, which serve as collateral for the PCF Notes. The PCF Notes are non-recourse to our other consolidated subsidiaries. PCF was originally determined to be a VIE in which we were the Primary Beneficiary. Accordingly, the entity’s assets and liabilities were consolidated into our accounts as of June 30, 2003.

As a result of the debt reserve monetization consummated on June 2, 2004, we were required to evaluate our new investment in PCF III and to reevaluate our investment in PCF under FIN 46-R (effective March 31, 2004). We determined that the entities were VIEs but we were not the Primary Beneficiary and, therefore, were required to deconsolidate the entities as of June 30, 2004.

Upon the application of FIN 46, as originally issued at December 31, 2003, for our investments in SPEs, we determined that our equity investment in the Calpine Capital Trusts was not considered at-risk as defined in FIN 46 and that we did not have a significant variable interest in the Calpine Capital Trusts. Consequently, we deconsolidated the Calpine Capital Trusts as of December 31, 2003. During 2004 and 2005, we repaid the debentures issued to the Calpine Capital Trusts, which then used these proceeds to redeem all the outstanding HIGH TIDES issued by the Calpine Capital Trusts.

We created CNEM, PCF, PCF III and the Trusts to facilitate capital transactions. However, in cases such as these where we have a continuing involvement with the assets held by the deconsolidated SPE, we account for the capital transaction with the SPE as a financing rather than a sale under EITF Issue No. 88-18, “Sales of Future Revenue” or Statement of Financial Accounting Standard No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities — a Replacement of FASB Statement No. 125,” as appropriate. When EITF Issue No. 88-18 and SFAS No. 140 require us to account for a transaction as a financing, derecognition of the assets underlying the financing is prohibited, and the proceeds received from the transaction must be recorded as debt. Accordingly, in situations where we account for transactions as financings under EITF Issue No. 88-18 or SFAS No. 140, we continue to recognize the assets and the debt of the deconsolidated SPE on our balance sheet. See Note 2 of the Notes to Consolidated Financial Statements for a summary on how we account for our SPEs when we have continuing involvement under EITF Issue No. 88-18 or SFAS No. 140.


	Stock-Based Compensation

Prior to 2003, we accounted for qualified stock compensation under APB Opinion No. 25, “Accounting for Stock Issued to Employees.” Under APB No. 25, we were required to recognize stock compensation as expense only to the extent that there is a difference in value between the market price of the stock being offered to employees and the price those employees must pay to acquire the stock. The expense measurement methodology provided by APB No. 25 is commonly referred to as the “intrinsic value based method.” To date, our stock compensation program has been based primarily on stock options whose exercise prices are equal to the market price of Calpine stock on the date of the stock option grant; consequently, under APB No. 25 we had historically incurred minimal stock compensation expense. On January 1, 2003, we prospectively adopted the fair value method of accounting for stock-based employee compensation pursuant to SFAS No. 123, “Accounting for Stock-Based Compensation” as amended by SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure.” SFAS No. 148 amends SFAS No. 123 to provide alternative methods of transition for companies that voluntarily change their accounting for stock-based compensation from the less preferred intrinsic value based method to the more preferred fair value based method. Prior to its amendment, SFAS No. 123 required that companies enacting a voluntary change in accounting principle from the intrinsic value methodology provided by APB No. 25 could only do so on a prospective basis; no adoption or transition provisions were established to allow for a restatement of prior period financial statements. SFAS No. 148 provided two additional transition options to report the change in accounting principle — the modified prospective method and the retroactive restatement method. Additionally, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of

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the method used on reported results. We elected to adopt the provisions of SFAS No. 123 on a prospective basis; consequently, we are required to provide a pro-forma disclosure of net income and EPS as if SFAS No. 123 accounting had been applied to all prior periods presented within our financial statements. In December 2004 the FASB issued SFAS No. 123-R (revised 2004), “Share Based Payments.” This statement revises SFAS No. 123, “Accounting for Stock-Based Compensation” and supersedes APB No. 25, “Accounting for Stock Issued to Employees,” and its related implementation guidance. SFAS No. 123-R requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (with limited exceptions), which must be recognized over the period during which an employee is required to provide service in exchange for the award — the requisite service period (usually the vesting period). Adoption of SFAS No. 123-R is not expected to materially impact our operating results, cash flows or financial position, due to the aforementioned discussion surrounding our prior adoption of SFAS No. 123 as amended by SFAS No. 148.

Under SFAS No. 123, the fair value of a stock option or its equivalent is estimated on the date of grant by using an option-pricing model, such as the Black-Scholes model or a binomial model. The option-pricing model selected should take into account, as of the stock option’s grant date, the exercise price and expected life of the stock option, the current price of the underlying stock and its expected volatility, expected dividends on the stock, and the risk-free interest rate for the expected term of the stock option.

The fair value calculated by this model is then recognized as compensation expense over the period in which the related employee services are rendered. Unless specifically defined within the provisions of the stock option granted, the service period is presumed to begin on the grant date and end when the stock option is fully vested. Depending on the vesting structure of the stock option and other variables that are built into the option-pricing model, the fair value of the stock option is recognized over the service period using either a straight-line method (the single option approach) or a more conservative, accelerated method (the multiple option approach). For consistency, we have chosen the multiple option approach, which we have used historically for pro-forma disclosure purposes. The multiple option approach views one four-year option grant as four separate sub-grants, each representing 25% of the total number of stock options granted. The first sub-grant vests over one year, the second sub-grant vests over two years, the third sub-grant vests over three years, and the fourth sub-grant vests over four years. Under this scenario, over 50% of the total fair value of the stock option grant is recognized during the first year of the vesting period, and nearly 80% of the total fair value of the stock option grant is recognized by the end of the second year of the vesting period. By contrast, if we were to apply the single option approach, only 25% and 50% of the total fair value of the stock option grant would be recognized as compensation expense by the end of the first and second years of the vesting period, respectively.

We have selected the Black-Scholes model, primarily because it has been the most commonly recognized options-pricing model among U.S.-based corporations. Nonetheless, we believe this model tends to overstate the true fair value of our employee stock options in that our options cannot be freely traded, have vesting requirements, and are subject to blackout periods during which, even if vested, they cannot be traded. We will monitor valuation trends and techniques as more companies adopt SFAS No. 123-R and as additional guidance is provided by FASB and the SEC and review our choices as appropriate in the future. The key assumption in our Black-Scholes model is the expected life of the stock option, because it is this figure that drives our expected volatility calculation, as well as our risk-free interest rate. The expected life of the option relies on two factors — the option’s vesting period and the expected term that an employee holds the option once it has vested. There is no single method described by SFAS No. 123 for predicting future events such as how long an employee holds on to an option or what the expected volatility of a company’s stock price will be; the facts and circumstances are unique to different companies and depend on factors such as historical employee stock option exercise patterns, significant changes in the market place that could create a material impact on a company’s stock price in the future, and changes in a company’s stock-based compensation structure.

We base our expected option terms on historical employee exercise patterns. We have segregated our employees into four different categories based on the fact that different groups of employees within our company have exhibited different stock exercise patterns in the past, usually based on employee rank and

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income levels. Therefore, we have concluded that we will perform separate Black-Scholes calculations for four employee groups — executive officers, senior vice presidents, vice presidents, and all other employees.

We compute our expected stock price volatility based on our stock’s historical movements. For each employee group, we measure the volatility of our stock over a period that equals the expected term of the option. In the case of our executive officers, this means we measure our stock price volatility dating back to our public inception in 1996, because these employees are expected to hold their options for over 7 years after the options have fully vested. In the case of other employees, volatility is only measured dating back 4 years. In the short run, this causes other employees to generate a higher volatility figure than the other company employee groups because our stock price has fluctuated significantly in the past four years. As of December 31, 2005, the volatility for our employee groups ranged from 71%-91%.

It is expected that as a result of our bankruptcy filing on December 20, 2005, existing stock options may be cancelled upon approval of our plan of reorganization once it is prepared and filed with the U.S. Bankruptcy Court. Until such time as the existing stock options may be cancelled, however, we will continue to amortize the grant date fair value as described above.

See Note 2 of the Notes to Consolidated Financial Statements for additional information related to the January 1, 2003, adoption of SFAS Nos. 123 and 148 and the pro-forma impact that they would have had on our net income for the years ended December 31, 2005, 2004 and 2003.

Initial Adoption of New Accounting Standards in 2005

See Note 2 of the Notes to Consolidated Financial Statements for information regarding the initial adoption of new accounting standards in 2005.


Item 7A.	*Quantitative and Qualitative Disclosures About Market Risk*

The information required hereunder is set forth under Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Market Risks.”


Item 8.	*Financial Statements and Supplementary Data*

The information required hereunder is set forth under “Report of Independent Registered Public Accounting Firm,” “Consolidated Balance Sheets,” “Consolidated Statements of Operations,” “Consolidated Statements of Comprehensive Income and Stockholders’ Equity (Deficit),” “Consolidated Statements of Cash Flows,” and “Notes to Consolidated Financial Statements” included in the consolidated financial statements that are a part of this Report. Other financial information and schedules are included in the consolidated financial statements that are a part of this Report.


Item 9.	*Changes in and Disagreements With Accountants on Accounting and Financial Disclosure*

None.


Item 9A.	*Controls and Procedures*

Disclosure Controls and Procedures

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

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon, and as of the date of this evaluation, the Chief Executive Officer and

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the Chief Financial Officer concluded that our disclosure controls and procedures were not effective, because of the material weakness discussed below. In light of this material weakness, we performed additional analysis and post-closing procedures to ensure our consolidated financial statements are prepared in accordance with GAAP. Accordingly, management believes that the financial statements included in this report fairly present in all material respects our financial condition, results of operations and cash flows for the periods presented.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.

Management has assessed the effectiveness of our internal control over financial reporting as of December 31, 2005. In making its assessment of internal control over financial reporting, management used the criteria described in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. As of December 31, 2005, we did not have effective controls related to accounting for income taxes. Specifically we did not timely reconcile the underlying data being provided by the accounting department to the tax department to ensure the accuracy and validity for purposes of our tax calculations, principally relating to the book and tax basis of our property, plant and equipment. This control deficiency could result in a misstatement of deferred income tax assets and liabilities, valuation allowances and the related income tax provision (benefit) which could result in a material misstatement to annual or interim financial statements that would not be timely prevented or detected. Accordingly, management determined that this control deficiency constitutes a material weakness. Because of this material weakness, we have concluded that we did not maintain effective internal control over financial reporting as of December 31, 2005, based on criteria in Internal Control — Integrated Framework.

Management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

Since December 31, 2005, we have experienced resignations of key personnel in the accounting and SEC reporting functions. Additionally, we have begun to implement company-wide staff reductions and a reorganization of our operations. The impact of these developments could potentially have an adverse impact on the Company’s internal control over financial reporting until we are able to replace the employees in key positions that have resigned with permanent personnel and we have completed the design and implementation of new internal controls to address the planned staff reductions and reorganization of our operations and financial reporting functions. We have added contract workers and consultants as temporary replacements of the key personnel who have resigned and we expect that we will be successful during 2006 in attracting qualified permanent employees to fill these key positions.

Status of Remediation of 2004 Material Weakness

Prior to the fourth quarter of 2004, we identified certain deficiencies in our tax accounting processes, procedures and controls. Although we had processes and systems in place relating to the preparation and review of the interim and annual income tax provisions, we subsequently determined that these controls were not adequate, and in our Form 10-K for the year ended December 31, 2004, we reported a material weakness in our internal controls over the accounting for income taxes and the determination of current income taxes payable, deferred income tax assets and liabilities and the related income tax provision (benefit) for

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continuing and discontinued operations. In 2005, we took the steps listed below to remediate our internal controls relating to these areas:


	•	Enhanced various tax provision processes such as effective tax rate schedules and review procedures.

	•	Completed reviews of significant transactions for tax ramifications.

	•	Engaged third party tax consultants to supplement our staff and to review the details of income tax calculations.

Although it was also intended that we would have completed our implementation of a tax provision software system, we decided to suspend the implementation of the system initially identified and to review alternative software solutions in the marketplace. Consequently, we decided to perform manually the functions that we would have done by using a tax provision software system.

We added additional resources in the Tax department during the year ended 2005, specifically appointing a new income tax director as well as lower level personnel and designating an accounting director with lead responsibility for working closely with the Tax department and reviewing tax provision calculations. However, during the fourth quarter of 2005, both the new income tax director and designated accounting director tendered their resignations with Calpine and consequently did not perform certain documented key controls relating to the Company’s year-end income tax process. Due in part to the bankruptcy filing, we were unable to hire replacement internal resources prior to the date of this report. In the interim the Company has engaged third party tax consultants to perform these key income tax controls for the period ended December 31, 2005.

We believe that meaningful progress was made during 2005 in strengthening our control environment related to the accounting for income taxes. However, due in large part to changes in our circumstances related to our ability to realize the value of our deferred tax assets, we determined that a control weakness existed as discussed below.

2005 Material Weakness and Planned Steps to Remediate

In the fourth quarter of 2005 as we assessed the need to provide valuation allowances related to deferred tax asset balances, the Company determined that it did not have effective controls in place related to the processes around underlying accounting data used for tax accounting purposes, including the timely reconciliation of such data. Additional procedures have been performed by the Company in order to ensure that the consolidated financial statements were prepared in accordance with GAAP. In 2006, we plan to take the following steps to improve our internal controls relating to the timely reconciliation of the book and tax basis of our property assets:


	•	Improve the processes around the underlying accounting data used for tax accounting purposes.

	•	Integrate and centralize the fixed assets system to include both accounting and tax basis.

	•	Add additional internal resources in the accounting department and provide additional tax accounting training for key personnel; and

	•	Timely perform book-tax basis reconciliations on newly acquired property, plant and equipment.

We believe we are taking the steps necessary for the remediation of the 2005 material weakness and will continue to monitor the effectiveness of these procedures and to make any changes that management deems appropriate.

Changes in Internal Control Over Financial Reporting

Notwithstanding the developments discussed above, there was no change in our internal control over financial reporting that occurred during the last fiscal quarter of 2005 that materially affected, or was reasonably likely to materially affect, our internal control over financial reporting as of December 31, 2005.

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Item 9B.	*Other Information*

None

PART III


Item 10.	*Directors and Executive Officers of the Registrant*

Set forth in the table below is a list of the Company’s directors, together with certain biographical information.


Name	Age		Principal Occupation

Kenneth T. Derr*		69	Chairman of the Board, Calpine Corporation
Robert P. May		57	Chief Executive Officer, Calpine Corporation
David C. Merritt*		51	Managing Director, Salem Partners LLC
William J. Keese*		67	Consultant, North American Insulation Manufacturers Association
Walter L. Revell*		71	Chairman and Chief Executive Officer, Revell Investments International, Inc.
George J. Stathakis		76	Chief Executive Officer, George J. Stathakis & Associates
Susan Wang*		55	Retired, Former Executive Vice President and Chief Financial Officer of Solectron Corporation


*	Independent director as independence is defined by the listing standards of the NYSE.

Kenneth T. Derr became a director of the Company in May 2001. Mr. Derr has been Chairman of the Board of Calpine Corporation since November 2005 and served as Acting Chief Executive Officer of Calpine Corporation from November to December 2005. He retired as the Chairman and Chief Executive Officer of Chevron Corporation, an international oil company, in 1999, a position that he held since 1989, after a 39-year career with the company. Mr. Derr obtained a Master of Business Administration degree from Cornell University in 1960 and a Bachelor of Science degree in Mechanical Engineering from Cornell University in 1959. Mr. Derr serves as a director of Citigroup, Inc. and Halliburton Co.

William J. Keese became a director of the Company in September 2005. Mr. Keese has been a strategic consultant to the North American Manufacturers Association since July 2005. Mr. Keese was Chairman of the CEC from March 1997 to March 2005. During his eight-year tenure with the CEC, Mr. Keese was Chair of the National Association of State Energy Officials and the Western Interstate Energy Board. Prior to his distinguished career at the CEC, he served as a California public affairs advocate and consultant, representing energy and professional clients. He obtained a Juris Doctor degree from Loyola University, Los Angeles in 1963 and is a member of the American and California Bar Associations. Mr. Keese is also California’s representative to, and co-chair of, the Western Governors Association’s Clean and Diversified Energy Advisory Committee. In addition, he sits on the board of the Alliance to Save Energy, where he co-chaired the Alliance’s Vision 2010 effort, crafting a suite of federal energy policy options. He is a strategic consultant to the North American Insulation Manufacturers Association.

Robert P. May became Chief Executive Officer and a director of the Company in December 2005. Mr. May served as Interim President and Chief Executive Officer of Charter Communications, Inc. from January 2005 to August 2005. He served on the Board of Directors of HealthSouth Corporation from October 2002 to October 2005 and as its Chairman of the Board from July 2004 to October 2005. From March 2003 to May 2004, he served as HealthSouth’s Interim Chief Executive Officer, and from August 2003 to January 2004, he served as Interim President of its outpatient and diagnostic division. Since March 2001, Mr. May has been a private investor and principal of RPM Systems, which provides strategic business consulting services. From March 1999 to March 2001, Mr. May served on the board of directors and was Chief Executive of PNV

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Inc., a national telecommunications company. Mr. May was Chief Operating Officer and a director of Cablevisions Systems Corp., from October 1996 to February 1998 and he held several senior executive positions with Federal Express Corporation, including President, Business Logistics Services, from 1973 to 1993. Mr. May was educated at Curry College and Boston College and attended Harvard Business School’s Program for Management Development. Mr. May also serves as a director of Charter Communications and on the advisory board of Deutsche Bank America.

David C. Merritt became an independent director of the Company in February 2006. He has been a Managing Director at Salem Partners LLC, an investment banking firm, since October 2003. From January 2001 to April 2003, he served as Managing Director in the Entertainment Media Advisory Group at Gerard Klauer Mattison & Co., Inc., a company that provides advisory services to the entertainment media industries. He also served as a director of Laser-Pacific Media Corporation from January 2001 to October 2003. He served as Chief Financial Officer of CKE Associates, Ltd., a privately held company with interests in talent management, film production, television production, music and new media from 1999 to 2000. Mr. Merritt was an audit and consulting partner of KPMG LLP from 1985 to 1999. During that time, he served as national partner in charge of the media and entertainment practice. Mr. Merritt obtained a Bachelor of Science degree in business and accounting from California State University, Northridge in 1976. Mr. Merritt serves as a director of Outdoor Channel Holdings, Inc. and Charter Communications, Inc.

George J. Stathakis became a director of the Company in September 1996 and served as a senior advisor to the Company from December 1994 to December 2005. Mr. Stathakis is also the Chief Executive Officer of George J. Stathakis & Associates. He has been providing financial, business and management advisory services to numerous corporations since 1985. He also served as Chairman of the Board and Chief Executive Officer of Ramtron International Corporation, an advanced technology semiconductor company, from 1990 to 1994. From 1986 to 1989, he served as Chairman of the Board and Chief Executive Officer of International Capital Corporation, a subsidiary of American Express. Prior to 1986, Mr. Stathakis served 32 years with General Electric in various management and executive positions.

Walter L. Revell became a director of the Company in September 2005. He has been Chairman and Chief Executive Officer of Revell Investments International, Inc., an investment, development and management company, since 1984. Mr. Revell served as Chairman of the Board and Chief Executive Officer of H.J. Ross Associates, Inc. from 1991 to 2002 and as President, Chief Executive Officer and Director of Post, Buckley, Schuh & Jernigan, Inc., consulting engineers and planners, from 1975 to 1983. Mr. Revell served as Secretary of Transportation for the State of Florida from 1972 to 1975. Mr. Revell obtained a Bachelor of Science degree from Florida State University in 1957. Mr. Revell serves as a director of Edd Helms Group Inc., The St. Joe Company, Rinker Group Limited and NCL Corporation Ltd.

Susan Wang became a director of the Company in June 2003. From January 2001 to February 2002, Ms. Wang served as Executive Vice President and Chief Financial Officer for Solectron Corporation, an electronics manufacturing services company, and from August 1989 to February 2002, she served as its Chief Financial Officer. Prior to that, she was the Director of Finance from October 1984 to August 1989. From May 1977 to October 1984 she was Manager, Financial Services for Xerox Corporation, a document and equipment services provider. Ms. Wang obtained a Master of Business Administration degree from University of Connecticut in 1981 and a Bachelor of Business Administration degree in accounting from the University of Texas in 1972. Ms. Wang is a certified public accountant in New York and served as chairman of the Financial Executive Research Foundation from 1998 to 1999. Ms. Wang serves as a director of Altera Corp., Avanex Corp. and Nektar Therapeutics.

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Set forth in the table below is a list of the Company’s executive officers serving as of April , 2006 who are not directors, together with certain biographical information.


Name	Age		Principal Occupation

Charles B. Clark, Jr.		58	Senior Vice President, Chief Accounting Officer and Corporate Controller
Scott J. Davido		44	Executive Vice President, Chief Financial Officer and Chief Restructuring Officer
Robert E. Fishman		54	Executive Vice President — Power Operations
Eric N. Pryor		41	Senior Vice President, Finance and Corporate Risk Officer

Charles B. Clark, Jr. has served as the Company’s Senior Vice President since September 2001 and Corporate Controller since May 1999. He was the Director of Business Services for the Company’s Geysers operations from February 1999 to April 1999. He also served as a Vice President of the Company from May 1999 until September 2001. Prior to joining the Company, Mr. Clark served as the Chief Financial Officer of Hobbs Group, LLC from March 1998 to November 1998. Mr. Clark also served as Senior Vice President — Finance and Administration of CNF Industries, Inc. from February 1997 to February 1998. He served as Vice President and Chief Financial Officer of Century Contractors West, Inc. from May 1988 to January 1997. Mr. Clark obtained a Bachelor of Science degree in Mathematics from Duke University in 1969 and a Master of Business Administration degree, with a concentration in Finance, from Harvard Graduate School of Business Administration in 1976.

Scott J. Davido has served as Executive Vice President, Chief Financial Officer and Chief Restructuring Officer since February 2006. He monitors the overall financial health of the Company and is responsible for implementing and contributing to all major financial decisions and transactions affecting the Company. Mr. Davido leads the Company’s financial operations including: corporate accounting, finance, treasury and tax. He served as Executive Vice President and President for the Northeast Region of NRG Energy, Inc. from April 2004 to January 2006. Mr. Davido was chairman of the board of NRG Energy, Inc. from May to December 2003, during its financial restructuring, and was senior vice president, general counsel and secretary from October 2002 through April 2004. He served as Executive Vice President and Chief Financial Officer of The Elder-Beerman Stores Corp. from March 1999 to May 2002, and as General Counsel from January 1998 to March 1999. He obtained a Bachelor of Science degree in Accounting from Case Western Reserve University in 1983 and a Juris Doctor degree from Case Western Reserve University in 1987. Mr. Davido serves as a director of Stage Stores, Inc., where he serves as Chairman of the Audit Committee.

Robert E. Fishman has served as Executive Vice President — Power Operations since February 2006. Mr. Fishman is responsible for managing the Company’s portfolio of natural gas-fired and geothermal power plants. Mr. Fishman served as Executive Vice President — Development from September 2005 to February 2006, Senior Vice President — Business Development from July 2004 to August 2005, as Senior Vice President — Engineering from October 2002 to June 2004 and as Senior Vice President — California Peaker Program from September 2001 to September 2002. Mr. Fishman was president of PB Power, Inc. from 1997 to 2001 and Senior Vice President from 1991 to 1996. During his nearly 30-year career, he has managed power project engineering services for more than 4,000 MW of gas turbine combined-cycle, cogeneration and peaking plants. He also has power plant operations experience as a chief engineer in the U.S. Navy. Fishman obtained a bachelor’s degree in mechanical engineering from the U.S. Naval Academy in 1973, a master’s and engineer’s degree in mechanical engineering from Massachusetts Institute of Technology in 1977, and a Ph.D. in mechanical engineering from the University of Maryland in 1980. He currently serves as a director of Century Aluminum Company.

Eric N. Pryor has served as Senior Vice President, Finance and Corporate Risk Officer since April 17, 2006. He served as Interim Chief Financial Officer from November 2005 to January, 2006. He plays a key role in leading the Company’s financial operations and in assessing and managing business risk for the Company. From June 27, 2005 to April 17, 2005, he served as Executive Vice President, Deputy Chief Financial Officer and Corporate Risk Officer. From December 27, 2004 to June 27, 2005 he served as Senior

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Vice President, Deputy Chief Financial Officer and Corporate Risk Officer. From November 1, 2001 until December 27, 2004 he served as Senior Vice President, Finance. From July 1999 to April 2001 he served as Vice President — Finance. From January 1998 to June 1999 he served as Director — Finance. From January 1997 to December 1997 he served as Senior Analyst. Prior to joining the Company, Mr. Pryor served as Enterprise Tax Specialist with Arthur Andersen from 1990 to 1995. He obtained a Bachelor of Arts degree in Economics from the University of California, Davis in 1988 and a Master of Business Administration degree also from the University of California, Davis in 1990. Mr. Pryor is a certified public accountant.


	*Director Independence*

The Board of Directors of the Company has determined that a majority of the members of the Company’s Board of Directors has no material relationship with the Company (either directly or as partners, stockholders or officers of an organization that has a relationship with the Company) and is “independent” within the meaning of the NYSE director independence standards. Robert P. May, Chief Executive Officer of the Company, and George Stathakis, who provided consulting services to the Company from 2000 to 2005, are not considered to be independent.

Furthermore, the Board has determined that each of the members of the Audit Committee, the Compensation Committee and the Nominating and Governance Committee has no material relationship to the Company (either directly or as a partner, stockholder or officer of an organization that has a relationship with the Company) and is “independent” within the meaning of the NYSE’s director independence standards.


	*Family Relationships — None*


	Certain Legal Proceedings

On December 20, 2005, Calpine and certain of its subsidiaries filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code. Certain of Calpine’s officers are also officers or directors of subsidiaries that filed for reorganization under Chapter 11. As such, each of the Company’s executive officers has been associated with a corporation that filed a petition under the federal bankruptcy laws within the last five years.

In addition, Mr. Davido served as Chairman of the Board of NRG Energy, Inc. from May to December 2003, and as Senior Vice President, General Counsel and Secretary from October 2002 through April 2004. On May 14, 2003, NRG Energy, Inc. and certain of its subsidiaries commenced voluntary petitions under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of New York. On November 24, 2003, the Bankruptcy Court entered an order confirming NRG Energy, Inc.’s plan of reorganization and the plan became effective on December 5, 2003.


	*Audit Committee and Designated Audit Committee Financial Experts*

Calpine has a standing Audit Committee established in accordance with Section 3(a)(58)(A) of the Exchange Act and its members are Susan Wang (Chair), David C. Merritt and Walter L. Revell. The Board of Directors has evaluated the members of the Audit Committee and determined that each member is independent, as independence for audit committee members is defined under the listing standards of the NYSE and Item 7(d)(3)(iv) of Schedule 14A of the Exchange Act. The Board also determined that each member of the Audit Committee is financially literate and has designated Ms. Wang and Messrs. Merritt and Revell as “audit committee financial experts” as defined in SEC regulations. Ms. Wang and Mr. Revell each serve on the audit committee of three other publicly traded companies. The Board has made a determination that in each case, Ms. Wang’s and Mr. Revell’s simultaneous service on the audit committees of such other companies does not impair Ms. Wang’s or Mr. Revell’s ability to effectively serve on the Company’s Audit Committee.


	*Section 16(a) Beneficial Ownership Reporting Compliance*

Section 16(a) of the Securities Exchange Act requires the Company’s directors and executive officers, and persons who own more than 10% of a registered class of the Company’s equity securities, to file with the Securities and Exchange Commission initial reports of beneficial ownership and reports of changes in

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beneficial ownership of Common Stock and other equity securities of the Company and to provide the Company with a copy.

Based solely upon review of the copies of such reports furnished to the Company and written representations that no other reports were required, the Company is not aware of any instances of noncompliance with the Section 16(a) filing requirements by any executive officer, director or greater than 10% beneficial owners during the year ended December 31, 2005.


	*Code of Ethics for Senior Financial Officers*

We have adopted a code of conduct that is applicable to all employees, including our principal executive officer, principal financial officer and principal accounting officer, and to members of our Board of Directors. A copy of the code of conduct is posted on our website at www.calpine.com. We intend to post any amendments and any waivers to our code of conduct on our website in accordance with Item 5.05 of Form 8-K and Item 406 of Regulation S-K.


	*Stockholder Nominees to Board of Directors*

We have not yet adopted procedures by which stockholders may recommend director candidates for consideration by our Nominating and Governance Committee because we are not holding annual meetings of stockholders while we are under Chapter 11 protection.

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Item 11.	*Executive Compensation*

The following table provides certain information concerning the compensation for services rendered to the Company in all capacities for the past three years for the Company’s Chief Executive Officer (and the Company’s former Acting Chief Executive Officer and the former Chief Executive Officer) and each of the four other most highly-compensated executive officers of the Company in 2005 who were serving as executive officers as of December 31, 2005, as well as the Company’s former Chief Financial Officer, who would have been included as one of the Company’s most highly-compensated executive officers, but for the fact that he was not serving as an executive officer as of December 31, 2005.

Summary Compensation Table


								Long-Term Compensation

		Annual Compensation(5)						Restricted		Securities
								Stock		Underlying		All Other
Name and Principal Position		Year		Salary(6)		Bonus(7)		Awards(8)		Options(6)		Compensation(9)

Robert P. May			2005	$	57,692	$	2,000,000	$	—		—	$	—
	Chief Executive Officer
Kenneth T. Derr			2005		80,000		—		—		25,000		—
	Director and Chairman of the		2004		24,000		—		—		16,176		—
	Board, and former Acting		2003		29,000		—		—		20,922		—
	Chief Executive Officer(1)
Peter Cartwright			2005		1,595,865		—		1,350,002		1,600,500		137,186
	Former Chairman of the Board,		2004		1,000,000		—		—		915,090		119,865
	President and Chief		2003		1,000,000		2,250,000		—		1,018,939		83,782
	Executive Officer(2)
Ann B. Curtis			2005		550,000		—		412,500		350,000		11,298
	Former Executive Vice President,		2004		547,222		2,000		—		255,018		14,276
	Vice Chairman of the Board		2003		475,000		660,000		—		350,000		14,180
	and Corporate Secretary(3)
Robert D. Kelly			2005		682,934		—		1,000,001		500,000		19,083
	Executive Vice President, and		2004		548,162		—		—		288,000		20,045
	Chief Financial Officer,		2003		470,000		1,000,000		—		368,939		20,270
	Calpine Corporation, and President, Calpine Finance Company(2)
E. James Macias			2005		538,462		148		375,001		225,000		11,298
	Senior Vice President		2004		490,741		—		—		183,622		11,006
			2003		467,308		560,000		—		250,000		9,905
Thomas R. Mason			2005		538,462		—		375,001		200,000		16,716
	Executive Vice President,		2004		499,074		—		—		144,000		28,044
	Calpine Corporation, and		2003		475,000		560,000		—		150,000		28,030
	President, Calpine Power Company
Paul Posoli			2005		410,141		—		—		200,000		9,537
	Executive Vice President,		2004		398,524		750,500		—		38,500		9,343
	Calpine Corporation, and		2003		381,231		800,500		—		38,000		8,983
	President, Calpine Merchant Services Company, and Calpine Energy Services, L.P.(4)


(1)	Mr. Derr served as the Company’s Interim Chief Executive Officer from November 28, 2005 — December 12, 2005. Mr. Derr was not compensated for his service as Interim Chief Executive Officer and all compensation that is disclosed was received in his role as a non-employee director.

(2)	Mr. Cartwright’s and Mr. Kelly’s employment with the Company terminated effective November 28, 2005 and Mr. Cartwright resigned from the Board of Directors on December 20, 2005.

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(3)	Ms. Curtis’ employment with the Company terminated and she resigned from the Board of Directors, effective January 27, 2006.

(4)	Mr. Posoli’s employment with the Company terminated effective March 22, 2006.

(5)	The Company does not provide any perquisites to its named executive officers.

(6)	Salary figures for years prior to 2005 include the amount of salary deferral reflected in the following stock option grants under the Salary Investment Option Grant Program of the 1996 Stock Incentive Plan, which was frozen in December 2004 to comply with Section 409A of the Internal Revenue Code:


Name	Year		Option Grant		Salary Deferral

Peter Cartwright		2004		15,090	$	50,000
		2003		18,939		50,000
Ann B. Curtis		2004		3,018		10,000
Robert D. Kelly		2003		18,939		50,000
E. James Macias		2004		3,622		12,000


	These stock option grants are also included in the amounts listed as Securities Underlying Options.


(7)	In December 2005, Mr. May was paid a one-time cash signing bonus of $2,000,000 under his Employment Agreement. Bonuses for 2003 and, in the case of Mr. Posoli, 2004, were made under the Company’s Management Incentive Plan. Such annual incentives bonuses are tied to the Company’s performance as well as the performance of each executive and his or her business unit. In addition, an Employee Service Recognition bonus was paid to Ann B. Curtis in 2004 in recognition of her 20th year of service with the Company. A non-cash Employee Service Recognition bonus was paid to E. James Macias in 2005 in recognition of his 5th year of service with the Company. All Company employees are eligible to participate in the Employee Service Recognition bonus program.

(8)	Indicates the following restricted stock grants made by the Company on March 8, 2005 under the Direct Issuance Program of the 1996 Stock Incentive Plan. The fair market value of such grants on the date of grant was $3.32 per share and such restricted stock grants were issued in consideration for past services. Such restricted stock grants have the following performance-based vesting: 50% of such restricted stock shall vest at such time as the Company’s stock price is equal to or greater than $5.00 per share for four consecutive trading days and the remaining 50% of the restricted stock shall vest at such time as the Company’s stock price is equal to or greater than $10.00 per share for four consecutive trading days.

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(9)	For the named executive officers, this column includes the following payments by the Company.


					Term Life
					Insurance
Name	Year		401(k)		Payment

Peter Cartwright		2005	$	8,400	$	128,786
		2004		8,200		111,665
		2003		8,000		75,782
Ann B. Curtis		2005		8,400		2,898
		2004		8,200		6,076
		2003		8,000		6,180
Robert D. Kelly		2005		8,400		10,683
		2004		8,200		11,845
		2003		8,000		12,180
E. James Macias		2005		8,400		2,898
		2004		8,200		2,806
		2003		8,000		1,905
Thomas R. Mason		2005		8,400		8,316
		2004		8,200		19,844
		2003		8,000		20,030
Paul Posoli		2005		8,400		1,137
		2004		8,200		1,143
		2003		8,000		983


	*Stock Options*

The following table sets forth certain information concerning grants of stock options during the fiscal year ended December 31, 2005 to each of the executive officers named in the Summary Compensation Table above. The table also sets forth hypothetical gains or “option spreads” for the options at the end of their respective 10-year terms. These gains are based on the assumed rates of annual compound stock price appreciation of 5% and 10% from the date the option was granted over the full option term. No stock appreciation rights were granted during the fiscal year ended December 31, 2005.

Option Grants in Last Fiscal Year


	Individual Grants(5)
											Potential Realizable Value
				Percentage of							at Assumed Annual Rates
				Total Options							of Stock Price Appreciation
	Options			Granted to			Exercise				for Option Term(7)
	Granted			Employees in			Price per		Expiration
Name	(No. of Shares)			Fiscal Year(6)			Share		Date		5%		10%

Robert P. May		—			—		$	—			$	—	$	—
Peter Cartwright(1)		350,500			4.39	%		3.32		3/8/2012		473,726		1,103,984
Peter Cartwright(1)		1,250,000	(8)		15.64			3.80		3/9/2011		895,153		2,712,701
Ann B. Curtis(2)		350,000			4.38			3.32		3/8/2012		473,051		1,102,409
Robert D. Kelly(1)(4)		500,000			6.26			3.32		3/8/2012		675,787		1,574,870
E. James Macias		225,000			2.82			3.32		3/8/2012		304,104		708,692
Thomas R. Mason		200,000			2.50			3.32		3/8/2012		270,315		629,948
Paul Posoli(3)		200,000			2.50			3.32		3/8/2012		270,315		629,948


(1)	Mr. Cartwright’s and Mr. Kelly’s employment with the Company terminated effective November 28, 2005, and Mr. Cartwright resigned from the Board of Directors on December 20, 2005.

(2)	Ms. Curtis’ employment with the Company terminated and she resigned from the Board of Directors, effective January 27, 2006.

(3)	Mr. Posoli’s employment with the Company terminated effective March 22, 2006.

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(4)	Mr. Kelly’s options have terminated.

(5)	Unless otherwise noted herein, the following applies to each option set forth in the table. Each option has a term of seven (7) years, subject to earlier termination upon the executive officer’s termination of service with the Company. Each option has an exercise price equal to the fair market value of the Common Stock on the date of grant. Each option will become exercisable for 25% of the option shares upon the officer’s completion of each additional one year of service measured from the grant date. Each option will immediately become exercisable for all of the option shares (i) upon an acquisition of the Company by merger or asset sale unless the options are assumed by the successor corporation, or (ii) upon retirement of the executive officer at least 12 months after the option grant date, if the executive officer is at least 55 years of age at retirement and if the sum of the executive officer’s age and years of service at retirement is at least 70.

(6)	The Company granted options to purchase 7,992,710 shares of Common Stock during the fiscal year ended December 31, 2005 to employees.

(7)	The 5% and 10% assumed annual rates of compound stock price appreciation from the exercise date are mandated by the rules of the Securities and Exchange Commission and do not represent the Company’s estimate or a projection by the Company of future stock prices.

(8)	These options were granted pursuant to Mr. Cartwright’s employment agreement under the Discretionary Option Grant Program of the 1996 Stock Incentive Plan. The options will fully vest upon the earlier to occur of (a) the price of the Company’s common stock closing at or above $10.00 per share for four consecutive trading days or (b) December 31, 2009. The options expire on March 9, 2011. As provided by Mr. Cartwright’s employment agreement, if Mr. Cartwright is entitled to receive a severance under such agreement, all stock options shall vest and remain exercisable through their initial terms.


	*Stock Option Exercises and Holdings*

The following table sets forth certain information concerning the exercise of options during the fiscal year ended December 31, 2005, and the number of shares subject to exercisable and unexercisable stock options held as of December 31, 2005, by the executive officers named in the Summary Compensation Table above. No stock appreciation rights were exercised by such executive officers in the fiscal year ended December 31, 2005 and no stock appreciation rights were outstanding at the end of that year,

Aggregated Option Exercises in Last Fiscal Year and Fiscal Year-End Option Values


					Options at				Value of Unexercised
					December 31, 2005				In-the-Money Options
					(No. of Shares)				at December 31, 2005(3)
	Shares Acquired		Value
Name	on Exercise		Realized(2)		Exercisable		Unexercisable		Exercisable		Unexercisable

Robert P. May		—	$	—		—		—	$	—	$	—
Peter Cartwright(1)		1,289,320		2,810,718		9,435,117		—		—		—
Ann B. Curtis		—		—		1,034,812		722,820		—		—
Robert D. Kelly		—		—		1,019,072		—		—		—
E. James Macias		—		—		241,897		489,828		—		—
Thomas R. Mason		—		—		510,543		391,820		—		—
Paul Posoli		—		—		131,102		252,875		—		—


(1)	Includes options to purchase 2,050,000 shares, which might be subject to accelerated vesting pursuant to Mr. Cartwright’s employment agreement, if Mr. Cartwright is entitled to severance benefits under his employment agreement.

(2)	Based upon the market price of the purchased shares on the exercise date less the option exercise price paid for the shares.

(3)	Based upon the closing selling price on the last trading day in the calendar year 2005 of $0.208 per share of the Common Stock on December 30, 2005, less the option exercise price payable per share.

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	*Director Compensation*

Only non-employee directors are compensated for Board service. In 2005, non-employee members of the Board of Directors were each paid an annual retainer fee of $50,000 and were reimbursed for all expenses incurred in attending meetings of the Board of Directors or any committee thereof. The chairs of the Compensation Committee and the Nominating and Governance Committee each received an additional annual fee of $15,000. The chair of the Audit Committee received an additional annual fee of $20,000 and members of the Audit Committee (including the Chair) each received an additional annual fee of $10,000 for serving on the Audit Committee. The Lead Director received an annual fee of $20,000 for serving as Lead Director.

In 2005, upon their initial election to the Board of Directors, Mr. Keese and Mr. Revell were each granted an option to purchase 50,000 shares of Common Stock (under various option grant programs in effect under the Company’s 1996 Stock Incentive Plan). Such initial option grant vests in a series of four successive annual installments upon the optionee’s completion of each year of service on the Board of Directors over the four-year period measured from the grant date. Each initial option grant has an exercise price per share equal to the fair market value per share of Common Stock on the grant date and a term of ten years, subject to earlier termination upon the optionee’s cessation of Board service. Each option is immediately exercisable for all the option shares, but any shares purchased upon exercise of the option will be subject to repurchase by the Company, at the option exercise price paid per share, upon the optionee’s cessation of Board service prior to vesting in those shares. However, option shares issuable upon exercise of options granted will immediately vest on an accelerated basis upon certain changes in control of the Company or upon the retirement, death or disability of the optionee while serving as a Board member.

Each non-employee member of the Board who was serving on the Board at the time of the annual meeting of stockholders in May 2005 (except for Mr. Keese and Mr. Revell who joined the Board in September 2005) received an annual option grant to purchase 25,000 shares of Common Stock (under various option grant programs in effect under the Company’s 1996 Stock Incentive Plan). Such annual option grant vests upon the optionee’s completion of one year of Board service measured from the grant date.

George Stathakis, who is a former employee of the Company, received additional compensation in 2005 from his service as a consultant to the Company. Mr. Stathakis’ compensation is discussed in greater detail under Certain Relationships and Related Transactions.

Beginning in 2006, non-employee members of the Board of Directors will be paid an annual retainer fee of $125,000 and will be reimbursed for all expenses incurred in attending meetings of the Board of Directors or any committee thereof. Board members will receive meeting attendance fees of $2,000 per in-person meeting and $1,000 per telephonic meeting. The chairs of the Compensation Committee and the Nominating and Governance Committee will each receive an additional annual fee of $15,000. The chair of the Audit Committee will receive an additional annual fee of $30,000 and members of the Audit Committee (including the Chair) will each receive an additional annual fee of $10,000 for serving on the Audit Committee. Committee members will receive meeting attendance fees of $1,000 per in-person or telephonic meeting. In addition, the Chairman of the Board will receive an annual retainer fee of $50,000. Non-employee members of the Board of Directors will not receive stock options in 2006. While our bankruptcy cases are pending, changes in the compensation of our Board members will be subject to U.S. Bankruptcy Court approval.


	*Employment Agreements, Termination of Employment and Change in Control Arrangements*


	Employment Contracts

Certain contracts that were entered into prior to our Chapter 11 filing are considered pre-petition and, as such, we may decide either to accept or reject these contracts as part of the Chapter 11 cases based on a cost-benefit analysis of the individual agreements. Additionally, any such claims with respect to such pre-petition agreements are subject to Bankruptcy Court approval and the Court may limit the amount of such claims.

Effective December 12, 2005, the Company entered into an employment agreement with Mr. May, which was amended on May 18, 2006, in accordance with the May 10, 2006 order of the U.S. Bankruptcy

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Court approving the employment agreement. The term of the employment agreement consists of a two-year initial term (until December 31, 2007) and any subsequent term for which the employment agreement is renewed. Mr. May’s employment agreement provides for the payment of an annual base salary of $1,500,000, which is subject to annual adjustment by the Board of Directors. Mr. May was paid a one-time cash signing bonus of $2,000,000. Mr. May is eligible to receive an annual cash performance bonus so long as he achieves performance objectives set by the board of directors and remains employed by the Company on the last day of the applicable fiscal year. Mr. May’s target bonus will be established by the Board but the minimum target bonus will be 100% of his base salary, and his actual bonus may range from 0% to 200% of the minimum target bonus as determined by the Board, except that Mr. May shall receive minimum bonuses for the fiscal years ending December 31, 2006 and December 31, 2007, of $2,250,000 and $1,500,000, respectively. Mr. May is also eligible to receive a success fee if and when a plan of reorganization is confirmed by the U.S. Bankruptcy Court and becomes effective during Mr. May’s tenure as Chief Executive Officer of the Company or within 12 months after termination of Mr. May’s employment, but only if such termination is by Mr. May for good reason or by the Company without cause. Mr. May shall not be entitled to the success fee if the Company terminates his employment for cause, he resigned his employment without good reason or his employment terminates due to death or disability before the effective date of such plan of reorganization. The success fee shall contain a $4.5 million fixed component and an incentive component based on the achievement of certain “market adjusted enterprise value” and “plan adjusted enterprise value” metrics. Mr. May will also participate in employee benefit programs available to senior executives of the Company. Severance benefits are payable upon in the event of resignation for good reason or the Company terminates his employment without cause. The benefits include an amount equal to the sum of Mr. May’s base salary and target bonus at the time of the termination of his employment (except that if such termination were to occur in 2006 or 2007, in lieu of the target bonus amount, Mr. May would receive the minimum bonus amount for such years) paid over a year. If Mr. May’s employment is terminated because of death or disability he or his estate would receive a pro rata portion of his then current target bonus.

Effective January 30, 2006, the Company entered into an employment agreement with Mr. Davido which was amended on May 18, 2006 in accordance with the May 10, 2006 order of the U.S. Bankruptcy court approving the employment agreement. The term of the agreement consists of a two year initial term (until February 1, 2008) and any subsequent term for which the agreement is renewed. Mr. Davido’s employment agreement provides for the payment of an annual base salary of $700,000, which is subject to annual adjustment by the Board of Directors. Mr. Davido is also entitled to receive a one-time cash signing bonus of $500,000, which is payable within 15 days of the U.S. Bankruptcy Court’s approval of the agreement. If Mr. Davido terminates his employment without good reason, or his employment is terminated by the Company for cause, Mr. Davido will be required within 10 days of such termination to repay a pro rata portion (based on the number of full calendar months remaining in the initial 24-month term divided by 24 months) of the signing bonus, net of any associated income and employment taxes. Mr. Davido is eligible to receive an annual cash performance bonus so long as he remains employed by the Company on the last day of the applicable fiscal year. Mr. Davido’s target bonus will be established by the Board but the minimum target bonus will be 100% of his base salary, and his actual bonus may range from 0% to 150% of his base salary as determined by the Board, except that Mr. Davido shall receive minimum bonuses of $700,000 for each of the fiscal years ending December 31, 2006 and December 31, 2007. Mr. Davido is also eligible to receive a success fee if and when a plan of reorganization is confirmed by the U.S. Bankruptcy Court becomes effective during Mr. Davido’s tenure as Executive Vice President and Chief Financial Officer of the Company or within 12 months after termination of Mr. Davido’s employment, but only if such termination is by Mr. Davido for good reason or by the Company without cause. Mr. Davido shall not be entitled to the success fee if the Company terminates his employment for cause, he resigned his employment without good reason or his employment terminates due to death or disability before the effective date of such plan of reorganization. The success fee shall contain a $1.5 million fixed component and an incentive component based on the achievement of certain “market adjusted enterprise value” and “plan adjusted enterprise value” metrics. Mr. Davido will also participate in employee benefit programs available to senior executives of the Company. Severance benefits are payable upon in the event of resignation for good reason or the Company terminates his employment without cause. The benefits include an amount equal to two times Mr. Davido’s base salary at the

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time of the termination of his employment payable in a lump sum. If Mr. Davido’s employment is terminated because of death or disability, he or his estate would receive a pro rata portion of his then current target bonus.

On March 9, 2005, the Company entered into an employment agreement with Mr. Cartwright. The term of the agreement is two years (until December 31, 2006) and is renewable for three successive one-year terms upon the mutual agreement of the Board and Mr. Cartwright. Mr. Cartwright’s employment agreement provides for the payment of a base salary, which is subject to periodic adjustment by the Nominating and Governance Committee and the Compensation Committee of the Board of Directors, acting jointly; annual bonuses under the Company’s bonus plans; and participation in benefit and equity plans. Pursuant to the agreement, on March 9, 2005, Mr. Cartwright received an option to purchase 1,250,000 shares of the Company’s Common Stock under the Discretionary Stock Option Grant Program of the Company’s 1996 Stock Incentive Plan. The option has a six-year term and an exercise price of $3.80 per share. The option will vest upon the earlier of (i) the Company’s common stock closing price equaling at least $10.00 per share for four consecutive trading days and (ii) December 31, 2009. Except in certain circumstances, the option will be forfeited if Mr. Cartwright ceases to be employed as the Company’s Chief Executive Officer before the option vests. As provided by Mr. Cartwright’s employment agreement, if Mr. Cartwright is entitled to receive a severance under such agreement, such option shall vest and remain exercisable through its initial term. The employment agreement also provides for other employee benefits such as life insurance and health care, in addition to certain disability and death benefits. Severance benefits, including severance pay, the acceleration of outstanding options, life insurance and health care, and outplacement services, are payable upon in the event of (i) resignation for good cause, (ii) an involuntary termination other than for cause or (iii) the agreement is not renewed for any of the three one-year renewal terms. Such severance pay would be equal to the sum of Mr. Cartwright’s base salary and target bonus at the time of the termination of his employment, paid for the shorter of (i) two years and (ii) the period from his termination date to December 31, 2009. Mr. Cartwright ceased to serve as the Company’s President and Chief Executive Officer on November 28, 2005 and resigned from the Board of Directors on December 20, 2005. Any claim by Mr. Cartwright for severance benefits would be a pre-petition claim and processed accordingly in the Chapter 11 cases.


	Change in Control Arrangements

Under the terms of the 1996 Stock Incentive Plan, should the Company be acquired by merger or asset sale, then all outstanding options and shares of restricted stock held by the executive officers under the 1996 Stock Incentive Plan will automatically accelerate and vest in full, except to the extent those options and shares of restricted stock are to be assumed by the successor corporation. In addition, the Compensation Committee, as plan administrator of the 1996 Stock Incentive Plan, has the authority to provide for the accelerated vesting of the shares of Common Stock subject to outstanding options held by any executive officer of the Company or any unvested shares of Common Stock acquired by such individual, in connection with the termination of that individual’s employment following (i) a merger or asset sale in which these options are assumed or are assigned or (ii) certain hostile changes in control of the Company. Mr. May and Mr. Davido are not participants in the 1996 Stock Incentive Plan.


	*Key Employee Program/ Severance Program/2006 Management Incentive Plan*

On March 1, 2006, upon receipt of U.S. Bankruptcy Court approval, we implemented a severance program that provides eligible employees, including executive officers, whose employment is involuntarily terminated in connection with workforce reductions, with certain severance benefits, including base salary continuation for specified periods based on the employee’s position and length of service.

On May 10, 2006, the U.S. Bankruptcy Court approved our request to implement certain employee incentive programs. Such programs, which we expect to implement upon completing definitive documentation, will include (i) an Emergence Incentive Plan, which would provide executive officers and certain other officers of the Company with a cash incentive payment upon the Company’s emergence from Chapter 11, as determined by the Chief Executive Officer in his sole discretion, and (ii) a 2006 Short Term Incentive Plan which would provide performance bonuses for executive officers (excluding Mr. May and Mr. Davido) and other employees provided that individual or corporate performance objectives established by the Chief

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Executive Officer and Board are achieved, as determined by the Chief Executive Officer and the Board in their sole discretion.


	*Compensation Committee Interlocks and Insider Participation — None*


Item 12.	*Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters*

The following table sets forth certain information known to the Company regarding the beneficial ownership of the Common Stock as of December 31, 2005, or as of such later date as indicated below, by (i) each person known by the Company to be the beneficial owner of more than five percent of the outstanding shares of Common Stock, (ii) each director of the Company, (iii) each executive officer of the Company listed in the Summary Compensation Table above, and (iv) all executive officers and directors of the Company as a group. The Company has no known beneficial owners of more than 5% of the outstanding shares of Common Stock.


	Total						Shares Individuals
	Number of Shares		Common Shares		Restricted Shares		Have the Right to
	Beneficially		Beneficially		Subject to		Acquire Within
Name	Owned(5)		Owned(6)		Vesting(7)		60 days(8)

Robert P. May		—		—		—		—
Peter Cartwright(1)		12,265,901		2,424,157		406,627		9,435,117
Ann B. Curtis(2)		1,383,555		65,176		124,247		1,194,132
Kenneth T. Derr		52,393		5,000		—		47,393
William J. Keese		—		—		—		—
Robert D. Kelly(1)		1,019,072		—		—		1,019,072
E. James Macias		499,541		32,364		112,952		354,225
Thomas R. Mason		778,477		72,662		112,952		592,863
David C. Merritt(3)		—		—		—		—
George J. Stathakis		325,040		24,000		—		301,040
Paul Posoli(4)		199,065		44,088		—		154,977
Walter L. Revell		—		—		—		—
Susan Wang		13,500		—		—		13,500
All executive officers and directors as a group (16 persons)		17,746,100		2,726,539		946,222		14,073,339


(1)	Mr. Cartwright’s and Mr. Kelly’s employment with the Company terminated effective November 28, 2005, and Mr. Cartwright resigned from the Board of Directors on December 20, 2005. Includes options to purchase 2,050,500 shares, which might be subject to accelerated vesting pursuant to Mr. Cartwright’s employment agreement, if Mr. Cartwright is entitled to severance benefits under his employment agreement.

(2)	Ms. Curtis’ employment with the Company terminated and she resigned from the Board of Directors effective January 27, 2006.

(3)	Mr. Merritt joined the Board of Directors effective February 8, 2006.

(4)	Mr. Posoli’s employment with the Company terminated effective March 22, 2006.

(5)	Beneficial ownership is determined in accordance with the rules of the Securities and Exchange Commission and consists of either or both voting or investment power with respect to securities. Shares of Common Stock issuable upon the exercise of options or warrants or upon the conversion of convertible securities that are immediately exercisable or convertible or that will become exercisable or convertible within the next 60 days are deemed beneficially owned by the beneficial owner of such options, warrants or convertible securities and are deemed outstanding for the purpose of computing the percentage of

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	shares beneficially owned by the person holding such instruments, but are not deemed outstanding for the purpose of computing the percentage of any other person. Except as otherwise indicated by footnote, and subject to community property laws where applicable, the persons named in the table have reported that they have sole voting and sole investment power with respect to all shares of Common Stock shown as beneficially owned by them. The number of shares of Common Stock outstanding as of December 31, 2005 was 569,081,863.

(6)	Indicates shares of Calpine common stock beneficially owned. Shares indicated are included in the Total Number of Shares Beneficially Owned column.

(7)	Indicates restricted stock grants made by the Company on March 8, 2005 under the Direct Issuance Program of the 1996 Stock Incentive Plan. The fair market value of such grants on the date of grant was $3.32 per share and such restricted stock grants were issued in consideration for past services. Such restricted stock grants have the following performance-based vesting: 50% of such restricted stock shall vest at such time as the Company’s stock price is equal to or greater than $5.00 per share for four consecutive trading days and the remaining 50% of the restricted stock shall vest at such time as the Company’s stock price is equal to or greater than $10.00 per share for four consecutive trading days. Shares indicated are included in the Total Number of Shares Beneficially Owned column.

(8)	Indicates shares of Calpine common stock that certain directors and executive officers have the right to acquire within 60 days by exercising stock options. The numbers and values of exercisable stock options as of December 31, 2005 are shown in Item 11 above. Shares indicated are included in the Total Number of Shares Beneficially Owned column.


	*Securities Authorized for Issuance Under Equity Compensation Plans*

The following table indicates the compensation plans under which equity securities of the Company are authorized for issuance as of December 31, 2005.

Number of Securities

Remaining Available for

Future Issuance Under

Equity Compensation

Number of Securities

Plans (Excluding

to be Issued Upon

Weighted Average

Securities to be Issued

Exercise of

Exercise Price of

Upon Exercise of

Outstanding Options,

Plan Category

Warrants and Rights

Warrants and Rights)(1)

Equity compensation plans approved by security holders

37,090,268

7.62

30,293,714

Equity compensation plans not approved by security holders

—

Total

37,090,268

7.62

30,293,714


(1)	Includes 13,451,324 shares subject to issuance under the Calpine Corporation 2000 Employee Stock Purchase Plan.


Item 13.	*Certain Relationships and Related Transactions*

From 2000 to 2005, the Company entered into an annual Consulting Agreement with George J. Stathakis, who is a member of the Board of Directors, to provide advice and guidance on various management issues to the Chief Executive Officer and members of the Chief Executive Officer’s senior staff. Pursuant to the terms of the Consulting Agreement, in 2005 the Company paid Mr. Stathakis a consulting fee of $5,000 per month and issued Mr. Stathakis a stock option grant in January 2005 under the Discretionary Option Grant Program for 10,000 shares of Common Stock at an exercise price of $3.80 per share. Such options were fully vested at the end of 2005. Mr. Stathakis, who is a former employee of the Company, also receives an annual stock option grant from the Company under the Discretionary Option Grant Program in an amount equal to and on similar terms as the grants issued to the other non-employee directors of the Company. Accordingly, in May 2005, Mr. Stathakis received a stock option grant to purchase 25,000 shares of

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Common Stock at an exercise price of $2.64 per share, vesting upon the completion of one year of service from the date of grant. The Company and Mr. Stathakis did not enter into a Consulting Agreement for 2006.


Item 14.	*Principal Accounting Fees and Services*


	*Audit Fees*

The fees billed by PricewaterhouseCoopers for performing our integrated audit were approximately $12.4 million during the fiscal year ended December 31, 2005 and approximately $12.7 million during the fiscal year ended December 31, 2004. The fees billed for performing audits and reviews of certain of our subsidiaries were approximately $4.4 million during the fiscal year ended December 31, 2005 and approximately $3.0 million during the fiscal year ended December 31, 2004. The audit fees for 2004 have been revised from the 2004 proxy to reflect final billings.


	*Audit-Related Fees*

The fees billed by PricewaterhouseCoopers for audit-related services were approximately $1.2 million for the fiscal year ended December 31, 2005 and approximately $0.9 million for the fiscal year ended December 31, 2004. Such audit-related fees consisted primarily of consultations concerning financial accounting and reporting standards and employee benefit plan audits.


	*Tax Fees*

PricewaterhouseCoopers did not provide the Company with any tax compliance and tax consulting services during the fiscal years ended December 31, 2005 and December 31, 2004.


	*All Other Fees*

There were no fees billed by PricewaterhouseCoopers for services rendered, other than as described above under the headings Audit Fees, Audit-Related Fees and Tax Fees, for the fiscal year ended December 31, 2005 and approximately $0.8 million during the fiscal year ended December 31, 2004. Such fees primarily consisted of advisory services related to compliance with the Sarbanes-Oxley Act of 2002.

PART IV


Item 15.	*Exhibits, Financial Statement Schedules*

(a)-1. Financial Statements and Other Information

The following items appear in Appendix F of this Report:


	Report of Independent Registered Public Accounting Firm

	Consolidated Balance Sheets December 31, 2005 and 2004

	Consolidated Statements of Operations for the Years Ended December 31, 2005, 2004, and 2003

	Consolidated Statements of Comprehensive Income and Stockholders’ Equity (Deficit) for the Years Ended December 31, 2005, 2004, and 2003

	Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004, and 2003

	Notes to Consolidated Financial Statements for the Years Ended December 31, 2005, 2004, and 2003

(a)-2. Financial Statement Schedules

Schedule II — Valuation and Qualifying Accounts

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(b) Exhibits

The following exhibits are filed herewith unless otherwise indicated:


Exhibit
Number			Description

	2	.1	Purchase and Sale Agreement, dated July 1, 2004, among Calpine Corporation (the “Company”), Calpine Natural Gas L.P. and Pogo Producing Company.(a)

	2	.2	Purchase and Sale Agreement, dated July 1, 2004, among the Company, Calpine Natural Gas L.P. and Bill Barrett Corporation.(a)

	2	.3	Asset and Trust Unit Purchase and Sale Agreement, dated July 1, 2004, among the Company, Calpine Canada Natural Gas Partnership, Calpine Energy Holdings Limited, PrimeWest Gas Corp. and PrimeWest Energy Trust.(a)

	2	.4	Share Sale and Purchase Agreement, made as of May 28, 2005, among the Company, Calpine UK Holdings Limited, Quintana Canada Holdings, LLC, International Power PLC, Mitsui & Co., Ltd. and Normantrail (UK CO 3) Limited. Approximately four pages of this Exhibit 2.4 have been omitted pursuant to a request for confidential treatment. The omitted language has been filed separately with the SEC.(b)

	2	.5	Purchase and Sale Agreement dated July 7, 2005, by and among Calpine Gas Holdings LLC, Calpine Fuels Corporation, the Company, Rosetta Resources Inc., and the other Subject Companies identified therein.(c)

	2	.6	Agreement dated as of December 20, 2005, by and among Steam Heat LLC, Thermal Power Company and, for certain limited purposes, Geysers Power Company, LLC.(*)

	3	.1.1	Amended and Restated Certificate of Incorporation of the Company, as amended through June 2, 2004.(d)

	3	.1.2	Amendment to Amended and Restated Certificate of Incorporation of the Company, dated June 20, 2005.(e)

	3	.2	Amended and Restated By-laws of the Company.(f)

	4	.1.1	Indenture dated as of May 16, 1996, between the Company and U.S. Bank (as successor trustee to Fleet National Bank), as Trustee, including form of Notes.(g)

	4	.1.2	First Supplemental Indenture dated as of August 1, 2000, between the Company and U.S. Bank (as successor trustee to Fleet National Bank), as Trustee.(h)

	4	.1.3	Second Supplemental Indenture dated as of April 26, 2004, between the Company and U.S. Bank (as successor trustee to Fleet National Bank), as Trustee.(i)

	4	.2.1	Indenture dated as of July 8, 1997, between the Company and The Bank of New York, as Trustee, including form of Notes.(j)

	4	.2.2	Supplemental Indenture dated as of September 10, 1997, between the Company and The Bank of New York, as Trustee.(k)

	4	.2.3	Second Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(h)

	4	.2.4	Third Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(i)

	4	.3.1	Indenture dated as of March 31, 1998, between the Company and The Bank of New York, as Trustee, including form of Notes.(l)

	4	.3.2	Supplemental Indenture dated as of July 24, 1998, between the Company and The Bank of New York, as Trustee.(l)

	4	.3.3	Second Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(h)

	4	.3.4	Third Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(i)

	4	.4.1	Indenture dated as of March 29, 1999, between the Company and The Bank of New York, as Trustee, including form of Notes.(m)

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Exhibit
Number			Description


	4	.4.2	First Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(h)

	4	.4.3	Second Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(i)

	4	.5.1	Indenture dated as of March 29, 1999, between the Company and The Bank of New York, as Trustee, including form of Notes.(m)

	4	.5.2	First Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(h)

	4	.5.3	Second Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(i)

	4	.6.1	Indenture dated as of August 10, 2000, between the Company and Wilmington Trust Company, as Trustee.(n)

	4	.6.2	First Supplemental Indenture dated as of September 28, 2000, between the Company and Wilmington Trust Company, as Trustee.(h)

	4	.6.3	Second Supplemental Indenture dated as of September 30, 2004, between the Company and Wilmington Trust Company, as Trustee.(o)

	4	.6.3	Third Supplemental Indenture dated as of June 23, 2005, between the Company and Wilmington Trust Company, as Trustee.(b)

	4	.7.1	Amended and Restated Indenture dated as of October 16, 2001, between Calpine Canada Energy Finance ULC and Wilmington Trust Company, as Trustee.(p)

	4	.7.2	Guarantee Agreement dated as of April 25, 2001, between the Company and Wilmington Trust Company, as Trustee.(q)

	4	.7.3	First Amendment, dated as of October 16, 2001, to Guarantee Agreement dated as of April 25, 2001, between the Company and Wilmington Trust Company, as Trustee.(p)

	4	.8.1	Indenture dated as of October 18, 2001, between Calpine Canada Energy Finance II ULC and Wilmington Trust Company, as Trustee.(p)

	4	.8.2	First Supplemental Indenture, dated as of October 18, 2001, between Calpine Canada Energy Finance II ULC and Wilmington Trust Company, as Trustee.(p)

	4	.8.3	Guarantee Agreement dated as of October 18, 2001, between the Company and Wilmington Trust Company, as Trustee.(p)

	4	.8.4	First Amendment, dated as of October 18, 2001, to Guarantee Agreement dated as of October 18, 2001, between the Company and Wilmington Trust Company, as Trustee.(p)

	4	.9	Indenture, dated as of June 13, 2003, between Power Contract Financing, L.L.C. and Wilmington Trust Company, as Trustee, Accounts Agent, Paying Agent and Registrar, including form of Notes.(r)

	4	.10	Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(r)

	4	.11	Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(r)

	4	.12	Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(r)

	4	.13.1	Indenture, dated as of August 14, 2003, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee, including form of Notes.(s)

	4	.13.2	Supplemental Indenture, dated as of September 18, 2003, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee.(s)

133


Exhibit
Number			Description


	4	.13.3	Second Supplemental Indenture, dated as of January 14, 2004, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee.(t)

	4	.13.4	Third Supplemental Indenture, dated as of March 5, 2004, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee.(t)

	4	.13.5	Fourth Supplemental Indenture, dated as of March 15, 2006, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee.(*)

	4	.13.6	Waiver Agreement, dated as of March 15, 2006, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee.(*)

	4	.14	Indenture, dated as of September 30, 2003, among Gilroy Energy Center, LLC, each of Creed Energy Center, LLC and Goose Haven Energy Center, as Guarantors, and Wilmington Trust Company, as Trustee and Collateral Agent, including form of Notes.(s)

	4	.15	Indenture, dated as of November 18, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(t)

	4	.16	Amended and Restated Indenture, dated as of March 12, 2004, between the Company and Wilmington Trust Company, including form of Notes.(t)

	4	.17.1	First Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust Company, as Trustee, including form of Notes.(t)

	4	.17.2	Second Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust Company, as Trustee, including form of Notes.(t)

	4	.17.3	Third Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust Company, as Trustee, including form of Notes.(t)

	4	.18	Indenture, dated as of June 2, 2004, between Power Contract Financing III, LLC and Wilmington Trust Company, as Trustee, Accounts Agent, Paying Agent and Registrar, including form of Notes.(d)

	4	.19	Indenture, dated as of September 30, 2004, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(u)

	4	.20.1	Amended and Restated Rights Agreement, dated as of September 19, 2001, between Calpine Corporation and Equiserve Trust Company, N.A., as Rights Agent.(v)

	4	.20.2	Amendment No. 1 to Rights Agreement, dated as of September 28, 2004, between Calpine Corporation and Equiserve Trust Company, N.A., as Rights Agent.(o)

	4	.20.3	Amendment No. 2 to Rights Agreement, dated as of March 18, 2005, between Calpine Corporation and Equiserve Trust Company, N.A., as Rights Agent.(w)

	4	.21.1	Second Amended and Restated Limited Liability Company Operating Agreement of CCFC Preferred Holdings, LLC, dated as of October 14, 2005, containing terms of its 6-Year Redeemable Preferred Shares Due 2011.(*)

	4	.21.2	Consent, Acknowledgment and Amendment, dated as of March 15, 2006, among Calpine CCFC Holdings, Inc. and the Redeemable Preferred Members party thereto.(*)

	4	.22	Third Amended and Restated Limited Liability Company Operating Agreement of Metcalf Energy Center, LLC, dated as of June 20, 2005, containing terms of its 5.5-year redeemable preferred shares.(*)

	4	.23	Pass Through Certificates (Tiverton and Rumford)

	4	.23.1	Pass Through Trust Agreement dated as of December 19, 2000, among Tiverton Power Associates Limited Partnership, Rumford Power Associates Limited Partnership and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including the form of Certificate.(h)

134


Exhibit
Number			Description


	4	.23.2	Participation Agreement dated as of December 19, 2000, among the Company, Tiverton Power Associates Limited Partnership, Rumford Power Associates Limited Partnership, PMCC Calpine New England Investment LLC, PMCC Calpine NEIM LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee.(h)

	4	.23.3	Appendix A — Definitions and Rules of Interpretation.(h)

	4	.23.4	Indenture of Trust, Mortgage and Security Agreement, dated as of December 19, 2000, between PMCC Calpine New England Investment LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, including the forms of Lessor Notes.(h)

	4	.23.5	Calpine Guaranty and Payment Agreement (Tiverton) dated as of December 19, 2000, by the Company, as Guarantor, to PMCC Calpine New England Investment LLC, PMCC Calpine NEIM LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(h)

	4	.23.6	Calpine Guaranty and Payment Agreement (Rumford) dated as of December 19, 2000, by the Company, as Guarantor, to PMCC Calpine New England Investment LLC, PMCC Calpine NEIM LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(h)

	4	.24	Pass Through Certificates (South Point, Broad River and RockGen)

	4	.24.1	Pass Through Trust Agreement A dated as of October 18, 2001, among South Point Energy Center, LLC, Broad River Energy LLC, RockGen Energy LLC and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including the form of 8.400% Pass Through Certificate, Series A.(f)

	4	.24.2	Pass Through Trust Agreement B dated as of October 18, 2001, among South Point Energy Center, LLC, Broad River Energy LLC, RockGen Energy LLC and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including the form of 9.825% Pass Through Certificate, Series B.(f)

	4	.24.3	Participation Agreement (SP-1) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-1, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)

	4	.24.4	Participation Agreement (SP-2) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-2, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)

	4	.24.5	Participation Agreement (SP-3) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-3, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)

	4	.24.6	Participation Agreement (SP-4) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-4, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)

135


Exhibit
Number			Description


	4	.24.7	Participation Agreement (BR-1) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-1, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)

	4	.24.8	Participation Agreement (BR-2) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-2, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)

	4	.24.9	Participation Agreement (BR-3) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-3, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)

	4	.24.10	Participation Agreement (BR-4) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-4, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)

	4	.24.11	Participation Agreement (RG-1) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-1, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)

	4	.24.12	Participation Agreement (RG-2) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-2, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)

	4	.24.13	Participation Agreement (RG-3) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-3, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)

	4	.24.14	Participation Agreement (RG-4) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-4, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)

	4	.24.15	Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-1, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(f)

136


Exhibit
Number			Description


	4	.24.16	Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-2, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(f)

	4	.24.17	Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-3, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(f)

	4	.24.18	Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-4, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(f)

	4	.24.19	Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-1, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(f)

	4	.24.20	Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-2, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(f)

	4	.24.21	Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-3, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(f)

	4	.24.22	Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-4, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(f)

	4	.24.23	Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-1, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(f)

	4	.24.24	Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-2, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(f)

	4	.24.25	Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-3, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(f)

	4	.24.26	Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-4, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(f)

	4	.24.27	Calpine Guaranty and Payment Agreement (South Point SP-1) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-1, LLC, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)

	4	.24.28	Calpine Guaranty and Payment Agreement (South Point SP-2) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-2, LLC, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)

137


Exhibit
Number			Description


	4	.24.29	Calpine Guaranty and Payment Agreement (South Point SP-3) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-3, LLC, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)

	4	.24.30	Calpine Guaranty and Payment Agreement (South Point SP-4) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-4, LLC, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)

	4	.24.31	Calpine Guaranty and Payment Agreement (Broad River BR-1) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-1, LLC, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)

	4	.24.32	Calpine Guaranty and Payment Agreement (Broad River BR-2) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-2, LLC, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)

	4	.24.33	Calpine Guaranty and Payment Agreement (Broad River BR-3) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-3, LLC, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)

	4	.24.34	Calpine Guaranty and Payment Agreement (Broad River BR-4) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-4, LLC, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)

	4	.24.35	Calpine Guaranty and Payment Agreement (RockGen RG-1) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-1, LLC, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)

	4	.24.36	Calpine Guaranty and Payment Agreement (RockGen RG-2) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-2, LLC, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)

	4	.24.37	Calpine Guaranty and Payment Agreement (RockGen RG-3) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-3, LLC, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)

	4	.24.38	Calpine Guaranty and Payment Agreement (RockGen RG-4) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-4, LLC, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)

	10	.1	DIP Financing Agreements

	10	.1.1.1	$2,000,000,000 Amended & Restated Revolving Credit, Term Loan and Guarantee Agreement, dated as of February 23, 2006, among the Company, as borrower, the Subsidiaries of the Company named therein, as guarantors, the Lenders from time to time party thereto, Credit Suisse Securities (USA) LLC and Deutsche Bank Trust Company Americas, as Joint Syndication Agents, Deutsche Bank Securities Inc. and Credit Suisse Securities (USA) LLC, as Joint Lead Arrangers and Joint Bookrunners, and Credit Suisse and Deutsche Bank Trust Company Americas, as Joint Administrative Agents.(*)

138


Exhibit
Number			Description


	10	.1.1.2	First Consent, Waiver and Amendment, dated as of May 3, 2006, to and under the Amended and Restated Revolving Credit, Term Loan and Guarantee Agreement, dated as of February 23, 2006, among Calpine Corporation, as borrower, its subsidiaries named therein, as guarantors, the Lenders party thereto, Deutsche Bank Trust Company Americas, as administrative agent for the First Priority Lenders, Credit Suisse, Cayman Islands Branch, as administrative agent for the Second Priority Term Lenders.(*)

	10	.1.2	Amended and Restated Security and Pledge Agreement, dated as of February 23, 2006, among the Company, the Subsidiaries of the Company signatory thereto and Deutsche Bank Trust Company Americas, as collateral agent.(*)

	10	.2	Financing and Term Loan Agreements

	10	.2.1	Share Lending Agreement, dated as of September 28, 2004, among the Company, as Lender, Deutsche Bank AG London, as Borrower, through Deutsche Bank Securities Inc., as agent for the Borrower, and Deutsche Bank Securities Inc., in its capacity as Collateral Agent and Securities Intermediary.(o)

	10	.2.2	Amended and Restated Credit Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, The Bank of Nova Scotia, as Administrative Agent, LC Bank, Lead Arranger and Sole Bookrunner, Bayerische Landesbank Cayman Islands Branch, as Arranger and Co-Syndication Agent, Credit Lyonnais New York Branch, as Arranger and Co-Syndication Agent, ING Capital LLC, as Arranger and Co-Syndication Agent, Toronto-Dominion (Texas) Inc., as Arranger and Co-Syndication Agent, and Union Bank of California, N.A., as Arranger and Co-Syndication Agent.(t)

	10	.2.3.1	Letter of Credit Agreement, dated as of July 16, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent.(r)

	10	.2.3.2	Amendment to Letter of Credit Agreement, dated as of September 30, 2004, between the Company and The Bank of Nova Scotia, as Administrative Agent.(y)

	10	.2.4	Letter of Credit Agreement, dated as of September 30, 2004, between the Company and Bayerische Landesbank, acting through its Cayman Islands Branch, as the Issuer.(y)

	10	.2.5	Credit Agreement, dated as of July 16, 2003, among the Company, the Lenders named therein, Goldman Sachs Credit Partners L.P., as Sole Lead Arranger, Sole Bookrunner and Administrative Agent, The Bank of Nova Scotia, as Arranger and Syndication Agent, TD Securities (USA) Inc., ING (U.S.) Capital LLC and Landesbank Hessen-Thuringen, as Co-Arrangers, and Credit Lyonnais New York Branch and Union Bank of California, N.A., as Managing Agents.(r)

	10	.2.6.1	Credit and Guarantee Agreement, dated as of August 14, 2003, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(s)

	10	.1.6.2	Amendment No. 1 to the Credit and Guarantee Agreement, dated as of September 12, 2003, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(s)

	10	.2.6.3	Amendment No. 2 to the Credit and Guarantee Agreement, dated as of January 13, 2004, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(t)

	10	.2.6.4	Amendment No. 3 to the Credit and Guarantee Agreement, dated as of March 5, 2004, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(t)

	10	.2.6.5	Amendment No. 4 to the Credit and Guarantee Agreement, dated as of March 15, 2006, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(*)

139


Exhibit
Number			Description


	10	.2.6.6	Waiver Agreement, dated as of March 15, 2006 among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(*)

	10	.2.7	Credit and Guarantee Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, Morgan Stanley Senior Funding, Inc., as Administrative Agent, and Morgan Stanley Senior Funding, Inc., as Sole Lead Arranger and Sole Bookrunner.(t)

	10	.2.8	Credit and Guarantee Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, Morgan Stanley Senior Funding, Inc., as Administrative Agent, and Morgan Stanley Senior Funding, Inc., as Sole Lead Arranger and Sole Bookrunner.(t)

	10	.2.9	Credit Agreement, dated as of June 24, 2004, among Riverside Energy Center, LLC, the Lenders named therein, Union Bank of California, N.A., as the Issuing Bank, Credit Suisse First Boston, acting through its Cayman Islands Branch, as Lead Arranger, Book Runner, Administrative Agent and Collateral Agent, and CoBank, ACB, as Syndication Agent.(z)

	10	.2.10	Credit Agreement, dated as of June 24, 2004, among Rocky Mountain Energy Center, LLC, the Lenders named therein, Union Bank of California, N.A., as the Issuing Bank, Credit Suisse First Boston, acting through its Cayman Islands Branch, as Lead Arranger, Book Runner, Administrative Agent and Collateral Agent, and CoBank, ACB, as Syndication Agent.(z)

	10	.2.11	Credit Agreement, dated as of February 25, 2005, among Calpine Steamboat Holdings, LLC, the Lenders named therein, Calyon New York Branch, as a Lead Arranger, Underwriter, Co-Book Runner, Administrative Agent, Collateral Agent and LC Issuer, CoBank, ACB, as a Lead Arranger, Underwriter, Co-Syndication Agent and Co-Book Runner, HSH Nordbank AG, as a Lead Arranger, Underwriter and Co-documentation Agent, UFJ Bank Limited, as a Lead Arranger, Underwriter and Co-Documentation Agent, and Bayerische Hypo-Und Vereinsbank AG, New York Branch, as a Lead Arranger, Underwriter and Co-Syndication Agent.(z)

	10	.3	Security Agreements

	10	.3.1	Guarantee and Collateral Agreement, dated as of July 16, 2003, made by the Company, JOQ Canada, Inc., Quintana Minerals (USA) Inc., and Quintana Canada Holdings LLC, in favor of The Bank of New York, as Collateral Trustee.(r)

	10	.3.2	First Amendment Pledge Agreement, dated as of July 16, 2003, made by JOQ Canada, Inc., Quintana Minerals (USA) Inc., and Quintana Canada Holdings LLC in favor of The Bank of New York, as Collateral Trustee.(r)

	10	.3.3	First Amendment Assignment and Security Agreement, dated as of July 16, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(r)

	10	.3.4.1	Second Amendment Pledge Agreement (Stock Interests), dated as of July 16, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(r)

	10	.3.4.2	Amendment No. 1 to the Second Amendment Pledge Agreement (Stock Interests), dated as of November 18, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(t)

	10	.3.5.1	Second Amendment Pledge Agreement (Membership Interests), dated as of July 16, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(r)

	10	.3.5.2	Amendment No. 1 to the Second Amendment Pledge Agreement (Membership Interests), dated as of November 18, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(t)

	10	.3.6	First Amendment Note Pledge Agreement, dated as of July 16, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(r)

140


Exhibit
Number			Description


	10	.3.7.1	Collateral Trust Agreement, dated as of July 16, 2003, among the Company, JOQ Canada, Inc., Quintana Minerals (USA) Inc., Quintana Canada Holdings LLC, Wilmington Trust Company, as Trustee, The Bank of Nova Scotia, as Agent, Goldman Sachs Credit Partners L.P., as Administrative Agent, and The Bank of New York, as Collateral Trustee.(r)

	10	.3.7.2	First Amendment to the Collateral Trust Agreement, dated as of November 18, 2003, among the Company, JOQ Canada, Inc., Quintana Minerals (USA) Inc., Quintana Canada Holdings LLC, Wilmington Trust Company, as Trustee, The Bank of Nova Scotia, as Agent, Goldman Sachs Credit Partners L.P., as Administrative Agent, and The Bank of New York, as Collateral Trustee.(t)

	10	.3.8	Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Multistate), dated as of July 16, 2003, from the Company to Messrs. Denis O’Meara and James Trimble, as Trustees, and The Bank of New York, as Collateral Trustee.(r)

	10	.3.9	Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Multistate), dated as of July 16, 2003, from the Company to Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of New York, as Collateral Trustee.(r)

	10	.3.10	Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Colorado), dated as of July 16, 2003, from the Company to Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of New York, as Collateral Trustee.(r)

	10	.3.11	Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (New Mexico), dated as of July 16, 2003, from the Company to Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of New York, as Collateral Trustee.(r)

	10	.3.12	Form of Amended and Restated Mortgage, Assignment, Security Agreement and Financing Statement (Louisiana), dated as of July 16, 2003, from the Company to The Bank of New York, as Collateral Trustee.(r)

	10	.3.13	Form of Amended and Restated Deed of Trust with Power of Sale, Assignment of Production, Security Agreement, Financing Statement and Fixture Filings (California), dated as of July 16, 2003, from the Company to Chicago Title Insurance Company, as Trustee, and The Bank of New York, as Collateral Trustee.(r)

	10	.3.14	Form of Deed to Secure Debt, Assignment of Rents and Security Agreement (Georgia), dated as of July 16, 2003, from the Company to The Bank of New York, as Collateral Trustee.(r)

	10	.3.15	Form of Mortgage, Assignment of Rents and Security Agreement (Florida), dated as of July 16, 2003, from the Company to The Bank of New York, as Collateral Trustee.(r)

	10	.3.16	Form of Deed of Trust, Assignment of Rents and Security Agreement and Fixture Filing (Texas), dated as of July 16, 2003, from the Company to Malcolm S. Morris, as Trustee, in favor of The Bank of New York, as Collateral Trustee.(r)

	10	.3.17	Form of Deed of Trust, Assignment of Rents and Security Agreement (Washington), dated as of July 16, 2003, from the Company to Chicago Title Insurance Company, in favor of The Bank of New York, as Collateral Trustee.(r)

	10	.3.18	Form of Deed of Trust, Assignment of Rents, and Security Agreement (California), dated as of July 16, 2003, from the Company to Chicago Title Insurance Company, in favor of The Bank of New York, as Collateral Trustee.(r)

	10	.3.19	Form of Mortgage, Collateral Assignment of Leases and Rents, Security Agreement and Financing Statement (Louisiana), dated as of July 16, 2003, from the Company to The Bank of New York, as Collateral Trustee.(r)

	10	.3.20	Amended and Restated Hazardous Materials Undertaking and Indemnity (Multistate), dated as of July 16, 2003, by the Company in favor of The Bank of New York, as Collateral Trustee.(r)

141


Exhibit
Number			Description


	10	.3.21	Amended and Restated Hazardous Materials Undertaking and Indemnity (California), dated as of July 16, 2003, by the Company in favor of The Bank of New York, as Collateral Trustee.(r)

	10	.3.22	Designated Asset Sale Proceeds Account Control Agreement, dated as of July 16, 2003, among the Company, Union Bank of California, N.A., and The Bank of New York, as Collateral Agent.(t)

	10	.4	Power Purchase and Other Agreements.

	10	.4.1	Master Transaction Agreement, dated September 7, 2005, among the Company, Calpine Energy Services, L.P., The Bear Stearns Companies Inc., and such other parties as may become party thereto from time to time. Approximately two pages of this Exhibit 10.3.1 have been omitted pursuant to a request for confidential treatment. The omitted language has been filed separately with the SEC.(aa)

	10	.4.2	Power Purchase and Sale Agreements with the State of California Department of Water Resources comprising Amended and Restated Cover Sheet and Master Power Purchase and Sale Agreement, dated as of April 22, 2002 and effective as of May 1, 2004, between Calpine Energy Services, L.P. and the State of California Department of Water Resources together with Amended and Restated Confirmation (“Calpine 1”), Amended and Restated Confirmation (“Calpine 2”), Amended and Restated Confirmation (“Calpine 3”) and Amended and Restated Confirmation (“Calpine 4”), each dated as of April 22, 2002, and effective as of May 1, 2002, between Calpine Energy Services, L.P., and the State of California Department of Water Resources.(bb)

	10	.5	Management Contracts or Compensatory Plans or Arrangements.

	10	.5.1	Employment Agreement, effective as of January 1, 2005, between the Company and Mr. Peter Cartwright.(cc)(dd)

	10	.5.2	Employment Agreement, effective as of December 12, 2005, between the Company and Mr. Robert P. May.(*)(dd)

	10	.5.3	Employment Agreement, effective as of January 30, 2006, between the Company and Mr. Scott J. Davido.(*)(dd)

	10	.5.5	Consulting Contract, dated as of January 1, 2005, between the Company and Mr. George J. Stathakis.(hh)(dd)

	10	.5.6	Form of Indemnification Agreement for directors and officers.(gg)(dd)

	10	.5.7	Form of Indemnification Agreement for directors and officers.(f)(dd)

	10	.5.8.1	Calpine Corporation 1996 Stock Incentive Plan and forms of agreements there under.(t)(dd)

	10	.5.8.2	Amendment to Calpine Corporation 1996 Stock Incentive Plan.(z)(dd)

	10	.5.9	Calpine Corporation U.S. Severance Program.(*)(dd)

	10	.5.10	Base Salary, Bonus, Stock Option Grant and Restricted Stock Summary Sheet.(cc)(dd)

	10	.511	Form of Stock Option Agreement.(cc)(dd)

	10	.5.12	Form of Restricted Stock Agreement.(cc)(dd)

	10	.5.13	Calpine Corporation 2003 Management Incentive Plan.(hh)(dd)

	10	.5.14	2000 Employee Stock Purchase Plan.(ii)(dd)

	12	.1	Statement on Computation of Ratio of Earnings to Fixed Charges.(*)

	21	.1	Subsidiaries of the Company.(*)

	24	.1	Power of Attorney of Officers and Directors of Calpine Corporation (set forth on the signature pages of this report).(*)

	31	.1	Certification of the Chairman, President and Chief Executive Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(*)

	31	.2	Certification of the Executive Vice President and Chief Financial Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(*)

142


Exhibit
Number			Description


	32	.1	Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.(*)

	99	.1	Acadia Power Partners, LLC and Subsidiary, Consolidated Financial Statements, July 31, 2005 and December 31, 2004 and 2003.(*)


(*)	Filed herewith.

(a)	Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K/ A filed with the SEC on September 14, 2004.

(b)	Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on June 23, 2005.

(c)	Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on July 13, 2005.

(d)	Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 2004, filed with the SEC on August 9, 2004.

(e)	Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 2005, filed with the SEC on August 9, 2005.

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

(g)	Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration Statement No. 333-06259) filed with the SEC on June 19, 1996.

(h)	Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2000, filed with the SEC on March 15, 2001.

(i)	Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated March 31, 2004, filed with the SEC on May 10, 2004.

(j)	Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 1997, filed with the SEC on August 14, 1997.

(k)	Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration Statement No. 333-41261) filed with the SEC on November 28, 1997.

(l)	Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration Statement No. 333-61047) filed with the SEC on August 10, 1998.

(m)	Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3/ A (Registration Statement No. 333-72583) filed with the SEC on March 8, 1999.

(n)	Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3 (Registration No. 333-76880) filed with the SEC on January 17, 2002.

(o)	Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on September 30, 2004.

(p)	Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K dated October 16, 2001, filed with the SEC on November 13, 2001.

(q)	Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3/ A (Registration No. 333-57338) filed with the SEC on April 19, 2001.

(r)	Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 2003, filed with the SEC on August 14, 2003.

(s)	Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated September 30, 2003, filed with the SEC on November 13, 2003.

(t)	Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2003, filed with the SEC on March 25, 2004.

143


(u)	Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on October 6, 2004.

(v)	Incorporated by reference to Calpine Corporation’s Registration Statement on Form 8-A/ A (Registration No. 001-12079) filed with the SEC on September 28, 2001.

(w)	Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on March 23, 2005.

(x)	This document has been omitted in reliance on Item 601(b)(4)(iii) of Regulation S-K. Calpine Corporation agrees to furnish a copy of such document to the SEC upon request.

(y)	Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated September 30, 2004, filed with the SEC on November 9, 2004.

(z)	Description of such Amendment is incorporated by reference to Item 1.01 of Calpine Corporation’s Current Report on Form 8-K filed with the SEC on September 20, 2005.

(aa)	Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated September 30, 2005, filed with the SEC on November 9, 2005.

(bb)	Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K/ A dated December 31, 2003, filed with the SEC on September 13, 2004

(cc)	Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on March 17, 2005.

(dd)	Management contract or compensatory plan or arrangement.

(ee)	Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on December 27, 2005.

(ff)	Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on February 3, 2006.

(gg)	Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-1/ A (Registration Statement No. 333-07497) filed with the SEC on August 22, 1996.

(hh)	Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2004, filed with the SEC on March 31, 2005.

(ii)	Incorporated by reference to Calpine Corporation’s Definitive Proxy Statement on Schedule 14A dated April 13, 2000, filed with the SEC on April 13, 2000.

144

SIGNATURES

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


	CALPINE CORPORATION


	By:	/s/ SCOTT J. DAVIDO


	Scott J. Davido
	Executive Vice President,
	Chief Financial Officer and
	Chief Restructuring Officer

Date: May 19, 2006

POWER OF ATTORNEY

KNOW ALL PERSONS BY THESE PRESENT: That the undersigned officers and directors of Calpine Corporation do hereby constitute and appoint Robert P. May and Scott J. Davido, and each of them, the lawful attorney and agent or attorneys and agents with power and authority to do any and all acts and things and to execute any and all instruments which said attorneys and agents, or either of them, determine may be necessary or advisable or required to enable Calpine Corporation to comply with the Securities and Exchange Act of 1934, as amended, and any rules or regulations or requirements of the Securities and Exchange Commission in connection with this Form 10-K Annual Report. Without limiting the generality of the foregoing power and authority, the powers granted include the power and authority to sign the names of the undersigned officers and directors in the capacities indicated below to this Form 10-K Annual Report or amendments or supplements thereto, and each of the undersigned hereby ratifies and confirms all that said attorneys and agents, or either of them, shall do or cause to be done by virtue hereof. This Power of Attorney may be signed in several counterparts.

IN WITNESS WHEREOF, each of the undersigned has executed this Power of Attorney as of the date indicated opposite the name.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Signature	Title	Date


/s/ ROBERT P. MAY Robert P. May	Chief Executive Officer and Director (Principal Executive Officer)	May 19, 2006

/s/ SCOTT J. DAVIDO Scott J. Davido	Executive Vice President, Chief Financial Officer and Chief Restructuring Officer (Principal Financial Officer)	May 19, 2006

/s/ CHARLES B. CLARK, JR. Charles B. Clark, Jr.	Senior Vice President and Corporate Controller (Principal Accounting Officer)	May 19, 2006

145


Signature	Title	Date


/s/ KENNETH T. DERR Kenneth T. Derr	Director	May 19, 2006

/s/ WILLIAM J. KEESE William J. Keese	Director	May 19, 2006

/s/ DAVID C. MERRITT David C. Merritt	Director	May 19, 2006

/s/ WALTER L. REVELL Walter L. Revell	Director	May 19, 2006

/s/ GEORGE J. STATHAKIS George J. Stathakis	Director	May 19, 2006

/s/ SUSAN WANG Susan Wang	Director	May 19, 2006

146

CALPINE CORPORATION AND SUBSIDIARIES

(DEBTOR-IN-POSSESSION)

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2005


			Page

Report of Independent Registered Public Accounting Firm				148
Consolidated Balance Sheets December 31, 2005 and 2004				150
Consolidated Statements of Operations for the Years Ended December 31, 2005, 2004, and 2003				152
Consolidated Statements of Comprehensive Income and Stockholders’ Equity (Deficit) For the Years Ended December 31, 2005, 2004, and 2003				153
Consolidated Statements of Cash Flows For the Years Ended December 31, 2005, 2004, and 2003				154
Notes to Consolidated Financial Statements For the Years Ended December 31, 2005, 2004, and 2003				157
	1.	Organization and Operations of the Company		157
	2.	Summary of Significant Accounting Policies		157
	3.	Bankruptcy Proceedings		176
	4.	Calpine Debtors Condensed Combined Financial Statements		181
	5.	Available-for-Sale Debt Securities		184
	6.	Impairments		185
	7.	Property, Plant and Equipment, Net, and Capitalized Interest		187
	8.	Goodwill and Other Intangible Assets		192
	9.	Acquisitions		193
	10.	Investments		195
	11.	Notes Receivable and Other Receivables		202
	12.	Canadian Power and Gas Trusts		203
	13.	Discontinued Operations		204
	14.	Debt		212
	15.	Notes Payable and Other Borrowings		218
	16.	Notes Payable to Calpine Capital Trusts		220
	17.	Preferred Interests		221
	18.	Capital Lease Obligations		223
	19.	CCFC Financing		225
	20.	CalGen Financing		226
	21.	Other Construction/ Project Financing		229
	22.	DIP Facility		232
	23.	Senior Notes		234
	24.	Liabilities Subject to Compromise		234
	25.	Provision for Income Taxes		245
	26.	Employee Benefit Plans		248
	27.	Stockholders’ Equity (Deficit)		250
	28.	Customers		251
	29.	Derivative Instruments		253
	30.	Earnings (Loss) per Share		258
	31.	Commitments and Contingencies		260
	32.	Operating Segments		275
	33.	California Power Market		277
	34.	Subsequent Events		280
	35.	Quarterly Consolidated Financial Data (unaudited)		284

147

Report of Independent Registered Public Accounting Firm

To the Board of Directors

and Stockholders of Calpine Corporation:

We have completed integrated audits of Calpine Corporation’s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005, and an audit of its 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements and financial statement schedule

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Calpine Corporation and its subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As described in Note 3 to the consolidated financial statements, the Company has suffered recurring losses from operations and on December 20, 2005, filed a voluntary petition for reorganization under Chapter 11 of the United States Bankruptcy Code, which raises substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 3. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

As discussed in Note 2 to the consolidated financial statements, the Company changed the manner in which they calculate diluted earnings per share effective April 1, 2004, changed the manner in which they report gains and losses on certain derivative instruments not held for trading purposes and account for certain derivative contracts with a price adjustment feature effective October 1, 2003, changed the manner in which they account for variable interests in special purpose entities effective December 31, 2003, and changed the manner in which they account for variable interests in all non-special purpose entities effective March 31, 2004.

Internal control over financial reporting

Also, we have audited management’s assessment, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A, that Calpine Corporation did not maintain effective internal control over financial reporting as of December 31, 2005, because the Company did not maintain effective controls over the accounting for the determination of deferred income tax assets and liabilities and the related income tax provision (benefit), based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was

148

maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. The following material weakness has been identified and included in management’s assessment. As of December 31, 2005, the Company did not maintain effective controls over the accounting for the determination of deferred income tax assets and liabilities and the related income tax provision (benefit). Specifically, the Company did not have effective controls in place to timely reconcile the underlying data being provided by the accounting department to the tax department to ensure the accuracy and validity of the Company’s tax calculations, principally related to the book and tax basis of its property, plant and equipment. This control deficiency could result in a misstatement of deferred income tax assets and liabilities, valuation allowances and the related income tax provision (benefit) that could result in a material misstatement to annual or interim financial statements that would not be prevented or detected. This material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2005 consolidated financial statements, and our opinion regarding the effectiveness of the Company’s internal control over financial reporting does not affect our opinion on those consolidated financial statements.

In our opinion, management’s assessment that Calpine Corporation did not maintain effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control — Integrated Framework issued by the COSO. Also, in our opinion, because of the effect of the material weakness described above on the achievement of the objectives of the control criteria, Calpine Corporation has not maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control — Integrated Framework issued by the COSO.

As disclosed in the fifth paragraph of Management’s Report on Internal Control Over Financial reporting, subsequent to December 31, 2005, the Company has experienced events which the Company expects to have an adverse effect on the Company’s internal control over financial reporting.

/s/ PricewaterhouseCoopers LLP

Los Angeles, California

May 19, 2006

149

CALPINE CORPORATION AND SUBSIDIARIES

(DEBTOR-IN-POSSESSION)

CONSOLIDATED BALANCE SHEETS

December 31, 2005 and 2004


			2005		2004

			(In thousands, except
			share and per share amounts)
ASSETS
Current assets:
	Cash and cash equivalents		$	785,637	$	718,023
	Accounts receivable, net of allowance of $12,686 and $7,317			1,025,886		1,043,061
	Margin deposits and other prepaid expense			434,363		439,698
	Inventories			150,444		171,639
	Restricted cash			457,510		593,304
	Current derivative assets			489,499		324,206
	Current assets held for sale			39,542		142,096
	Other current assets			45,156		131,538

		Total current assets		3,428,037		3,563,565

	Restricted cash, net of current portion			613,440		157,868
	Notes receivable, net of current portion			165,124		203,680
	Project development costs			24,232		150,179
	Investments			83,620		373,108
	Deferred financing costs			210,809		406,844
	Prepaid lease, net of current portion			515,828		424,586
	Property, plant and equipment, net			14,119,215		18,397,743
	Goodwill			45,160		45,160
	Other intangible assets, net			54,143		68,423
	Long-term derivative assets			714,226		506,050
	Long-term assets held for sale			—		2,260,401
	Other assets			570,963		658,481

		Total assets	$	20,544,797	$	27,216,088

150

CALPINE CORPORATION AND SUBSIDIARIES

(DEBTOR-IN-POSSESSION)

CONSOLIDATED BALANCE SHEETS — (Continued)


			2005			2004

			(In thousands, except
			share and per share amounts)

LIABILITIES & STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities:
	Accounts payable		$	399,450		$	980,280
	Accrued payroll and related expense			29,483			87,659
	Accrued interest payable			195,980			385,794
	Income taxes payable			99,073			57,234
	Notes payable and other borrowings, current portion			188,221			200,076
	Preferred interests, current portion			9,479			8,641
	Capital lease obligations, current portion			191,497			5,490
	CCFC financing, current portion			784,513			3,208
	CalGen financing, current portion			2,437,982			—
	Construction/project financing, current portion			1,160,593			93,393
	Senior notes and term loans, current portion			641,652			718,449
	Current derivative liabilities			728,894			356,030
	Current liabilities held for sale			—			86,458
	Other current liabilities			275,595			302,680

		Total current liabilities		7,142,412			3,285,392
	Notes payable and other borrowings, net of current portion			558,353			769,490
	Notes payable to Calpine Capital Trusts			—			517,500
	Preferred interests, net of current portion			583,417			497,896
	Capital lease obligations, net of current portion			95,260			283,429
	CCFC financing, net of current portion			—			783,542
	CalGen financing			—			2,395,332
	Construction/project financing, net of current portion			1,200,432			1,905,658
	Convertible Senior Notes			—			1,255,298
	DIP Facility			25,000			—
	Senior notes, net of current portion			—			8,532,664
	Deferred income taxes, net of current portion			353,386			885,754
	Deferred revenue			138,653			114,202
	Long-term derivative liabilities			919,084			516,230
	Long-term liabilities held for sale			—			176,298
	Other liabilities			151,437			316,285

Total liabilities not subject to compromise				11,167,434			22,234,970
Liabilities subject to compromise				14,610,064			—
Commitments and contingencies (see Note 31)
Minority interests				275,384			393,445
Stockholders’ equity (deficit):
	Preferred stock, $.001 par value per share; authorized 10,000,000 shares; none issued and outstanding in 2005 and 2004			—			—
	Common stock, $.001 par value per share; authorized 2,000,000,000 shares; issued and outstanding 569,081,863 shares in 2005 and 536,509,231 shares in 2004			569			537
	Additional paid-in capital			3,265,458			3,151,577
	Additional paid-in capital, loaned shares			258,100			258,100
	Additional paid-in capital, returnable shares			(258,100	)		(258,100	)
	Retained earnings (accumulated deficit)			(8,613,160	)		1,326,048
	Accumulated other comprehensive income (loss)			(160,952	)		109,511

		Total stockholders’ equity (deficit)		(5,508,085	)		4,587,673

		Total liabilities and stockholders’ equity (deficit)	$	20,544,797		$	27,216,088

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

151

CALPINE CORPORATION AND SUBSIDIARIES

(DEBTOR-IN-POSSESSION)

CONSOLIDATED STATEMENTS OF OPERATIONS


			For the Years Ended December 31,

			2005			2004			2003

			(In thousands, except per share
			amounts)
Revenue:
Electricity and steam revenue			$	6,278,840		$	5,165,347		$	4,291,174
Transmission sales revenue				11,479			20,003			15,347
Sales of purchased power and gas for hedging and optimization				3,667,992			3,376,293			4,033,193
Mark-to-market activities, net				11,385			13,404			(26,439	)
Other revenue				142,962			73,335			107,895

	Total revenue			10,112,658			8,648,382			8,421,170

Cost of revenue:
Plant operating expense				717,393			727,911			599,324
Royalty expense				36,948			28,370			24,634
Transmission purchase expense				87,598			74,818			34,690
Purchased power and gas expense for hedging and optimization				3,417,153			3,198,690			3,962,613
Fuel expense				4,623,286			3,587,416			2,636,744
Depreciation and amortization expense				506,441			446,018			381,980
Operating plant impairments				2,412,586			—			—
Operating lease expense				104,709			105,886			112,070
Other cost of revenue				151,467			99,324			62,288

	Total cost of revenue			12,057,581			8,268,433			7,814,343

		Gross profit (loss)		(1,944,923	)		379,949			606,827
(Income) loss from unconsolidated investments				(12,119	)		14,088			(75,724	)
Equipment, development project and other impairments				2,117,665			46,894			67,979
Long-term service agreement cancellation charge				34,095			7,735			16,255
Project development expense				27,623			19,889			18,208
Research and development expense				19,235			18,396			10,630
Sales, general and administrative expense				239,857			220,567			204,106

Income (loss) from operations				(4,371,279	)		52,380			365,373
Interest expense				1,397,288			1,095,419			695,504
Distributions on trust preferred securities				—			—			46,610
Interest (income)				(84,226	)		(54,766	)		(39,190	)
Minority interest expense				42,454			34,735			27,330
(Income) from repurchase of various issuances of debt				(203,341	)		(246,949	)		(278,612	)
Other (income) expense, net				72,388			(121,062	)		(46,564	)

Income (loss) before reorganization items, provision (benefit) for income taxes, discontinued operations and cumulative effect of a change in accounting principle				(5,595,842	)		(654,997	)		(39,705	)
Reorganization items				5,026,510			—			—

Income (loss) before provisions (benefit) for income taxes, discontinued operations and cumulative effect of a change in accounting principle				(10,622,352	)		(654,997	)		(39,705	)
Benefit for income taxes				(741,398	)		(235,314	)		(26,433	)

Loss before discontinued operations and cumulative effect of a change in accounting principle				(9,880,954	)		(419,683	)		(13,272	)
Discontinued operations, net of tax provision of $131,746, $8,860 and $20,513				(58,254	)		177,222			114,351
Cumulative effect of a change in accounting principle, net of tax provision of $ — , $ — , and $110,913				—			—			180,943

	Net income (loss)		$	(9,939,208	)	$	(242,461	)	$	282,022

Basic earnings per common share:
	Weighted average shares of common stock outstanding			463,567			430,775			390,772
	Income (loss) before discontinued operations and cumulative effect of a change in accounting principle		$	(21.32	)	$	(0.97	)	$	(0.03	)
	Discontinued operations, net of tax			(0.12	)		0.41			0.29
	Cumulative effect of a change in accounting principle, net of tax			—			—			0.46

	Net income (loss)		$	(21.44	)	$	(0.56	)	$	0.72

Diluted earnings per common share:
	Weighted average shares of common stock outstanding before dilutive effect of certain convertible securities			463,567			430,775			396,219
	Income (loss) before discontinued operations and cumulative effect of a change in accounting principle		$	(21.32	)	$	(0.97	)	$	(0.03	)
	Discontinued operations, net of tax			(0.12	)		0.41			0.29
	Cumulative effect of a change in accounting principle, net of tax			—			—			0.45

		Net income (loss)	$	(21.44	)	$	(0.56	)	$	0.71

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

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME AND

STOCKHOLDERS’ EQUITY (DEFICIT)

For the Years Ended December 31, 2005, 2004, and 2003


											Accumulated Other Comprehensive
											Income (Loss)
											Net Unrealized Gain (Loss) from
(in thousands except per share amounts)								Retained												Total
					Additional			Earnings						Available-			Foreign			Stockholders’
			Common		Paid-In			(Accumulated			Cash Flow			For-Sale			Currency			Equity
			Stock		Capital			Deficit)			Hedges(1)			Investments			Translation			(Deficit)

Balance, January 1, 2003			$	381	$	2,802,503		$	1,286,487		$	(224,414	)	$	—		$	(13,043	)	$	3,851,914
	Issuance of 34,194,063 shares of common stock, net of issuance costs			34		175,063			—			—			—			—			175,097
	Tax benefit from stock options exercised and other			—		2,097			—			—			—			—			2,097
	Stock compensation expense			—		16,072			—			—			—			—			16,072

		Total stockholders’ equity (deficit) before comprehensive income items																			4,045,180
	Net income			—		—			282,022			—			—			—			282,022
	Comprehensive pre-tax gain before reclassification adjustment			—		—			—			112,481			—			—			112,481
	Reclassification adjustment for loss included in net loss			—		—			—			55,620			—			—			55,620
	Income tax provision			—		—			—			(74,106	)		—			—			(74,106	)
	Foreign currency translation gain			—		—			—			—			—			200,056			200,056

		Total comprehensive income																			576,073
Balance, December 31, 2003			$	415	$	2,995,735		$	1,568,509		$	(130,419	)	$	—		$	187,013		$	4,621,253

	Issuance of 32,499,106 shares of common stock, net of issuance costs			33		130,141			—			—			—			—			130,174
	Issuance of 89,000,000 shares of loaned common stock			89		258,100			—			—			—			—			258,189
	Returnable shares					(258,100	)		—			—			—			—			(258,100	)
	Tax benefit from stock options exercised and other			—		4,773			—			—			—			—			4,773
	Stock compensation expense					20,928															20,928

		Total stockholders’ equity (deficit) before comprehensive income items																			155,964
	Net loss			—		—			(242,461	)		—			—			—			(242,461	)
	Comprehensive pre-tax gain (loss) before reclassification adjustment			—		—			—			(106,071	)		19,239			—			(86,832	)
	Reclassification adjustment for (gain) loss included in net loss			—		—			—			89,888			(18,281	)		—			71,607
	Income tax benefit (provision)			—		—			—			6,451			(376	)		—			6,075
	Foreign currency translation gain			—		—			—			—			—			62,067			62,067

		Total comprehensive income																			(189,544	)
Balance, December 31, 2004			$	537	$	3,151,577		$	1,326,048		$	(140,151	)	$	582		$	249,080		$	4,587,673

	Issuance of 32,572,632 shares of common stock, net of issuance costs			32		97,608			—			—			—			—			97,640
	Stock compensation expense			—		16,273			—			—			—			—			16,273

		Total stockholders’ equity (deficit) before comprehensive income items																			113,913
	Net loss			—		—			(9,939,208	)		—			—			—			(9,939,208	)
	Comprehensive pre-tax gain (loss) before reclassification adjustment			—		—			—			(435,583	)		(958	)		—			(436,541	)
	Reclassification adjustment for (gain) loss included in net loss			—		—			—			405,524			—			—			405,524
	Income tax benefit (provision)			—		—			—			11,483			376			—			11,859
	Foreign currency translation loss			—		—			—			—			—			(251,305	)		(251,305	)

		Total comprehensive income																			(10,209,671	)
Balance, December 31, 2005			$	569	$	3,265,458		$	(8,613,160	)	$	(158,727	)	$	—		$	(2,225	)	$	(5,508,085	)


(1)	Includes AOCI from cash flow hedges held by unconsolidated investees. At December 31, 2005, 2004 and 2003, these amounts were $0, $1,698 and $6,911, respectively.

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

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CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2005, 2004, and 2003


			2005			2004			2003

			(In thousands)
Cash flows from operating activities:
	Net income (loss)		$	(9,939,208	)	$	(242,461	)	$	282,022
	Adjustments to reconcile net income to net cash provided by operating activities:
	Depreciation and amortization(1)			760,023			833,375			732,410
	Oil and gas impairments			—			202,120			2,931
	Operating plant impairments			2,412,586			—			—
	Equipment, development project and other impairments			2,361,435			42,374			56,458
	Deferred income taxes, net			(609,652	)		(226,454	)		150,323
	Gain on sale of assets			(326,176	)		(349,611	)		(65,351	)
	Foreign currency transaction loss (gain)			53,586			25,122			33,346
	Cumulative change in accounting principle			—			—			(180,943	)
	Income from repurchase of various issuances of debt			(203,341	)		(246,949	)		(278,612	)
	Minority interest expense			42,454			34,735			27,330
	Change in net derivative liability			25,035			14,743			59,490
	(Income) loss from unconsolidated investments in power projects			(12,280	)		9,717			(76,704	)
	Distributions from unconsolidated investments in power projects			24,962			29,869			141,627
	Stock compensation expense			19,283			20,929			16,072
	Other			2,146			—			—
	Reorganization items			5,012,765			—			—
Change in operating assets and liabilities, net of effects of acquisitions:
	Accounts receivable			(42,437	)		(99,447	)		(221,243	)
	Other current assets			(23,266	)		(118,790	)		(160,672	)
	Other assets			(95,722	)		(95,699	)		(143,654	)
	Accounts payable and accrued expense			(111,282	)		231,827			(111,901	)
	Other liabilities			(59,272	)		(55,505	)		27,630

		Net cash provided by (used in) operating activities		(708,361	)		9,895			290,559

154


			2005			2004			2003

			(In thousands)
Cash flows from investing activities:
	Purchases of property, plant and equipment			(773,988	)		(1,545,480	)		(1,886,013	)
	Disposals of property, plant and equipment			2,066,242			1,066,481			206,804
	Disposal of subsidiary			—			85,412			—
	Disposal of investment			36,900			—			—
	Acquisitions, net of cash acquired			—			(187,786	)		(6,818	)
	Advances to joint ventures			—			(8,788	)		(54,024	)
	Sale of collateral securities			—			93,963			—
	Project development costs			(14,880	)		(29,308	)		(35,778	)
	Purchases of HIGH TIDES securities			—			(110,592	)		—
	Disposal of HIGH TIDES securities			132,500			—			—
	Cash flows from derivatives not designated as hedges			102,698			16,499			42,342
	(Increase) decrease in restricted cash			(535,621	)		210,762			(766,841	)
	(Increase) decrease in notes receivable			837			10,235			(21,135	)
	Cash effect of deconsolidation of Canadian Operations			(90,897	)		—			—
	Other			(6,334	)		(2,824	)		6,098

		Net cash provided by (used in) investing activities		917,457			(401,426	)		(2,515,365	)

Cash flows from financing activities:
	Borrowings from notes payable and lines of credit			6,289			101,781			1,672,871
	Repayments of notes payable and lines of credit			(204,074	)		(256,141	)		(1,768,704	)
	Borrowings from project financing			750,484			3,743,930			1,548,601
	Repayments of project financing			(185,775	)		(3,006,374	)		(1,638,519	)
	Proceeds from issuance of Convertible Notes			650,000			867,504			650,000
	Repurchases of Convertible Senior Notes			(15	)		(834,765	)		(455,447	)
	DIP facility borrowings			25,000			—			—
	Repayments and repurchases of senior notes			(880,063	)		(871,309	)		(1,139,812	)
	Proceeds from issuance of senior notes			—			878,814			3,892,040
	Proceeds from issuance of preferred interests(2)			865,000			360,000			—
	Redemptions of preferred interests			(778,641	)		(97,095	)		(368	)
	Repayment of Calpine Capital Trust convertible debentures			(517,500	)		(483,500	)		—
	Proceeds from Deer Park prepaid commodity contract			263,623			—			—
	Costs of Deer Park prepaid commodity contract			(20,315	)		—			—
	Proceeds from issuance of common stock			4			98			15,951
	Proceeds from income trust offerings			—			—			159,727
	Financing costs			(96,966	)		(204,139	)		(323,167	)
	Other			(36,980	)		(31,752	)		10,813

		Net cash provided by (used in) financing activities		(159,929	)		167,052			2,623,986

155


		2005			2004			2003

		(In thousands)
Effect of exchange rate changes on cash and cash equivalents			(181	)		16,101			13,140
Net increase (decrease) in cash and cash equivalents including discontinued operations cash			48,986			(208,378	)		412,320
Change in discontinued operations cash classified as current assets held for sale			18,628			(28,427	)		(24,863	)

Net increase (decrease) in cash and cash equivalents			67,614			(236,805	)		387,457
Cash and cash equivalents, beginning of period			718,023			954,828			567,371

Cash and cash equivalents, end of period		$	785,637		$	718,023		$	954,828

Cash paid during the period for:
	Interest, net of amounts capitalized	$	1,315,538		$	939,243		$	462,714
	Income taxes	$	26,104		$	22,877		$	18,415
	Reorganization items included in operating activities	$	13,744		$	—		$	—


(1)	Includes depreciation and amortization that is also recorded in sales, general and administrative expense and interest expense.

(2)	2005 amount relates to the $260.0 million Calpine Jersey II, $155.0 million Metcalf, $150.0 million CCFC, and $300.0 million CCFC offerings of redeemable preferred securities. See Note 17 of the accompanying notes.

Schedule of non-cash investing and financing activities:


	•	2005 contribution of turbines to Greenfield joint venture investment resulting in a non-cash decrease in property, plant and equipment of $62.1 million, and non-cash increases in Investments of $40.7 million and in other assets of $21.4 million.

	•	2005 Consolidation of our Acadia joint venture investment resulting in non-cash increases in property, plant and equipment of $478.4 million and minority interest of $275.4 million and a non-cash decrease in Investments of $203.0 million.

	•	2005 issuance of 27.5 million shares of Calpine common stock in exchange for $94.3 million in principal amount at maturity of 2014 Convertible Notes.

	•	2004 issuance of 24.3 million shares of Calpine common stock in exchange for $40.0 million par value of HIGH TIDES I and $75.0 million par value of HIGH TIDES II.

	•	2004 capital lease entered into for the King City facility for an initial asset balance of $114.9 million.

	•	2004 issuance of 89 million shares of Calpine common stock pursuant to a Share Lending Agreement. See Note 27 for more information.

	•	2004 acquisition of the remaining 50% interest in the Aries Power Plant for net amounts of $3.7 million cash and $220.0 million of assumed liabilities, including debt of $173.2 million.

	•	2003 issuance of 30 million shares of Calpine common stock in exchange for $182.5 million of debt, convertible debt and preferred securities.

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

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(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the Years Ended December 31, 2005, 2004, and 2003


1.	Organization and Operations of the Company

Calpine Corporation, a Delaware corporation, and subsidiaries (collectively, “we,” “us,” or “our”) are engaged in the generation of electricity in the U.S. and Canada and were engaged in the generation of electricity in the United Kingdom until the sale of Saltend in July 2005. We are involved in the development, construction, ownership and operation of power generation facilities and the sale of electricity and its by-product, thermal energy, primarily in the form of steam. We have ownership interests in, and operate, gas-fired power generation and cogeneration facilities and gas pipelines, geothermal steam fields and geothermal power generation facilities in the United States. Until we sold our remaining oil and gas assets in July 2005, we also had ownership interests in gas fields and gathering systems in the United States. In Canada, we have ownership interests in, and operate, gas-fired power generation facilities. In Mexico, we were a joint venture participant in a gas-fired power generation facility under construction but, in April 2006, we consummated the sale of our interest in the facility to our joint venture partners. See Note 34 for more information on this sale. We market electricity produced by our generating facilities to utilities and other third party purchasers. Thermal energy produced by the gas-fired power cogeneration facilities is primarily sold to industrial users. We offer to third parties energy procurement, settlement, scheduling and risk management services, and combustion turbine component parts. See Note 13 for a discussion of our discontinued operations.

On December 20 and 21, 2005, we and many of our direct and indirect wholly owned subsidiaries in the United States filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court and, in Canada, 12 of our indirect, wholly owned Canadian subsidiaries were granted relief under the CCAA. Thereafter additional wholly owned indirect subsidiaries of ours also commenced Chapter 11 cases under the Bankruptcy Code in the U.S. Bankruptcy Court. Additional subsidiaries could file in the future. The Chapter 11 cases of the U.S. Debtors are being jointly administered for procedural purposes only in the U.S. Bankruptcy Court under the case captioned In re Calpine Corporation et al., Case No. 05-60200 (BRL), and the CCAA cases of the Canadian Debtors are being jointly administered by the Canadian Court. See Note 3 for a discussion of the bankruptcy cases.


2.	Summary of Significant Accounting Policies

Principles of Consolidation — The accompanying consolidated financial statements include accounts of us and our wholly owned and majority-owned subsidiaries, except for most of our Canadian and other foreign subsidiaries, which were deconsolidated on December 20, 2005, due to filing under the CCAA in Canada. For further information regarding the deconsolidation of the Canadian entities, see Note 10. The results of operation of these deconsolidated entities from December 21, 2005, to December 31, 2005, were insignificant to our overall results of operations. We adopted FASB Interpretation No. 46, “Consolidation of Variable Interest Entities, an interpretation of ARB 51” for our investments in SPEs as of December 31, 2003. These consolidated financial statements as of December 31, 2005, 2004 and 2003, and for the twelve months ended December 31, 2005 and 2004, also include the accounts of those special purpose VIEs for which we are the Primary Beneficiary. We adopted FIN 46, as revised for our investments in non-SPE VIEs on March 31, 2004. These consolidated financial statements as of December 31, 2005 and 2004, and for the twelve and nine months ended December 31, 2005 and 2004, respectively, include the accounts of non-special purpose VIEs for which we are the Primary Beneficiary. Certain less-than-majority-owned subsidiaries are accounted for using the equity method or cost method. For equity method investments, our share of income is calculated according to our equity ownership or according to the terms of the appropriate partnership agreement. For cost method investments, income is recognized when equity distributions are received. All intercompany accounts and transactions are eliminated in consolidation.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Accounting for Reorganization — The accompanying consolidated financial statements of Calpine Corporation have been prepared in accordance with Statement of Position 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code,” and on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. However, as a result of the bankruptcy filings, such realization of assets and satisfaction of liabilities are subject to a significant number of uncertainties. Calpine’s consolidated financial statements do not reflect adjustments that might be required if we (or each of the Calpine Debtors) are unable to continue as a going concern. SOP 90-7 requires the following for Debtor entities:


	•	Reclassification of unsecured or under-secured pre-petition liabilities to a separate line item in the balance sheet which we have called Liabilities Subject to Compromise;

	•	Non-accrual of interest expense for financial reporting purposes, to the extent not paid during bankruptcy and not expected to be an allowable claim. However, unpaid contractual interest is calculated for disclosure purposes.

	•	Adjust any unamortized deferred financing costs and discounts/premiums associated with debt classified as LSTC to reflect the expected amount of the probable allowed claim. As a result of applying this guidance, we have written off approximately $148.1 million for the year ended December 31, 2005, as a charge to reorganization items related to certain debt instruments deemed subject to compromise, in order to reflect this debt at the amount of the probable allowed claim;

	•	Segregation of reorganization items (direct and incremental costs, such as professional fees, of being in bankruptcy) as a separate line item in the statement of operations outside of income from continuing operations;

	•	Evaluation of actual or potential bankruptcy claims, which are not already reflected as a liability on the balance sheet, under SFAS No. 5, “Accounting for Contingencies.” Due to the close proximity of our bankruptcy filing date to our fiscal year-end date, we have been presented with only a limited number of significant claims meeting the SFAS No. 5 criteria (probable and can be reasonably estimated) to be accrued at December 31, 2005, the most significant of which we expect could total approximately $3.8 billion related to U.S. parent guarantees of our deconsolidated Canadian subsidiary debt. If valid unrecorded claims, including parent guarantees of subsidiary debt, meeting the SFAS No. 5 criteria are presented to us in future periods, we would accrue for these amounts, also at the expected amount of the allowed claim rather than at the expected settlement amount.

	•	Disclosure of condensed combined debtor entity financial information, if our consolidated financial statements include material subsidiaries that did not file for bankruptcy protection.

	•	Upon confirmation of our plan of reorganization, and our emergence from Chapter 11 reorganization, “fresh-start reporting” must be adopted if the reorganization value of our assets immediately before the date of confirmation is less than the total of all post-petition liabilities and allowed claims, and if holders of existing voting shares immediately before confirmation receive less than 50 percent of the voting shares of the emerging entity. Essentially, the reorganization value of the entity, as mutually agreed to by the debtor-in-possession and its creditors, would be allocated to the entity’s assets in conformity with the procedures specified by SFAS No. 141, “Business Combinations.”

Impairment Evaluation of Long-Lived Assets, Including Intangibles and Investments — We evaluate our property, plant and equipment, equity method investments, patents and specifically identifiable intangibles, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Factors which could trigger an impairment include significant underperformance relative to historical or projected future operating results, significant changes in the manner of our use of the acquired

158

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(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

assets or the strategy for our overall business, significant negative industry or economic trends or a determination that a suspended project is not likely to be completed.

In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we evaluate the impairment of our operating plants by first estimating projected undiscounted pre-interest expense and pre-tax expense cash flows associated with the asset. The significant assumptions that we use in our undiscounted future cash flow estimates include (1) the future supply and demand relationships for electricity and natural gas, (2) the expected pricing for those commodities, (3) the likelihood of continued development, (4) the resultant spark spreads in the various regions where we generate and (5) that we will hold these assets over their depreciable lives. If we conclude that it is more likely than not that an operating power plant will be sold or abandoned, we perform an evaluation of the probability-weighted expected future cash flows, giving consideration to both (1) the continued ownership and operation of the power plant, and (2) consummating a sale transaction or abandonment of the plant. In the event such cash flows are not expected to be sufficient to recover the recorded value of the assets, the assets are written down to their estimated fair values, which are determined by the best available information which may include but not be limited to, comparable sales, discounted cash flow valuations and third party appraisals. Certain of our generating assets are located in regions with depressed demands and market spark spreads. Our forecasts assume that spark spreads will increase in future years in these regions as the supply and demand relationships improve. There can be no assurance that this will occur. Further, utilizing this methodology, we have recently determined that certain of our operating plants have been impaired. See Note 6 for a discussion of impairment charges recorded during the fourth quarter of 2005 related to these operating plants.

All construction and development projects and unassigned turbines are reviewed for impairment whenever there is an indication of potential reduction in fair value. Equipment assigned to such projects is not evaluated for impairment separately, as it is integral to the assumed future operations of the project to which it is assigned. If it is determined that it is no longer probable that the projects will be completed and all capitalized costs recovered through future operations, the carrying values of the projects would be written down to the recoverable value in accordance with the provisions of SFAS No. 144.

A significant portion of our overall cost of constructing a power plant is the cost of the gas turbine-generators, steam turbine-generators and related equipment (collectively the “turbines”). The turbines are ordered primarily from three large manufacturers under long-term, build to order contracts. Payments are generally made over a two to four year period for each turbine. The turbine prepayments are included as a component of construction-in-progress if the turbines are assigned to specific projects probable of being built, and interest is capitalized on such costs. Turbines assigned to specific projects are not evaluated for impairment separately from the project as a whole. Prepayments for turbines that are not assigned to specific projects that are probable of being built are carried in other assets, and interest is not capitalized on such costs. Additionally, our commitments relating to future turbine payments are discussed in Note 31 of the Notes to Consolidated Financial Statements.

To the extent that there are more turbines on order than are allocated to specific construction projects, we determine the probability that new projects will be initiated to utilize the turbines or that the turbines will be resold to third parties. Completion of in-progress projects or the initiation of new projects is uncertain due to our recent bankruptcy filings. We have reviewed our unassigned equipment for potential impairment based on probability-weighted alternatives of utilizing the equipment for future projects versus selling the equipment. Utilizing this methodology, we have currently, and in the past, determined that certain equipment held for use has been impaired. We have recorded these impairment charges to the “Equipment, development project and other impairments” line of the Consolidated Statement of Operations. See Note 6 for a discussion of impairment charges recorded during the fourth quarter of 2005 related to our development projects and unassigned turbines.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For equity and cost method investments (including notes receivables from those entities) and assets identified as held for sale, the book value is compared to the estimated fair value to determine if an impairment loss is required. For equity method investments, we would record a loss when the decline in value is other-than-temporary.

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

Reclassifications — Certain prior years’ amounts in the consolidated financial statements were reclassified to conform to the 2005 presentation. Sales of purchased gas for hedging and optimization were combined with sales of purchased power for hedging and optimization and are now being reported as sales of purchased power and gas for hedging and optimization. Purchased gas expense for hedging and optimization was combined with purchased power expense for hedging and optimization and is now being reported as purchased power and gas expense for hedging and optimization. Equipment cancellation and impairment cost is now being reported as equipment, development project and other impairments. Oil and gas sales and oil and gas operating expense were reclassified to other revenue and other cost of revenue, respectively.

Certain prior year amounts have also been reclassified to conform with discontinued operations presentation. See Note 13 for information on our discontinued operations.

Use of Estimates in Preparation of Financial Statements — The preparation of financial statements in conformity with GAAP in the U.S. requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during the reporting period. Actual results could differ from those estimates. The most significant estimates with regard to these financial statements relate to useful lives and carrying values of assets (including the carrying value of projects in development, construction, and operation), provision for income taxes, fair value calculations of derivative instruments and associated reserves, capitalization of interest, primary beneficiary determination for our investments in VIEs, expected amount of bankruptcy claims, the outcome of pending litigation, and prior to the divestiture of our remaining oil and gas assets (see Note 13 for more information regarding this sale), estimates of oil and gas reserve quantities used to calculate depletion, depreciation and impairment of oil and gas property and equipment.

Foreign Currency Translation — We own subsidiary entities in several countries, most of which have been deconsolidated (see Note 4) due to the filings under the CCAA of approximately 12 of our Canadian entities on December 20, 2005. These entities generally have functional currencies other than the U.S. dollar; in most cases, the functional currency was consistent with the local currency of the host country where the particular entity was located. In accordance with FASB No. 52, “Foreign Currency Translation,” we historically translated the financial statements of our foreign subsidiaries from their respective functional currencies into the U.S. dollar, which is our reporting currency.

For the years ended December 31, 2005, 2004 and 2003, we recognized foreign currency transaction losses from continuing operations of $14.7 million, $41.6 million and $34.5 million, respectively, which were recorded within Other Income on our Consolidated Statements of Operations. Additionally, we settled a series of forward foreign exchange contracts associated with the sale of our Canadian oil and gas assets in 2004. See Note 13 for further discussion of the settlement of these contracts within discontinued operations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Fair Value of Financial Instruments — The carrying value of accounts receivable, marketable securities, accounts payable and other payables approximate their respective fair values due to their short maturities. See Note 23 for disclosures regarding the fair value of the senior notes.

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

We have certain project finance facilities and lease agreements that establish segregated cash accounts. These accounts have been pledged as security in favor of the lenders to such project finance facilities, and the use of certain cash balances on deposit in such accounts with our project financed securities is limited to the operations of the respective projects. At December 31, 2005 and 2004, $518.1 million and $284.4 million, respectively, of the cash and cash equivalents balance that was unrestricted was subject to such project finance facilities and lease agreements. In addition, at December 31, 2005 and 2004, $1.0 million and $232.4 million, respectively, of our consolidated cash and cash equivalents was held in bank accounts outside the United States. The decrease was due to the sale of Saltend and the deconsolidation of the majority of our Canadian and other foreign subsidiaries.

Accounts Receivable and Accounts Payable — Accounts receivable and payable represent amounts due from customers and owed to vendors. Accounts receivable are recorded at invoiced amounts, net of reserves and allowances and do not bear interest. Reserve and allowance accounts represent our best estimate of the amount of probable credit losses in our existing accounts receivable. We review the financial condition of customers prior to granting credit. We determine the allowance based on a variety of factors, including the length of time receivables are past due, economic trends and conditions affecting our customer base, significant one-time events and historical write-off experience. Also, specific provisions are recorded for individual receivables when we become aware of a customer’s inability to meet its financial obligations, such as in the case of bankruptcy filings or deterioration in the customer’s operating results or financial position. We review the adequacy of our reserves and allowances quarterly. Generally, past due balances over 90 days and over a specified amount are individually reviewed for collectibility. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote.

The accounts receivable and payable balances also include settled but unpaid amounts relating to hedging, balancing, optimization and trading activities of CES. Some of these receivables and payables with individual counterparties are subject to master netting agreements whereby we legally have a right of offset and we settle the balances net. However, for balance sheet presentation purposes and to be consistent with the way we present the majority of amounts related to hedging, balancing and optimization activities in our Consolidated Statements of Operations under SAB No. 101 “Revenue Recognition in Financial Statements,” as amended by SAB No. 104 “Revenue Recognition” and Issue No. 99-19 “Reporting Revenue Gross as a Principal Versus Net as an Agent,” we present our receivables and payables on a gross basis. CES receivable balances (which comprise the majority of the accounts receivable balance at December 31, 2005) greater than 30 days past due are individually reviewed for collectibility, and if deemed uncollectible, are charged off against the allowance accounts or reversed out of revenue after all means of collection have been exhausted and the potential for recovery is considered remote. We do not have any off-balance-sheet credit exposure related to our customers.

Margin Deposits — As of December 31, 2005 and 2004, we had margin deposits with third parties of $287.5 million and $276.5 million, respectively, to support commodity transactions. Counterparties had deposited with us $27.0 million and $27.6 million as margin deposits at December 31, 2005 and 2004, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Inventories — Our inventories primarily include spare parts, stored gas and oil as well as work-in-process. Inventories are valued at the lower of cost or market. The cost for spare parts as well as stored gas and oil is generally determined using the weighted average cost method. Work-in-process is generally determined using the specific identification method and represents the value of manufactured goods during the manufacturing process. The inventory balance at December 31, 2005, was $150.4 million. This balance is comprised of $84.4 million of spare parts, $46.2 million of stored gas and oil and $19.8 million of work-in-process. The inventory balance at December 31, 2004, was $171.6 million. This balance is comprised of $109.9 million of spare parts, $52.6 million of stored gas and oil and $9.1 million of work-in-process.

Available-for-Sale Debt Securities — See Note 5 for a discussion of our accounting policy for our available-for-sale debt securities.

Property, Plant and Equipment, Net — See Note 7 for a discussion of our accounting policy for property, plant, and equipment, net.

Asset Retirement Obligation — The Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” on January 1, 2003. As required by SFAS No. 143, we recorded liabilities equal to the present value of expected future asset retirement obligations at January 1, 2003. We identified obligations related to operating gas-fired power plants, geothermal power plants and oil and gas properties. The liabilities are partially offset by increases in net assets recorded as if the provisions of SFAS No. 143 had been in effect at the date the obligation was incurred, which for power plants is generally the start of construction, typically building up during construction until commercial operations for the facility is achieved.

Notes Receivable — Generally, notes receivable are recorded at the face amount, net of allowances. Our notes bear interest at rates that approximate current market interest rates at the time of issuance. Certain of our long-term notes receivable have no stated rate and are recorded by discounting expected future cash flows using then current interest rates at which similar loans would be made to borrowers with similar credit ratings and remaining maturities. We intend to hold our notes receivable to maturity. The amortization of the discount is recognized as interest income, using the effective interest method, over the repayment term of the notes receivable. We review the financial condition of customers prior to granting credit. The allowance represents our best estimate of the amount of probable credit losses in our existing notes receivable. We determine the allowance based on a variety of factors, including economic trends and conditions and significant events affecting the note issuer, the length of time principal and interest payments are past due and historical write-off experience. Also, specific provisions are recorded for individual notes receivable when we become aware of a customer’s inability to meet its financial obligations, such as in the case of bankruptcy filings or deterioration in the customer’s operating results or financial position. We review the adequacy of our notes receivable allowance quarterly. Generally, individual past due amounts are reviewed for collectibility. Interest income is reserved when amounts are more than 90 days past due, or sooner if circumstances indicate recoverability is not reasonably assured. Past due amounts are charged off against the allowance after all means of collection are exhausted and the potential for recovery is considered remote.

Project Development Costs — We capitalize project development costs once it is determined that it is highly probable that such costs will be realized through the ultimate construction of a power plant. These costs include professional services, salaries, permits, capitalized interest, and other costs directly related to the development of a new project. Upon commencement of construction, these costs are transferred to construction in progress, a component of property, plant and equipment. Upon the start-up of plant operations, these construction costs are reclassified as buildings, machinery and equipment, also a component of property, plant and equipment, and are depreciated as a component of the total cost of the plant over its estimated useful life. Capitalized project costs are charged to expense if we determine that the project is no longer probable or to the extent it is impaired. Outside services and other third party costs are capitalized for acquisition projects. See Note 6 for a discussion of impaired projects at December 31, 2005.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Investments — See Note 10 for a discussion of our accounting policies for investments.

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

The table below represents the components of our consolidated restricted cash as of December 31, 2005 and 2004 (in thousands):


		2005						2004

		Current		Non-Current		Total		Current		Non-Current		Total

Debt service		$	152,512	$	118,000	$	270,512	$	160,655	$	120,106	$	280,761
Rent reserve			50,020		—		50,020		51,632		—		51,632
Construction/major maintenance			77,448		36,732		114,180		20,252		7,195		27,447
Proceeds from assets sales			—		406,905		406,905		—		—		—
Collateralized letters of credit and other credit support			148,959		9,327		158,286		329,280		9,140		338,420
Other			28,571		42,476		71,047		31,485		21,427		52,912

	Total	$	457,510	$	613,440	$	1,070,950	$	593,304	$	157,868	$	751,172

As part of a prior business acquisition, which included certain facilities subject to a pre-existing operating lease, we acquired certain restricted cash balances comprised of a portfolio of debt securities. This portfolio is classified as held-to-maturity because we have the intent and ability to hold the securities to maturity. The securities are held in escrow accounts to support operating activities of the leased facilities and consist of a $17.0 million debt security maturing in 2015 and a $7.4 million debt security maturing in 2023. This portfolio is stated at amortized cost, adjusted for amortization of premiums and accretion discounts to maturity.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Of our restricted cash at December 31, 2005 and 2004, $303.9 million and $276.0 million, respectively, relates to the assets of the following entities, each an entity with its existence separate from us and our other subsidiaries (in millions).


	2005		2004

PCF	$	178.1	$	175.6
Gilroy Energy Center, LLC		57.0		53.5
Riverside Energy Center, LLC		29.5		7.1
Rocky Mountain Energy Center, LLC		25.7		18.1
Calpine Northbrook Energy Marketing, LLC		7.3		6.0
Calpine King City Cogen, LLC		4.8		6.7
Calpine Fox LLC		1.0		—
PCF III		0.5		1.5
Calpine Energy Management, L.P.		—		6.9
Creed Energy Center, LLC		—		0.3
Goose Haven Energy Center, LLC		—		0.3

	$	303.9	$	276.0

Deferred Financing Costs — The deferred financing costs related to our First Priority Notes and project financings are amortized over the life of the related debt, ranging from 4 to 20 years, using the effective interest rate method. Costs incurred in connection with obtaining other financing are deferred and amortized over the life of the related debt. However, when timing of debt transactions involve contemporaneous exchanges of cash between us and the same creditor(s) in connection with the issuance of a new debt obligation and satisfaction of an existing debt obligation, deferred financing costs are accounted for in accordance with EITF Issue No. 96-19, “Debtor’s Accounting for a Modification or Exchange of Debt Instruments.” Depending on whether the transaction qualifies as an extinguishment or modification, EITF Issue No. 96-19 requires us to either write off the original deferred financing costs and capitalize the new issuance costs or continue to amortize the original deferred financing costs and immediately expense the new issuance costs. Following our bankruptcy filing on December 20, 2005, we expensed to reorganization items $135.1 million of unamortized deferred financing costs associated with debt subject to compromise. See Note 2 under section “Accounting for Reorganization” for more information regarding the application of SOP 90-7.

Goodwill and Other Intangible Assets — Goodwill is recorded when the purchase price of an acquisition exceeds the estimated fair value of the net identified tangible and intangible assets acquired. We perform an impairment review, at least annually, for our reporting unit with assigned goodwill using a fair value approach, whenever events or changes in circumstances indicate that the goodwill asset may not be fully recoverable. Reporting units may be operating segments, or one level below an operating segment, referred to as a component. Under the fair value approach, whenever the carrying value of the reporting unit, including the goodwill asset, exceeds the fair value of the reporting unit (generally based on the reporting unit’s future estimated discounted cash flows), then the goodwill asset may be impaired and the Company is required to compare the implied fair value of the reporting units goodwill with the carrying amount of the reporting unit’s goodwill. If the carrying amount of the reporting unit’s goodwill is greater than the implied fair value of the reporting unit’s goodwill an impairment loss must be recognized for the excess. In determining the carrying value of the reporting unit, our consolidated assets, including all recorded goodwill, must be allocated to each identified reporting unit. This allocation requires judgment as certain corporate assets are not dedicated to specific reporting units.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Acquisition-related intangibles reflected in the balance sheet line item “Other intangible assets” include patents, power purchase agreements, fuel supply and fuel management agreements and geothermal lease rights. Patents are amortized on a straight-line basis over the life of the patent. Power purchase agreements and fuel agreements are amortized as the commodity is delivered in accordance with the underlying contract. Geothermal lease rights are generally amortized on a straight line basis over the life of the project. The amortization periods for our other intangible assets range from 5 to 23 years. In the reporting period following the period in which identified intangible assets become fully amortized, the fully amortized balances are removed from the gross asset and accumulated amortization amounts. We periodically perform a review of our other intangible assets whenever events or changes in circumstances indicate that the useful life is shorter than originally estimated or that the carrying amount of assets may not be recoverable. If such events and changes in circumstances have occurred, we assess the recoverability of identified intangible assets by comparing the future estimated undiscounted net cash flows associated with the related other intangible asset over its remaining life against its carrying amount. Impairment, if any, is based on the excess of the carrying amount over the fair value of those assets.

Concentrations of Credit Risk — Financial instruments which potentially subject us to concentrations of credit risk consist primarily of cash, accounts receivable, notes receivable and commodity contracts. Our cash accounts are generally held in FDIC insured banks. Our accounts and notes receivable are concentrated within entities engaged in the energy industry, mainly within the United States. We generally do not require collateral for accounts receivable from end-user customers, but for trading counterparties, we evaluate the net accounts receivable, accounts payable, and fair value of commodity contracts and may require security deposits or letters of credit to be posted if exposure reaches a certain level.

Deferred Revenue — Our deferred revenue consists primarily of deferred gains related to certain sale/leaseback transactions as well as deferred revenue for long-term power supply contracts including contracts accounted for as operating leases.

Trust Preferred Securities — Prior to the adoption of FIN 46, as originally issued, for special purpose VIEs on October 1, 2003, our HIGH TIDES I, II, and III were accounted for as a minority interest in the balance sheet and reflected as “Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts.” The distributions were reflected in the Consolidated Statements of Operations as “distributions on trust preferred securities” through September 30, 2003. Financing costs related to these issuances are netted with the principal amounts and were accreted as minority interest expense over the securities’ 30-year maturity using the straight-line method, which approximated the effective interest rate method. Upon the adoption of FIN 46, we deconsolidated the Calpine Capital Trusts. Consequently, the HIGH TIDES were replaced on our Consolidated Balance Sheet with the convertible debentures that had been issued by us to the Calpine Capital Trusts. Due to the relationship with the Calpine Capital Trusts, we considered each of them to be a related party. The interest payments on the convertible debentures were reflected in the Consolidated Statements of Operations as “interest expense.” In 2004 and 2005, we repaid all the convertible debentures payable to the Calpine Capital Trusts, each of which then used the proceeds to redeem all of its outstanding HIGH TIDES. See Note 16 for further information.

Preferred Interests — As outlined in SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity,” we classify preferred interests that embody obligations to transfer cash to the preferred interest holder as debt. These instruments require us to make priority distributions of available cash, as defined in each preferred interest agreement, representing a return of the preferred interest holder’s investment over a fixed period of time and at a specified rate of return in priority to certain other distributions to equity holders. The return on investment is recorded as interest expense under the interest method over the term of the priority period. See Note 17 for a further discussion of our accounting policies for preferred interests.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Revenue Recognition — We are primarily an electric generation company with consolidated revenues being earned from operating a portfolio of mostly wholly owned plants. Income from unconsolidated investments is also earned from plants in which our ownership interest is 50% or less or we are not the “Primary Beneficiary” under FIN 46-R, and which are accounted for under the equity method or cost method. In conjunction with our electric generation business, we also produce, as a by-product, thermal energy for sale to customers, principally steam hosts at our cogeneration sites. In addition, prior to the sale of our remaining oil and gas assets in July 2005 (see Note 12 for further information), we acquired and produced natural gas for our own consumption and sold oil produced to third parties.

Where applicable, revenues are recognized under EITF Issue No. 91-06, “Revenue Recognition of Long Term Power Sales Contracts,” ratably over the terms of the related contracts. To protect and enhance the profit potential of our electric generation plants, we, through our subsidiary, CES, enter into electric and gas hedging, balancing, and optimization transactions, subject to market conditions, and CES has also, from time to time, entered into contracts considered energy trading contracts under EITF Issue No. 02- 03, “Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management.” CES executes these transactions primarily through the use of physical forward commodity purchases and sales and financial commodity swaps and options. With respect to its physical forward contracts, CES generally acts as a principal, takes title to the commodities, and assumes the risks and rewards of ownership. Therefore, when CES does not hold these contracts for trading purposes and, in accordance with SAB No. 104, and EITF Issue No. 99-19, we record settlement of the majority of CES’s non-trading physical forward contracts on a gross basis.

We, through our wholly owned subsidiary, PSM, design and manufacture certain spare parts for gas turbines. In the past, we have also generated revenue by occasionally loaning funds to power projects, and have provided O&M services to third parties and to certain unconsolidated power projects. We also sold engineering and construction services to third parties for power projects. Further details of our revenue recognition policy for each type of revenue transaction are provided below:


	*Accounting for Commodity Contracts*

Commodity contracts are evaluated to determine whether the contract is (1) accounted for as a lease, (2) accounted for as a derivative or (3) accounted for as an executory contract and additionally whether the financial statement presentation is gross or net.

Leases — Commodity contracts are evaluated for lease accounting in accordance with SFAS No. 13, “Accounting for Leases,” and EITF Issue No. 01-08, “Determining Whether an Arrangement Contains a Lease.” EITF Issue No. 01-08 clarifies the requirements of identifying whether an arrangement should be accounted for as a lease at its inception. The guidance in the consensus is designed to broaden the scope of arrangements, such as PPAs, accounted for as leases. EITF Issue No. 01-08 requires both parties to an arrangement to determine whether a service contract or similar arrangement is, or includes, a lease within the scope of SFAS No. 13, “Accounting for Leases.” The consensus is being applied prospectively to arrangements agreed to, modified, or acquired in business combinations on or after July 1, 2003. Prior to adopting EITF Issue No. 01-08, we had accounted for certain contractual arrangements as leases under existing industry practices, and the adoption of EITF Issue No. 01-08 did not materially change our accounting for leases. Under the guidance of SFAS No. 13, “Accounting for Leases,” operating leases with minimum lease rentals which vary over time must be levelized over the term of the contract. We currently levelize these contract revenues on a straight-line basis. See Note 31 for additional information on our operating leases. For income statement presentation purposes, income from PPAs accounted for as leases is classified within E&S revenue in our Consolidated Statements of Operations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Accounting for derivatives at fair value requires us to make estimates about future prices during periods for which price quotes are not available from sources external to us. As a result, we are required to rely on internally developed price estimates when external price quotes are unavailable. We derive our future price estimates, during periods where external price quotes are unavailable, based on an extrapolation of prices from periods where external price quotes are available. We perform this extrapolation using liquid and observable market prices and extending those prices to an internally generated long-term price forecast based on a generalized equilibrium model.

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

With respect to cash flow hedges, if the forecasted transaction is no longer probable of occurring, the associated gain or loss recorded in OCI is recognized currently. In the case of fair value hedges, if the underlying asset, liability or firm commitment being hedged is disposed of or otherwise terminated, the gain or loss associated with the underlying hedged item is recognized currently. If the hedging instrument is terminated prior to the occurrence of the hedged forecasted transaction for cash flow hedges, or prior to the settlement of the hedged asset, liability or firm commitment for fair value hedges, the gain or loss associated with the hedge instrument remains deferred.

Where our derivative instruments were subject to the special transition adjustment for the estimated future economic benefits of certain contracts upon adoption of DIG Issue No. C20, “Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature,” we will amortize the corresponding asset recorded upon adoption of DIG Issue No. C20 through a charge to earnings in future periods. Accordingly on October 1, 2003, the date we adopted DIG Issue No. C20, we recorded other current assets and other assets of approximately $33.5 million and $259.9 million, respectively, and a gain from the cumulative effect of a change in accounting principle of approximately $181.9 million, net of $111.5 million of tax. For all periods subsequent to October 1, 2003, we have accounted for the contracts as normal purchases and sales under the provisions of DIG Issue No. C20.

Mark-to-Market, net activity includes realized settlements of and unrealized mark-to-market gains and losses on both power and gas derivative instruments not designated as cash flow hedges, including those held for trading purposes. Gains and losses due to ineffectiveness on hedging instruments are also included in unrealized mark-to-market gains and losses. Trading activity is presented net in accordance with EITF Issue No. 02-03.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Executory Contracts — Where commodity contracts do not qualify as leases or derivatives, the contracts are classified as executory contracts. These contracts apply traditional accrual accounting unless the revenue must be levelized per EITF Issue No. 91-06. We currently account for one commodity contract under EITF Issue No. 91-06, under which the revenues are levelized over the term of the agreement.

Financial Statement Presentation — Where our derivative instruments are subject to a netting agreement and the criteria of FIN 39 “Offsetting of Amounts Related to Certain Contracts (An Interpretation of APB Opinion No. 10 and SFAS No. 105)” are met, we present our derivative assets and liabilities on a net basis in our balance sheet. We have chosen this method of presentation because it is consistent with the way related mark-to-market gains and losses on derivatives are recorded in our Consolidated Statements of Operations and within OCI.

Presentation of revenue under EITF Issue No. 03-11 “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to SFAS No. 133 and Not ‘Held for Trading Purposes’ As Defined in 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’ ” — We account for certain of our power sales and purchases on a net basis under EITF Issue No. 03-11, which we adopted on a prospective basis on October 1, 2003. Transactions with either of the following characteristics are presented net in our consolidated financial statements: (1) transactions executed in a back-to-back buy and sale pair, primarily because of market protocols; and (2) physical power purchase and sale transactions where our power schedulers net the physical flow of the power purchase against the physical flow of the power sale (or “book out” the physical power flows) as a matter of scheduling convenience to eliminate the need to schedule actual power delivery. These book out transactions may occur with the same counterparty or between different counterparties where we have equal but offsetting physical purchase and delivery commitments. In accordance with EITF Issue No. 03-11, we netted the following amounts (in thousands):


	Year Ended December 31,

	2005		2004		2003

Sales of purchased power for hedging and optimization	$	1,129,773	$	1,676,003	$	256,573

Purchased power expense for hedging and optimization	$	1,129,773	$	1,676,003	$	256,573

Electricity and Steam Revenue — This is composed of fixed capacity payments, which are not related to production, and variable energy payments, which are related to production. Capacity revenues include, besides traditional capacity payments, other revenues such as RMR and Ancillary Service revenues. Our thermal and other revenue consists of host steam sales and other thermal revenue.

Transmission Sales Revenue — From time-to-time, we sell excess transmission capacity. The cost of transmission capacity is recorded within cost of revenue as transmission purchase expense.

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

Plant Operating Expense — This primarily includes employee expenses, repairs and maintenance, insurance, and property taxes.

Purchased Power and Purchased Gas Expense — The cost of power purchased from third parties for hedging, balancing and optimization activities is recorded as purchased power expense. We record the cost of gas purchased from third parties for the purposes of consumption in our power plants as fuel expense, while gas purchased from third parties for hedging, balancing and optimization activities is recorded as purchased gas expense for hedging and optimization. Certain hedging, balancing and optimization activity is presented

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net in accordance with EITF Issue No. 03-11. See discussion above under “Financial Statement Presentation.”

Research and Development Expense — We engage in research and development activities through PSM. Research and development activities related to the design and manufacturing of high performance combustion system and turbine blade parts are accounted for in accordance with SFAS No. 2, “Accounting for Research and Development Costs.” Our research and development expense includes costs incurred for conceptual formulation and design of new vanes, blades, combustors and other replacement parts for the industrial gas turbine industry.

Provision (Benefit) for Income Taxes — SFAS No. 109 requires all available evidence, both positive and negative, to be considered 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. We considered all possible sources of taxable income that may be available under the tax law to realize a tax benefit for deductible temporary differences and loss carryforwards including future reversals of existing taxable temporary differences.

The valuation allowance was based on the historical earnings patterns within individual tax jurisdictions that make it uncertain that we will have sufficient income in the appropriate jurisdictions to realize the full value of the assets.

For the year ended December 31, 2005, we determined it is more likely than not a portion of our deferred tax assets will not be realized as the planned sale of certain appreciated assets to generate taxable income is no longer feasible due to our bankruptcy filings imposing restrictions on our entering into such transactions and executing other tax planning strategies. Given our current financial condition, management determined it was appropriate to record a valuation allowance on all deferred tax assets to the extent not offset by taxable income generated by reversing taxable temporary differences of the appropriate character within the carryback or carryforward periods. We will continue to evaluate the realizability of the deferred tax assets on a quarterly basis.

Our effective income tax rates for continuing operations were 7.0%, 35.9% and 66.6% in fiscal 2005, 2004 and 2003, respectively. The effective tax rate in all periods is the result of profits (losses) that we and our subsidiaries earned in various tax jurisdictions, both foreign and domestic, that apply a broad range of income tax rates. The provision for income taxes differs from the tax computed at the federal statutory income tax rate due primarily to state taxes, tax credits, other permanent differences and earnings considered as permanently reinvested in foreign operations. Future effective tax rates could be adversely affected if earnings are lower than anticipated in countries where we have lower statutory rates, if unfavorable changes in tax laws and regulations occur, or if we experience future adverse determinations by taxing authorities after any related litigation. Our foreign taxes at rates other than statutory include the benefit of cross border financings as well as withholding taxes and foreign valuation allowance.

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We account for income tax contingencies in accordance with both SFAS No. 109, “Accounting for Income Taxes” and SFAS No. 5 “Accounting for Contingencies.” The calculation of tax liabilities involves significant judgment in estimating the impact of uncertainties in the application of complex tax laws. Resolution of these uncertainties in a manner inconsistent with our expectations could have a material impact on our results of operations. We are currently under IRS examination for fiscal year 1999 through 2002. We believe we have made adequate tax payments and/or accrued adequate amounts such that the outcome of audits will have no material adverse effect on our financial statements.”

Comprehensive Income (Loss) — Comprehensive income is the total of net income and all other non-owner changes in equity. Comprehensive income includes our net income, unrealized gains and losses from derivative instruments that qualify as cash flow hedges, unrealized gains and losses from available-for-sale securities which are marked to market, our share of our equity method investee’s OCI, and the effects of foreign currency translation adjustments. We report AOCI in our Consolidated Balance Sheets.

Insurance Program — CPN Insurance Corporation, a wholly owned captive insurance subsidiary, charges us premium rates to insure casualty lines (worker’s compensation, automobile liability, and general liability) as well as all risk property insurance including business interruption. Accruals for casualty claims under the captive insurance program are recorded on a monthly basis, and are based upon the estimate of the total cost of the claims incurred during the policy period. Accruals for claims under the captive insurance program pertaining to property, including business interruption claims, are recorded on a claims-incurred basis. In consolidation, claims are accrued on a gross basis before deductibles. The captive provides insurance coverage with limits up to $25 million per occurrence for property claims, including business interruption, and up to $500,000 per occurrence for casualty claims. Intercompany transactions between the captive insurance program and Calpine affiliates are eliminated in consolidation.

Stock-Based Compensation — On January 1, 2003, we prospectively adopted the fair value method of accounting for stock-based employee compensation pursuant to SFAS No. 123 as amended by SFAS No. 148. SFAS No. 148 amended SFAS No. 123 to provide alternative methods of transition for companies that voluntarily change their accounting for stock-based compensation from the less preferred intrinsic value based method to the more preferred fair value based method. Prior to its amendment, SFAS No. 123 required that companies enacting a voluntary change in accounting principle from the intrinsic value methodology provided by APB Opinion No. 25 could only do so on a prospective basis; no adoption or transition provisions were established to allow for a restatement of prior period financial statements. SFAS No. 148 provides two additional transition options to report the change in accounting principle — the modified prospective method and the retroactive restatement method. Additionally, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. We elected to adopt the provisions of SFAS No. 123 on a prospective basis; consequently, we are required to provide a pro-forma disclosure of net income and EPS as if SFAS No. 123 accounting had been applied to all prior periods presented within our financial statements. As shown below, the adoption of SFAS No. 123 has had a material impact on our financial statements. The table below also reflects the pro forma impact of stock-based compensation on our net income (loss) and earnings (loss) per share for the years ended December 31, 2005, 2004 and 2003, had we applied the accounting

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provisions of SFAS No. 123 to our financial statements in years prior to adoption of SFAS No. 123 on January 1, 2003 (in thousands, except per share amounts):


			2005			2004			2003

Net income (loss)
	As reported		$	(9,939,208	)	$	(242,461	)	$	282,022
	Pro Forma			(9,940,776	)		(247,316	)		270,418
Earnings (loss) per share data:
	Basic earnings (loss) per share
		As reported	$	(21.44	)	$	(0.56	)	$	0.72
		Pro Forma		(21.44	)		(0.57	)		0.69
	Diluted earnings per share
		As reported	$	(21.44	)	$	(0.56	)	$	0.71
		Pro Forma		(21.44	)		(0.57	)		0.68
Stock-based compensation cost included in net income (loss), as reported			$	16,273		$	12,734		$	9,724
Stock-based compensation cost included in net income (loss), pro forma				17,841			17,589			21,328

The range of fair values of our stock options granted in 2005, 2004 and 2003 were as follows, based on varying historical stock option exercise patterns by different levels of our employees: $1.27 – $2.92 in 2005, $1.83 – $4.45 in 2004 and $1.50 – $4.38 in 2003 on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions: expected dividend yields of 0%, expected volatility of 58% – 92% for 2005, 69% – 98% for 2004 and 70% – 113% for 2003, risk-free interest rates of 3.39% – 4.45% for 2005, 2.35% – 4.54% for 2004 and 1.39% – 4.04% for 2003, and expected option terms of 1.1 – 7.3 years for 2005, 3 – 9.5 years for 2004 and 1.5 – 9.5 years for 2003.

In December 2004, FASB issued SFAS No. 123 (revised 2004), “Share Based Payments.” This statement, referred to as SFAS No. 123-R, revises SFAS No. 123 and supersedes APB Opinion No. 25 and its related implementation guidance. See “— New Accounting Pronouncements — SFAS No. 123-R” below for further information.

Operational Data — Operational data (including, but not limited to, MW, MWh, MMBtu, MMcfe, and Bcfe) throughout this Form 10-K is unaudited.


	*New Accounting Pronouncements*


	SFAS No. 123-R and Related FSPs

In December 2004, FASB issued SFAS No. 123-R, which revises SFAS No. 123, and supersedes APB Opinion No. 25 and its related implementation guidance. This statement requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (with limited exceptions), which must be recognized over the requisite service period (usually the vesting period) during which an employee is required to provide service in exchange for the award. The statement applies to all share-based payment transactions in which an entity acquires goods or services by issuing (or offering to issue) its shares, share options, or other equity instruments or by incurring liabilities to an employee or other supplier (a) in amounts based, at least in part, on the price of the entity’s shares or other equity instruments or (b) that require or may require settlement by issuing the entity’s equity shares or other equity instruments.

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The new guidance requires the accounting for any excess tax benefits to be consistent with the existing guidance under SFAS No. 123, which provides a two-transaction model summarized as follows:


	•	If settlement of an award creates a tax deduction that exceeds compensation cost, the additional tax benefit would be recorded as a contribution to paid-in-capital.

	•	If the compensation cost exceeds the actual tax deduction, the write-off of the unrealized excess tax benefits would first reduce any available paid-in capital arising from prior excess tax benefits, and any remaining amount would be charged against the tax provision in the income statement.

The new guidance also amends SFAS No. 95, “Statement of Cash Flows,” to require that excess tax benefits be reported as a financing cash inflow rather than as an operating cash inflow. However, the statement does not change the accounting guidance for share-based payment transactions with parties other than employees provided in SFAS No. 123 as originally issued and EITF Issue No. 96-18, “Accounting for Equity Instruments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling, Goods or Services.” Further, SFAS 123-R does not address the accounting for employee share ownership plans, which are subject to AICPA Statement of Position 93-6, “Employers’ Accounting for Employee Stock Ownership Plans.”

The statement applies to all awards granted, modified, repurchased, or cancelled after January 1, 2006, and to the unvested portion of all awards granted prior to that date. Public entities that used the fair-value-based method for either recognition or disclosure under SFAS No. 123 may adopt SFAS 123-R using a modified version of prospective application pursuant to which compensation cost for the portion of awards for which the employee’s requisite service has not been rendered, which awards are outstanding as of January 1, 2006, must be recognized as the requisite service is rendered on or after that date. The compensation cost for that portion of those awards shall be based on the original grant-date fair value of those awards as calculated for recognition under SFAS No. 123. The compensation cost for those earlier awards shall be attributed to periods beginning on or after January 1, 2006 using the attribution method that was used under SFAS No. 123. Furthermore, the method of recognizing forfeitures must now be based on an estimated forfeiture rate and can no longer be based on forfeitures as they occur.

Adoption of SFAS No. 123-R is not expected to materially impact our consolidated results of operations, cash flows or financial position, due to our prior adoption of SFAS No. 123 as amended by SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure” on January 1, 2003. SFAS No. 148 allowed companies to adopt the fair-value-based method for recognition of compensation expense under SFAS No. 123 using prospective application. Under that transition method, compensation expense was recognized in our Consolidated Statement of Operations only for stock-based compensation granted after the adoption date of January 1, 2003. Furthermore, as we have chosen the multiple option approach in recognizing compensation expense associated with the fair value of each option granted, nearly 94% of the total fair value of the stock option is recognized by the end of the third year of the vesting period, and therefore remaining compensation expense associated with options granted before January 1, 2003, is expected to be immaterial.


	SFAS No. 128-R

FASB is expected to revise SFAS No. 128, “Earnings Per Share” to make it consistent with International Accounting Standard No. 33, “Earnings Per Share,” so that EPS computations will be comparable on a global basis. This proposed exposure draft, as currently written, would be effective for interim and annual periods ending after June 15, 2006 and will require restatement of prior periods diluted EPS, except that retrospective application would be prohibited for contracts that were either settled in cash prior to adoption or modified prior to adoption to require cash settlement. The proposed changes will affect the application of the treasury

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stock method and contingently issuable (based on conditions other than market price) share guidance for computing year-to-date diluted EPS. In addition to modifying the year-to-date calculation mechanics, the proposed revision to SFAS No. 128 would eliminate a company’s ability to overcome the presumption of share settlement for those instruments or contracts that can be settled, at the issuer or holder’s option, in cash or shares. Under the revised guidance, FASB has indicated that any possibility of share settlement other than in an event of bankruptcy will require a presumption of share settlement when calculating diluted EPS. The Company’s 2023 Convertible Notes and 2014 Convertible Notes contain provisions that would require share settlement in the event of conversion under certain events of default, including but not limited to a bankruptcy-related event of default. Additionally, the 2023 Convertible Notes include a provision allowing the Company to meet a put with either cash or shares of stock. The Company’s 2015 Convertible Notes allow for share settlement of the principal only in the case of certain bankruptcy-related events of default. Therefore, a presumption of share settlement is required for the 2014 Convertible Notes and the 2023 Convertible Notes, but is not required for the 2015 Convertible Notes. Depending on the degree to which the respective series of Convertible Notes are ultimately compromised as a result of the Company’s bankruptcy filing, the revised guidance could result in a significant increase in the potential dilution to the Company’s EPS, particularly when the price of the Company’s common stock is low, since SFAS No. 128-R requires that the more dilutive of calculations be used considering both:


	•	normal conversion assuming a combination of cash and variable number of shares; and

	•	conversion during events of default other than bankruptcy assuming 100% shares at the fixed conversion rate, or, in the case of 2023 Convertible Notes, meeting a put entirely with shares of stock.


	SFAS No. 151

In November 2004, FASB issued SFAS No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4.” This statement amends the guidance in ARB No. 43, Chapter 4, “Inventory Pricing,” to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Paragraph 5 of ARB 43, Chapter 4, previously stated that “... under some circumstances, items such as idle facility expense, excessive spoilage, double freight, and rehandling costs may be so abnormal as to require treatment as current period charges. . . .” SFAS No. 151 requires those items to be recognized as a current-period charge regardless of whether they meet the criterion of “so abnormal.” In addition, SFAS No. 151 requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. The provisions of SFAS No. 151 are applicable to inventory costs incurred during fiscal years beginning after June 15, 2005. Adoption of this statement is not expected to materially impact our consolidated results of operations, cash flows or financial position.


	SFAS No. 153

In December 2004, FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets.” This statement eliminates the exception in APB Opinion No. 29, “Accounting for Nonmonetary Transactions” for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. It requires exchanges of productive assets to be accounted for at fair value, rather than at carryover basis, unless (1) neither the asset received nor the asset surrendered has a fair value that is determinable within reasonable limits or (2) the transaction lacks commercial substance (as defined). A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange.

SFAS No. 153 will not apply to the transfers of interests in assets in exchange for an interest in a joint venture and amends SFAS No. 66, “Accounting for Sales of Real Estate” to clarify that exchanges of real estate for real estate should be accounted for under APB Opinion No. 29. It also amends SFAS No. 140, to

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remove the existing scope exception relating to exchanges of equity method investments for similar productive assets to clarify that such exchanges are within the scope of SFAS No. 140 and not APB Opinion No. 29. SFAS No. 153 is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. Adoption of this statement did not materially impact our consolidated results of operations, cash flows or financial position.


	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. APB Opinion No. 20 previously required that most voluntary changes in accounting principle be recognized by including in net income for the period of the change the cumulative effect of changing to the new accounting principle. SFAS No. 154 requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. When it is impracticable to determine the cumulative effect of applying a change in accounting principle to all prior periods, SFAS No. 154 requires that the new accounting principle be applied as if it were adopted prospectively from the earliest date practicable.

SFAS No. 154 also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate effected by a change in accounting principle. SFAS No. 154 is effective for fiscal years beginning after December 15, 2005. Adoption of this statement is not expected to materially impact our consolidated results of operations, cash flows or financial position.


	EITF Issue No. 03-13

At the November 2004 EITF meeting, final consensus was reached on EITF Issue No. 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations.” EITF Issue No. 03-13 is effective prospectively for disposal transactions entered into after January 1, 2005, and provides a model to assist in evaluating (a) which cash flows should be considered in the determination of whether cash flows of the disposal component have been or will be eliminated from the ongoing operations of the entity and (b) the types of continuing involvement that constitute significant continuing involvement in the operations of the disposal component. We have applied the model outlined in EITF Issue No. 03-13 in our evaluation of the September 2004 sale of the Canadian and U.S. Rocky Mountain oil and gas assets, the July 2005 sales of the remaining oil and gas assets and the Saltend facility, the sale of the Morris facility in August 2005 and the sale of the Ontelaunee facility in October 2005 in determining whether or not the cash flows related to these components have been or will be permanently eliminated from our ongoing operations.


	EITF Issue No. 04-13

At the September 15, 2005, EITF meeting, consensus was reached on EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” EITF Issue No. 04-13 provides accounting guidance for entities that may sell inventory to another entity in the same line of business from which it also purchases inventory. The scope of EITF Issue No. 04-13 excludes inventory purchase and sales arrangements that (a) are accounted for as derivatives under SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” or (b) involve exchanges of software or exchanges of real estate.

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The guidance requires inventory transactions with the same counterparty to be recorded at either fair value or carrying value and if multiple sale and purchase transactions have occurred, possibly recording as a single transaction. Determining whether transactions are recognized at fair value or carrying value is based upon the type of inventories being exchanged. Determining whether two or more inventory purchase and sale transactions are recorded as a single transaction is based upon whether the transactions were entered into in “contemplation of one another.”

EITF Issue No. 04-13 should be applied to new arrangements entered into, and modifications or renewals of existing arrangements, beginning in the first interim or annual reporting period beginning after March 15, 2006. The carrying amount of the inventory that was acquired under these types of arrangements prior to the initial application of EITF Issue No. 04-13 and that still remains in an entity’s statement of financial position at the date of initial application of EITF Issue No. 04-13 is unchanged. Early application is permitted in periods for which financial statements have not been issued. We elected to early adopt in the first quarter of 2005 and this adoption had no impact our consolidated results of operations, cash flows or financial position.


	FIN 47

In April 2005 FASB issued FIN 47 to clarify the meaning of the term “conditional asset retirement obligation,” which refers to legal obligations that companies must perform in order to retirement long-lived assets for which the timing and/or method of settlement are conditional upon future events that may or may not be within the control of the entity. FIN 47 also clarifies that the obligation to perform the asset retirement is unconditional, despite the uncertainty that exists in regard to the timing and method of settlement, and requires the uncertainty about the timing and method of settlement for a conditional ARO to be considered in estimating the ARO when sufficient information exists. FIN 47 provides further guidance as to when sufficient information exists to reasonably estimate the fair value of an ARO. The Interpretation is effective for fiscal years ending after December 15, 2005 (December 31, 2005 for us) with early adoption allowed. Implementation of this new guidance did not materially impact our consolidated results of operations, cash flows or financial position.


	SFAS No. 155

In February 2006 FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments — an amendment of FASB Statements No. 133 and 140,” to resolve issues addressed in DIG Issue No. D1, “Application of Statement 133 to Beneficial Interests in Securitized Financial Assets.” SFAS No. 155 permits fair value remeasurement for hybrid financial instruments containing embedded derivatives, clarifies that certain types of financial instruments are not subject to the requirements of SFAS No. 133, requires an evaluation of interests in securitized financial assets to determine whether an embedded derivative requires bifurcation, clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives and amends SFAS No. 140 to eliminate the prohibition on a qualifying special-purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative financial instrument. SFAS No. 155 is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. We do not expect the adoption of this statement to have a material impact on our results of operations, cash flows or financial position.


	SFAS No. 156

In March 2006 FASB issued FASB Statement No. 156, “Accounting for Servicing of Financial Assets — An Amendment of FASB Statement No. 140.” The new statement addresses the recognition and measurement of separately recognized servicing assets and liabilities and provides an approach to simplify

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efforts to obtain hedge-like (offset) accounting. The statement also (i) clarifies when an obligation to service financial assets should be separately recognized as a servicing asset or a servicing liability, (ii) requires that a separately recognized servicing asset or servicing liability be initially measured at fair value, if practicable, (iii) permits an entity with a separately recognized servicing asset or servicing liability to choose either the amortization or fair value method for subsequent measurement and (iv) permits a servicer that uses derivative financial instruments to offset risks on servicing to report both the derivative financial instrument and related servicing asset or liability by using a consistent measurement attribute, or fair value. SFAS is effective for all separately recognized servicing assets and liabilities acquired or issued after the beginning of an entity’s fiscal year that begins after September 15, 2006, with early adoption permitted. We do not expect the adoption of this statement to have a material impact on our results of operations, cash flows or financial position.


3.	Bankruptcy Proceedings

On December 20, 2005 and December 21, 2005, Calpine and 254 of its wholly owned subsidiaries in the United States filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court and, in Canada, 12 of its Canadian subsidiaries were granted relief in the Canadian Court under the CCAA, which, like Chapter 11, allows for reorganization under the protection of the court system. On December 27 and 29, 2005, January 8 and 9, 2006, February 3, 2006, and May 2, 2006, 19 additional wholly owned subsidiaries of Calpine commenced Chapter 11 cases in the U.S. Bankruptcy Court. Certain other subsidiaries could file in the U.S. or Canada in the future. We refer to the filers collectively as the “Calpine Debtors.” The Chapter 11 cases of the U.S. Debtors are being jointly administered for procedural purposes only by the U.S. Bankruptcy Court under the case captioned In re Calpine Corporation et al., Case No. 05-60200 (BRL).

The Calpine Debtors are continuing to operate their business as debtors-in-possession under the jurisdiction of the Bankruptcy Courts and in accordance with the applicable provisions of the Bankruptcy Code, the Federal Rules of Bankruptcy Procedure, the CCAA and applicable court orders, as well as other applicable laws and rules. In general, as debtors-in-possession, each of the Calpine Debtors is authorized to continue to operate as an ongoing business, but may not engage in transactions outside the ordinary course of business without the prior approval of the applicable Bankruptcy Court.

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With respect to the U.S. bankruptcy cases, the Office of the United States Trustee has appointed a committee of unsecured creditors for Calpine Corporation, and there has also been formed an ad hoc committee of second lien creditors. The Office of the United States Trustee has also appointed a committee of equity security holders of Calpine Corporation.

The Canadian Debtors obtained an Initial Order from the Canadian Court granting those entities protection under the CCAA. Pursuant to the Initial Order, the Canadian Debtors are authorized to continue operations. In accordance with procedures under the CCAA, a court monitor was appointed by the Canadian Court to assess the Canadian Debtors and report its findings to the Canadian Court. Ernst & Young Inc. was appointed as the monitor and has been reporting to the Canadian Court from time to time on various matters including the Canadian Debtors’ cash flow, asset transfers and other developments in the Canadian cases.

On December 20, 2005, the U.S. Debtors entered into the $2.0 billion DIP Facility. On December 21, 2005, the U.S. Bankruptcy Court granted interim approval of the DIP Facility, but initially limited our access under the DIP Facility to $500 million under the revolving credit facility. On January 26, 2006 the U.S. Bankruptcy Court entered a final order approving the DIP Facility and removing the limitation on our ability to borrow thereunder. The syndication of the DIP Facility was closed on February 23, 2006. Deutsche Bank Securities Inc. and Credit Suisse were co-lead arrangers for the DIP Facility, which will remain in place until the earlier of an effective plan of reorganization or December 20, 2007. In connection with and as a condition to the closing, on February 3, 2006, we acquired ownership of The Geysers, which had previously been leased pursuant to a leveraged lease. We used borrowings under the DIP Facility to pay a portion of the purchase price for The Geysers and to retire certain facility operating lease and related debt obligations. The DIP Facility is secured by first priority liens on all of the unencumbered assets of the U.S. Debtors, including The Geysers, and junior liens on all of their encumbered assets. In addition, the DIP Facility was amended on May 3, 2006, to, among other things, provide us with extensions of time (i) to provide certain financial information to the DIP Facility lenders, including financial statements for the year ended December 31, 2005 (which are included in this Report), and for the quarter ended March 31, 2006 and (ii) to cause GPC to file for protection under Chapter 11 of the Bankruptcy Code. See Note 22 of the Notes to Consolidated Financial Statements for further details regarding the DIP Facility.

In addition, the U.S. Bankruptcy Court approved cash collateral and adequate assurance stipulations in connection with the approval of the DIP Facility, which has allowed our business activities to continue to function. We have also sought and obtained U.S. Bankruptcy Court approval through our “first day” and subsequent motions to continue to pay critical vendors, meet our pre-petition and post-petition payroll to obligations, maintain our cash management systems, collateralize certain of our gas supply contracts, enter into and collateralize trading contracts, pay our taxes, continue to provide employee benefits, maintain our insurance programs and implement an employee severance program, which has allowed us to continue to operate the existing business in the ordinary course. In addition, the U.S. Bankruptcy Court has approved certain trading notification and transfer procedures designed to allow us to restrict trading in our common stock (and related securities) which could negatively impact our accrued NOLs and other tax attributes, and granted us extensions of time to file and seek approval of a plan of reorganization and to assume or reject real property leases.

Subject to certain exceptions under the Bankruptcy Code and the CCAA, as applicable, our bankruptcy filings automatically stayed the initiation or continuation of most actions against the Calpine Debtors, including most actions to collect pre-petition indebtedness or to exercise control over the property of the Calpine Debtors’ estates. One exception to this stay is certain types of actions or proceedings by a governmental agency to enforce its police or regulatory powers. As a result of this stay, absent an order of the Bankruptcy Court, creditors are precluded from collecting pre-petition debts, and substantially all pre-petition

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liabilities are subject to compromise under a plan or plans of reorganization to be developed by the Calpine Debtors later in the bankruptcy cases.

The U.S. Bankruptcy Court has established August 1, 2006 as a bar date for filing proofs of claim against the U.S. Debtors’ estates; and the Canadian Court has established June 30, 2006, as a bar date for filing claims against the Canadian Debtors’ estates. We have not fully analyzed the validity and enforceability of any submitted proofs of claim filed against the Calpine Debtors’ estates to date. In addition, because the bar dates have not yet occurred, we expect that additional proofs of claim will be filed. Accordingly, it is not possible at this time to determine the extent of the claims that may be filed, whether or not such claims will be disputed, or whether or not such claims will be subject to discharge in the bankruptcy proceedings. Nor is it possible at this time to determine whether to establish any claims reserves. Once all applicable bar dates are established and all claims against the Calpine Debtors are filed, we will review all claims filed and begin the claims reconciliation process. In connection with the review and reconciliation process, we will also determine the reserves, if any, that may be established in respect of such claims.

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. Generally, the assumption of an executory contract or unexpired lease requires a debtor to cure certain existing defaults under the contract. Rejection of an executory contract or unexpired lease is typically treated as a breach occurring as of the moment immediately preceding the Chapter 11 filing. Subject to certain exceptions, this rejection relieves the debtor from performing its future obligations under the contract but entitles the counterparty to assert a pre-petition general unsecured claim for damages. Parties to executory contracts or unexpired leases rejected by a debtor may file proofs of claim against that debtor’s estate for damages. Due to ongoing evaluation of contracts for assumption or rejection and the uncertain nature of many of the potential claims for damages, we cannot project the magnitude of these potential claims at this time.

We continue to evaluate our executory contracts and real property leases in order to determine which contracts will be assumed, assumed and assigned, or rejected. Once the evaluation is complete with respect to each particular contract or lease, the applicable Calpine Debtors file the appropriate motion with the Bankruptcy Court seeking approval to assume, assume and assign, or reject the contract or lease. Pursuant to applicable orders of the U.S. Bankruptcy Court, if a Calpine Debtor seeks to reject a contract or lease, the contract or lease counterparties then have an opportunity to file objections. The Bankruptcy Court then determines whether to grant or deny such motions and, if an objection has been filed, will conduct a hearing to determine any matters raised by the objection. As of the date of this filing, the Calpine Debtors have identified the following significant contracts and leases to be rejected:


	•	On December 21, 2005, we filed a motion with the U.S. Bankruptcy Court to reject eight PPAs and to enjoin FERC from asserting jurisdiction over the rejections. The U.S. Bankruptcy Court issued a temporary restraining order against FERC and set the matter for a hearing on January 5, 2006. Under most of the PPAs sought to be rejected, we are obligated to sell power at prices that are significantly lower than currently-prevailing market prices. At the time of filing the motion, we forecasted that it would cost us in excess of $1.2 billion if we were required to continue to perform under these PPAs rather than to sell the contracted energy at current market prices. On December 29, 2005, certain counterparties to the various PPAs filed an action in the SDNY Court arguing that the U.S. Bankruptcy Court did not have jurisdiction over the dispute. On January 5, 2006, the SDNY Court entered an order that had the effect of transferring our motion seeking to reject the eight PPAs and our related request for an injunction against FERC to the SDNY Court from the U.S. Bankruptcy Court. Earlier, however, on December 19, 2005, CDWR, a counterparty to one of the eight PPAs, had filed a complaint with FERC seeking to obtain injunctive relief to prevent us from rejecting our PPA with CDWR and contending that FERC had exclusive jurisdiction over the matter. On January 3,

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		2006, FERC determined that it did not have exclusive jurisdiction, and that the matter could be heard by the U.S. Bankruptcy Court. However, despite the FERC ruling, on January 27, 2006, the SDNY Court determined that FERC had jurisdiction over whether the contracts could be rejected. We appealed the SDNY Court’s decision to the United States Court of Appeals for the Second Circuit. The appeal was heard on April 10, 2006 and we have not yet received a decision. We can not determine at this time whether the SDNY Court, the U.S. Bankruptcy Court or FERC will ultimately determine whether we may reject any or all of the eight PPAs, or when such determination will be made. In the meantime, three of the PPAs have been terminated by the applicable counterparties, and we continue to perform under those PPAs that remain in effect.

	•	On February 6, 2006, we filed a notice of rejection of our leasehold interests in the Rumford power plant and the Tiverton power plant with the U.S. Bankruptcy Court, and noticed the surrender of the two plants to their owner-lessor. The owner-lessor has declined to take possession and control of the plants, which are not currently being dispatched but are being maintained in operating condition. The deadline for filing objections to the notice of rejection, which pursuant to a U.S. Bankruptcy Court order regarding expedited lease rejection procedures was originally set for February 16, 2006, was consensually extended to April 14, 2006. Both the indenture trustee related to the leaseholds and the owner-lessor filed objections to the rejection notice on that date. Additionally, the indenture trustee filed a motion to withdraw the reference of the rejection notice to the SDNY Court, arguing that the U.S. Bankruptcy Court does not have jurisdiction over the lease rejection dispute. The ISO New England, Inc. has separately filed a motion to withdraw the reference of the rejection notice to the SDNY Court on similar grounds. A hearing is currently scheduled for May 24, 2006 before the U.S. Bankruptcy Court to determine whether or not to approve the rejection and any other matters raised by the objections. However, such hearing date is subject to change. The Rumford and Tiverton power plants represent a combined 530 MW of installed capacity with the output sold into the New England wholesale market.

	•	In February 2006, we filed notices of rejection with the U.S. Bankruptcy Court relating to our office leases in Portland, Oregon and in Deer Park, Texas. In March 2006, we filed notices of rejection relating to our office leases in Denver and Fort Collins, Colorado and in Tampa, Florida. In April 2006, we filed a notice of rejection relating to our office lease in Atlanta, Georgia. The rejection of each of the foregoing leases has been approved by the U.S. Bankruptcy Court. We anticipate that it is more likely than not that we will file further notices of rejection with respect to additional office leases; in particular, we announced in April 2006 that we intend to close our Dublin, California and Boston, Massachusetts offices.

At this time, it is not possible to accurately predict the effects of the reorganization process on the business of the Calpine Debtors or if and when some or all of the Calpine Debtors may emerge from bankruptcy. The prospects for future results depend on the timely and successful development, confirmation and implementation of a plan or plans of reorganization. There can be no assurance that a successful plan or plans of reorganization will be proposed by the Calpine Debtors, supported by the Calpine Debtors’ creditors or confirmed by the Bankruptcy Courts, 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 bankruptcy 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 Calpine and the other Calpine Debtors will be restructured in a manner that will substantially reduce or eliminate any remaining value of such equity interests or other securities, or that certain creditors may ultimately receive little or no payment with respect to their claims. Whether or not a plan or plans of reorganization are approved, it is possible that the assets of any one or more of the Calpine Debtors may be liquidated.

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As a result of our bankruptcy filings and the other matters described herein, including the uncertainties related to the fact that we have not yet had time to complete and have approved a plan of reorganization, there is substantial doubt about our ability to continue as a going concern. The accompanying consolidated financial statements have been prepared on a going concern basis, which assumes continuity of operations and realization of assets and satisfaction of liabilities in the ordinary course of business, and in accordance with SOP 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code.” The consolidated financial statements do not include any adjustments that might be required should we be unable to continue to operate as a going concern. In accordance with SOP 90-7, all pre-petition liabilities subject to compromise have been segregated in the consolidated balance sheets and classified as LSTC, at the estimated amount of allowable claims. Interest expense related to pre-petition LSTC has been reported only to the extent that it will be paid during the pendency of the bankruptcy cases. Liabilities not subject to compromise are separately classified as current or noncurrent. Expenses, provisions for losses resulting from reorganization and certain other items directly related to our bankruptcy case are reported separately as reorganization expenses due to bankruptcy. Cash used for reorganization items is disclosed in the consolidated statements of cash flows.

Our ability to continue as a going concern, including our ability to meet our ongoing operational obligations, is dependent upon, among other things: (i) our ability to maintain adequate cash on hand; (ii) our ability to generate cash from operations; (iii) the cost, duration and outcome of the restructuring process; (iv) our ability to comply with our DIP Facility agreement and the adequate assurance provisions of the Cash Collateral Order and (v) our ability to achieve profitability following a restructuring. These challenges are in addition to those operational and competitive challenges faced by us in connection with our business. In conjunction with our advisors, we are working to design and implement strategies to ensure that we maintain adequate liquidity and will be able to continue as a going concern. See Bankruptcy Considerations in the Overview section of Management’s Discussion and Analysis for further discussion of management’s plans. However, there can be no assurance as to the success of such efforts.

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4.	Calpine Debtors Condensed Combined Financial Statements

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

Condensed Combined Balance Sheet

As of December 31, 2005


			Debtors

			(In billions)
Assets:
	Current assets		$	5.5
	Restricted cash, net of current portion			.5
	Investments			2.1
	Property, plant and equipment, net			7.7
	Other assets			1.6

		Total assets	$	17.4

Liabilities not subject to compromise:
	Current liabilities		$	4.9
	Long-term debt			.2
Long-term derivative liabilities				.7
Other liabilities				.2
Liabilities subject to compromise				16.7
Minority interest				.3
Stockholders’ equity (deficit)				(5.6	)

		Total liabilities and stockholders’ equity (deficit)	$	17.4

See Note 24 for additional discussion of liabilities subject to compromise.

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Condensed Combined Statements of Operations

For the Year ended December 31, 2005


			Debtors

			(In billions)
Total revenue			$	11.6
Total cost of revenue				14.3
Operating expenses				2.2

	Loss from operations			(4.9	)
Interest expense				1.0
Other (income) expense, net				(.1	)
Reorganization items, net				5.0
Benefit for income taxes				.8

	Income (loss) from continuing operations before discontinued operations			(10.0	)
Income from discontinued operations, net of tax				.1

		Net income (loss)	$	(9.9	)

Condensed Combined Statements of Cash Flows

For the Year Ended December 31, 2005


		U.S.
		Debtors

		(In millions)
Net cash provided by (used in):
	Operating	$	(1,520.3	)
	Investing activities		2,113.1
	Financing activities		(630.7	)
Effect of exchange rate changes on cash and cash equivalents			(.1	)

Net (decrease) increase in cash and cash equivalents			(38.0	)
Cash and cash equivalents, beginning of year			481.9

Cash and cash equivalents, end of year		$	443.9

Cash paid for reorganization items included in operating activities		$	13.8


	*Basis of Presentation*

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


	*Interest Expense*

The Calpine Debtors have discontinued recording interest on unsecured or undersecured liabilities subject to compromise. Contractual interest on liabilities subject to compromise not reflected in the financial

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statements was approximately $17.9 million; representing interest expense from the bankruptcy filing on December 20, 2005 through December 31, 2005.


	*Reorganization Items*

Reorganization items represent the direct and incremental costs of being in bankruptcy, such as professional fees, pre-petition liability claim adjustments and losses related to terminated contracts that are probable and can be estimated. Reorganization items, as shown in the Condensed Combined Statements of Operations above, consist of expense or income incurred or earned as a direct and incremental result of the bankruptcy filings. The table below lists the significant items within this category for the year ended December 31, 2005 (in millions).


		December 31, 2005

Provision for allowable claims		$	3,791.5
Impairment of investment in Canadian subsidiaries			879.1
Write-off of unamortized deferred financing costs and debt discounts			148.1
Loss on terminated contracts, net			139.4
Professional fees			36.4
Other reorganization items			32.0

	Total reorganization items	$	5,026.5

We determined it was necessary to deconsolidate most of our Canadian and other foreign entities due to our loss of control over these entities upon the filing by the Canadian Debtors for protection under the CCAA in Canada. The Canadian Debtor entities are not under the jurisdiction of the U.S. Bankruptcy Court and are separately administered under the CCAA by the Canadian Court. In conjunction with the deconsolidation, we reviewed all intercompany guarantees. We identified guarantees by U.S. parent entities of debt (and accrued interest payable) of approximately $5.1 billion issued by entities in the Canadian debtor chains as constituting probable allowable claims against the U.S. parent entities. Some of the guarantee exposures are redundant, such as the Calpine Corporation guarantee to ULC I security holders and the Calpine Corporation guarantee of QCH’s subscription agreement obligations associated with the hybrid notes structure in support of the ULC I Unsecured Notes. Under the guidance of SOP 90-7 “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code,” we determined the duplicative guarantees were probable of being allowed into the claim pool by the U.S. Bankruptcy Court. We accrued an additional amount of approximately $3.8 billion as reorganization items related to these duplicative guarantees.

As a result of the deconsolidation, we adopted the cost method of accounting for our investment in our Canadian and other foreign entities. Upon adoption of the cost method, we evaluated our investment balances and intercompany notes receivable from these entities for impairment. We determined that our entire investment in these entities had experienced other-than-temporary decline in value and was impaired. We also concluded that all intercompany notes receivable balances from these entities were uncollectible, as the notes were unsecured and protected by the automatic stay under the CCAA. Consequently, we fully impaired these investment and receivable assets at December 31, 2005, resulting in an $879.1 million charge to reorganization items.

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Professional fees relate primarily to expenses incurred to secure the DIP Facility and the fees of attorneys and consultants working directly on the bankruptcy filings and our plan of reorganization.


5.	Available-for-Sale Debt Securities


	*HIGH TIDES*

During 2004, we exchanged 24.3 million shares of Calpine common stock in privately negotiated transactions for approximately $115.0 million par value of HIGH TIDES I and II securities. In connection with the repayment of the trust debentures (see Note 16) these securities were repurchased by the Calpine Capital Trusts, resulting in a realized gain of approximately $6.1 million.

On September 30, 2004, we repurchased, in a privately negotiated transaction, par value $115.0 million HIGH TIDES III securities for $111.6 million, which included $1.0 million for accrued interest. Due to the deconsolidation of the Calpine Capital Trusts upon the adoption of FIN 46 as of December 31, 2003, the terms of the underlying convertible debentures between us and Trust III and the requirements of SFAS 140, the repurchased HIGH TIDES III could not be offset against the convertible debentures. The repurchased HIGH TIDES III were accounted for as available-for-sale securities and recorded in Other Assets at the fair market value of $111.6 million at December 31, 2004.

On July 13, 2005, we repaid the convertible debentures held by Trust III, which used those proceeds to redeem the outstanding HIGH TIDES III. See Note 14 for more information. The redemption price paid per each $50 principal amount of HIGH TIDES III was $50, for a total redemption price of $115.0 million, plus accrued and unpaid distributions to the redemption date in the amount of $0.50. The redemption of the HIGH TIDES III available-for-sale securities previously purchased and held by us resulted in a realized gain of approximately $4.4 million. We have no available-for-sale debt securities recorded in the Consolidated Condensed Balance Sheet at December 31, 2005.

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6.	Impairments

During the fourth quarter of 2005, we concluded that impairment indicators existed at December 31, 2005, and that certain of our assets were impaired. This conclusion resulted from a convergence of multiple facts and circumstances arising during the fourth quarter of 2005, including:


	•	Restrictions on us and our subsidiaries that arise from our December 20, 2005, bankruptcy filings, including the need to obtain support or approvals from the Bankruptcy Courts, creditors’ committees and DIP Facility lenders to execute certain of our key business decisions;

	•	Our current status as a Chapter 11 debtor, current credit constraints and focus on reorganizing and emerging from bankruptcy have made us less likely to commit to expending additional capital in the foreseeable future for certain of our development and construction projects;

	•	Near-term action to sell or abandon operating plants that currently have significant negative cash flow is more likely as part of our reorganization and restructuring process;

	•	Debt covenant restrictions, including under the DIP Facility, and recent court rulings restrict or prevent the use of proceeds from the sale of assets, or use of cash from operations, for development and construction projects;

	•	Among other things, our bankruptcy filings and related credit constraints make it much more difficult to secure long-term PPAs with electrical utilities or other customers that would have made it possible to finance the construction of projects or allow merchant power plants with current negative cash flow (until spot market prices and spark spreads recover) to become profitable. For example, because credit support is required by prospective long-term PPA customers due to our financial condition and bankruptcy filings, it has become increasingly difficult for us to enter into PPAs;

	•	Our access to capital on attractive terms for development projects has been reduced; and

	•	Historically high and very volatile natural gas prices in recent times have made many customers hesitant to commit to long-term base load PPAs for gas-fired electrical generation.

This table presents the major components of the impairment charges recorded for the year ended December 31, 2005 (in thousands):


		Book Value
		before		Impairment			New Cost
Project Description		Impairment		Charge			Basis

Operating plants		$	3,182,392	$	(2,412,586	)	$	769,806

Development and construction projects and assets		$	3,314,418	$	(1,957,498	)	$	1,356,920
Joint venture investments			238,297		(134,469	)		103,828
Notes receivable			38,644		(25,698	)		12,946

	Total non-operating project impairment charges		3,591,359		(2,117,665	)		1,473,694

Total		$	6,773,751	$	(4,530,251	)	$	2,243,500


	*Operating Plants*

The impairment charges, which relate to 16 of our operating plants with a peak capacity of 5,268 MW were generally the result of our determination that the likelihood of sale or abandonment of certain of our plants had increased and totaled approximately $2.4 billion for the year ended December 31, 2005. Expected future cash expenditures total approximately $6.0 million, related primarily to sales costs. For power plants

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that are considered potential sale or abandonment candidates, we probability-weighted the estimated net proceeds from sale or abandonment with the projected pre-interest expense, pre-tax cash flows over the plants’ economically useful lives, assuming no sale or abandonment. Assessing the probability of sale or abandonment versus continuing to own and operate the facility and developing estimates of future cash flows and probability-weighted cash flow scenarios requires significant judgment, and our estimates of future cash flows and probabilities could be considerably different from actual results or outcomes and we may incur future impairment charges related to these and other operating plants.


	*Development and Construction Projects and Assets*

The impairment charges related to development and construction projects and assets (excluding joint venture investments, which are discussed below) totaled approximately $2.0 billion. Expected future cash expenditures total approximately $8 million, related primarily to costs to ready equipment for sale. The impairment charge is the result of our conclusion that the projects are no longer probable of being successfully completed by us and that project costs are no longer expected to be fully recovered by us through future operations.


	*Joint Venture Investments*

In November 2005 we contributed three combustion gas turbine generators and one steam turbine generator with a book value of approximately $154.1 million in exchange for a 50% interest in Greenfield LP. See Note 10 for a description of this transaction and resulting investment. Mitsui contributed monetary assets to the joint venture project for the other 50% equity interest. In accordance with APB No. 29, we recorded the value of our investment at its implied fair value of approximately $40.7 million, based on the value of monetary assets contributed to the joint venture entity by the other 50% equity partner. This transfer resulted in a $93.1 million impairment charge in the quarter ended December 31, 2005.

Subsequent to December 31, 2005, we completed the sale of our 45% interest in the Valladolid project to the two remaining partners. See Note 34 for a description of this sale. The carrying value of our investment was approximately $84.2 million. As part of our year-end close process related to our assessment of the fair value of this equity method investment, we determined that the investment had experienced an other-than-temporary decline in value, based on our probability weighted estimate of future discounted cash flows, giving effect to the likelihood of completing the sale. We concluded that a non-cash impairment charge of approximately $41.3 million was required for the year ended December 31, 2005. Future cash expenditures necessary to exit this investment are not expected to be significant. See Note 10 for a description of this investment.

The table below summarizes the impairment charges related to our joint venture investment projects during the year-ended December 31, 2005 (in thousands):


		Carrying Value					Carrying Value
		before					after
Project Description		Impairment		Impairments			Impairment

Greenfield LP(1)		$	154,060	$	(93,132	)	$	60,928
Valladolid			84,237		(41,337	)		42,900

	Total joint venture investments	$	238,297	$	(134,469	)	$	103,828


(1)	At December 31, 2005, our investment in Greenfield LP was approximately $40.7 million, representing the fair value of the turbines of approximately $60.9 million less a receivable from the joint venture of

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	approximately $20.2 million which we treated as a return of capital. See Note 10 for a discussion of this investment.


	*Notes receivable impairments*

In accordance with SFAS No. 114, “Accounting by Creditors for Impairment of a Loan,” we recorded a bad debt allowance of approximately $25.7 million on a note receivable balance of approximately $38.6 million due from an affiliate of Panda. The note is guaranteed by Panda and collateralized by Panda’s carried interest in our Oneta power plant. See Note 11 for a discussion of the impairment.

See also Reorganization Items under Note 4 for a discussion of an impairment charge of approximately $0.9 billion related to our investment in certain Canadian Debtors.

As we develop and implement our business plan, there could be additional impairment charges in future periods.


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

As of December 31, 2005 and 2004, the components of property, plant and equipment, are stated at cost less accumulated depreciation as follows (in thousands):


	2005			2004

Buildings, machinery, and equipment	$	14,023,358		$	14,615,907
Oil and gas pipelines		106,752			90,625
Geothermal properties		480,149			474,869
Other		178,145			206,049

		14,788,404			15,387,450
Less: Accumulated depreciation		(1,872,989	)		(1,416,586	)

		12,915,415			13,970,864
Land		92,595			104,972
Construction in progress		1,111,205			4,321,907

Property, plant and equipment, net	$	14,119,215		$	18,397,743

See Note 6 for a discussion of impairments.

Total depreciation expense for the years ended December 31, 2005, 2004 and 2003 was $526.0 million, $465.2 million and $400.7 million, respectively.

We have various debt instruments that are secured by certain of our property, plant and equipment. See Notes 14 — 24 for a detailed discussion of such instruments.


	*Buildings, Machinery and Equipment*

This component primarily includes electric power plants and related equipment. Depreciation is recorded utilizing the straight-line method over the estimated original composite useful life, generally 35 years for baseload power plants, exclusive of the estimated salvage value, typically 10%. Peaking facilities are generally depreciated over 40 years, less the estimated salvage value of 10%. We capitalize costs for major turbine generator refurbishments, which include such significant items as combustor parts (e.g. fuel nozzles, transition pieces, and “baskets”), compressor blades, vanes and diaphragms. These refurbishments are done either under LTSAs by the original equipment manufacturer or by our Turbine Maintenance Group. The capitalized costs

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are depreciated over their estimated useful lives ranging from 2 to 20 years. At December 31, 2005, the weighted average life was approximately 6 years. We expense annual planned maintenance. Included in buildings, machinery and equipment are assets under capital leases. See Note 18 for more information regarding these assets under capital leases. Certain capital improvements associated with leased facilities may be deemed to be leasehold improvements and are amortized over the shorter of the term of the lease or the economic life of the capital improvement.


	*Oil and Gas Pipelines*

On July 7, 2005, we, along with our subsidiaries Calpine Gas Holdings LLC and Calpine Fuels Corporation, sold substantially all of our remaining domestic oil and gas assets (other than certain gas pipeline assets) to Rosetta for $1.05 billion, less certain transaction fees and expenses. The disposition qualified as discontinued operations upon our commitment to a plan of divesture in the quarter ended June 30, 2005. See Note 13 for more information regarding our discontinued operations.

We historically followed the successful efforts method of accounting for oil and natural gas activities. Under the successful efforts method, lease acquisition costs and all development costs were capitalized. Exploratory drilling costs were capitalized until the results were determined. If proved reserves were not discovered, the exploratory drilling costs were expensed. Other exploratory costs were expensed as incurred. Interest costs related to financing major oil and gas projects in progress were capitalized until the projects were evaluated or until the projects were substantially complete and ready for their intended use if the projects were evaluated as successful. The provision for depreciation, depletion, and amortization was based on the capitalized costs as determined above, plus future abandonment costs net of salvage value, using the units of production method with lease acquisition costs amortized over total proved reserves and other costs amortized over proved developed reserves. The amounts remaining at December 31, 2005 and 2004, represent pipeline assets, which are depreciated over 30 years.

Prior to the sale of these oil and gas production assets and reserves in July 2005, we assessed the impairment for oil and gas properties periodically (at least annually) to determine if impairment of such properties were necessary. Management utilized its year-end reserve report prepared by a licensed independent petroleum engineering firm and related market factors to estimate the future cash flows for all proved developed (producing and non-producing) and proved undeveloped reserves. Property impairments occurred if a field discovered lower than anticipated reserves, reservoirs produced below original estimates or if commodity prices fell to a level that significantly affected anticipated future cash flows on the property. Proved oil and gas property values were reviewed when circumstances suggest the need for such a review and, if required, the proved properties were written down to their estimated fair value based on proved reserves and other market factors. Unproved properties were reviewed quarterly to determine if there had been impairment of the carrying value, with any such impairment charged to expense in the current period. As a result of decreases in proved undeveloped reserves located in South Texas and proved developed non-producing reserves in Offshore Gulf of Mexico, a non-cash impairment charge of approximately $202.1 million was recorded for the year ended December 31, 2004, which was reclassified to discontinued operations upon the sale of our oil and gas assets in July 2005.


	*Geothermal Properties*

We capitalize costs incurred in connection with the development of geothermal properties, including costs of drilling wells and overhead directly related to development activities as well as costs of production equipment, the related facilities and the operating power plants. Proceeds from the sale of geothermal properties are applied against capitalized costs, with no gain or loss recognized.

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


	*Other*

This component primarily includes software and ERCs. Software is amortized over its estimated useful life, generally 3 to 5 years. We hold ERCs that must generally be acquired during the permitting process for power plants in construction. ERCs are related to reductions in environmental emissions that result from some action like increasing energy efficiency, and are measured and registered in a way so that they can be bought, sold and traded. The lives of the ERCs are usually consistent with the life of the related plant. The gross ERC balance recorded in property, plant and equipment and included in “Other” above was $69.6 million and $103.6 million as of December 31, 2005 and 2004, respectively. Of this balance $30.8 million and $21.3 million related to plants in operation as of December 31, 2005 and 2004, respectively. The depreciation expense recorded in 2005, 2004 and 2003 related to ERCs was $0.7 million, $0.5 million and $0.5 million, respectively. During 2005, ERCs available for sale were reclassified from property, plant and equipment to the “Other assets” line of the Consolidated Balance Sheet. As of December 31, 2005, the total of such ERCs in “Other assets” was $20.1 million.


	*Construction in Progress*

CIP is primarily attributable to gas-fired power projects under construction including prepayments on gas and steam turbine generators and other long lead-time items of equipment for certain development projects not yet in construction. Upon commencement of plant operation, these costs are transferred to the applicable property category, generally buildings, machinery and equipment.


	Capital Spending — Development and Construction

CIP, development costs in process and unassigned equipment consisted of the following at December 31, 2005 (in thousands):


					Equipment		Project
	# of				Included in		Development		Unassigned
	Projects		CIP		CIP		Costs		Equipment

Projects in active construction(1)		4	$	662,952	$	247,916	$	—	$	—
Projects in suspended construction		3		265,416		167,447		—		—
Projects in suspended development		6		167,859		167,800		24,232		—
Other capital projects		NA		14,978		—		—		—
Unassigned equipment		NA		—		—		—		137,760

Total construction and development costs			$	1,111,205	$	583,163	$	24,232	$	137,760

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(1)	There were a total of four consolidated projects in active construction at December 31, 2005. Additionally, we had two projects in active construction that are recorded in unconsolidated investments and are not included in the table above.

Projects in Active Construction — Subsequent to December 31, 2005, we entered into a non-binding letter of intent contemplating the negotiation of a definitive agreement for the sale of Otay Mesa Energy Center, which is included in this table as a project in active construction and on which we recorded an impairment charge in the period ending December 31, 2005. See Note 34 for a description of the agreement. The remaining three consolidated projects in active construction are projected to come on line during 2006 or later. These projects will bring on line approximately 747 MW of base load capacity (871 MW with peaking capacity). Interest and other costs related to the construction activities necessary to bring these projects to their intended use are being capitalized. At December 31, 2005, the total projected cost to complete these three projects was approximately $215.2 million, which we primarily expect to fund under project financing facilities.

Projects in Suspended Construction — There are an additional three projects in suspended construction. These projects would bring on line approximately 1,769 MW of base load capacity (2,035 MW with peaking capacity). Work and capitalization of interest on the three projects has been suspended or delayed and we recorded impairment charges on all three of these projects in the period ending December 31, 2005.

Projects in Suspended Development — We have ceased capitalization of additional development costs and interest expense on certain development projects on which work has been suspended. Capitalization of costs may recommence as work on these projects resumes, if certain milestones and criteria are met indicating that it is again highly probable that the costs will be recovered through future operations. As is true for all projects, the suspended projects are reviewed for impairment whenever there is an indication of potential reduction in a project’s fair value. Further, if it is determined that it is no longer probable that the projects will be completed and all capitalized costs recovered through future operations, the carrying values of the projects would be written down to their recoverable value. In fact, we recorded substantial impairment charges on certain of these projects in the period ending December 31, 2005. These projects would bring on line approximately 1,533 MW of base load capacity (2,210 MW with peaking capacity).

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

On July 29, 2005, we completed the sale of our Inland Empire Energy Center development project to General Electric for approximately $30.9 million. The project will be financed, owned and operated by General Electric. We will manage plant construction, market the plant’s output, and manage its fuel requirements. We have an option to purchase the facility in years seven through fifteen following the commercial operation date and General Electric can require us to purchase the facility for a limited period of time in the fifteenth year, all subject to satisfaction of various terms and conditions. If we purchase the facility under the call or put, General Electric will continue to provide critical plant maintenance services throughout the remaining estimated useful life of the facility. Because of continuing involvement related to the purchase option and put, we deferred the gain of approximately $10 million until the call or put option is either exercised or expires.

Unassigned Equipment — As of December 31, 2005, we had made progress payments on four turbines and other equipment with an aggregate carrying value of $137.8 million. This unassigned equipment is classified on the balance sheet as other assets because it is not assigned to specific development and construction projects. We are holding this equipment for potential use on future projects. It is possible that some of this unassigned equipment may eventually be sold. For equipment that is not assigned to development or construction projects, interest is not capitalized.

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Capitalized Interest — We capitalize interest on capital invested in projects during the advanced stages of development and the construction period in accordance with SFAS No. 34, “Capitalization of Interest Cost,” as amended by SFAS No. 58, “Capitalization of Interest Cost in Financial Statements That Include Investments Accounted for by the Equity Method (an Amendment of FASB Statement No. 34).” Our qualifying assets include CIP, construction costs related to unconsolidated investments in power projects under construction, advanced stage development costs considered highly probable of completion, including assets classified from time-to-time as held for sale. For the years ended December 31, 2005, 2004 and 2003, the total amount of interest capitalized was $196.1 million, $376.1 million and $444.5 million, including $38.2 million, $49.1 million and $66.0 million, respectively, of interest incurred on funds borrowed for specific construction projects and $157.9 million, $327.0 million and $378.5 million, respectively, of interest incurred on general corporate funds used for construction. Upon commencement of plant operation, capitalized interest, as a component of the total cost of the plant, is amortized over the estimated useful life of the plant. The decrease in the amount of interest capitalized during the year ended December 31, 2005, reflects the completion of construction for several power plants, the suspension of certain of our development and construction projects, and a reduction in our development and construction program in general.

In accordance with SFAS No. 34, we determine which debt instruments best represent a reasonable measure of the cost of financing construction assets in terms of interest cost incurred that otherwise could have been avoided. These debt instruments and associated interest cost are included in the calculation of the weighted average interest rate used for capitalizing interest on general funds. Historically, the primary debt instruments included in the rate calculation of interest incurred on general corporate funds have been our Senior Notes, our term loan facilities and our secured working capital revolving credit facility with adjustments made as debt is retired or new debt is issued. We filed for protection on December 20, 2005, and subsequent to this date the debt instruments included in the rate calculation were the first priority Senior Notes and the DIP Facility. At the bankruptcy filing date, unsecured and undersecured Senior Notes and Term Loans were classified to “Liabilities Subject to Compromise” and were removed from the rate calculation for the period subsequent to the bankruptcy filing date. See Note 3 of the Notes to Consolidated Financial Statements for more information on the bankruptcy filing.

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	*Asset Retirement Obligations*

The information below reconciles the values, as of December 31, 2005, of the asset retirement obligation related to our continuing operations from the date the liability was recorded (in thousands):


		Total

Asset retirement obligation at January 1, 2004		$	23,551
	Liabilities incurred		3,492
	Liabilities settled		(324	)
	Accretion expense		5,174
	Revisions in the estimated cash flows		—
	Other (primarily foreign currency translation)		(1,897	)

Asset retirement obligation at December 31, 2004		$	29,996
	Liabilities incurred		156
	Liabilities settled		—
	Accretion expense		3,634
	Revisions in the estimated cash flows		(129	)
	Other (primarily Canadian and other foreign subsidiaries deconsolidation)		(846	)

Asset retirement obligation at December 31, 2005		$	32,811


8.	Goodwill and Other Intangible Assets

As of December 31, 2005, we completed our annual goodwill impairment test as required under SFAS No. 142, “Goodwill and Other Intangible Assets,” and determined that the fair value of the reporting units with goodwill exceeded their net carrying values. Therefore, our goodwill asset was not impaired as of December 31, 2005. Subsequent goodwill impairment tests will be performed, at a minimum, in December of each year in conjunction with our annual reporting process. The entire balance of goodwill, $45.2 million, has been assigned to the PSM reporting unit, which is included in the Other category as defined by SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information.”

The components of the amortizable intangible assets consist of the following (in thousands):


		Weighted		As of December 31, 2005					As of December 31, 2004
		Average
		Useful Life/		Carrying		Accumulated			Carrying		Accumulated
		Contract Life		Amount(1)		Amortization(1)			Amount(1)		Amortization(1)

Patents			5	$	—	$	—		$	485	$	(417	)
Power purchase agreements			23		85,099		(46,237	)		85,099		(43,115	)
Fuel supply and fuel management contracts			23		5,000		(2,039	)		5,000		(1,826	)
Geothermal lease rights(2)			20		8,108		(650	)		19,518		(550	)
Other			15		5,887		(1,025	)		4,755		(526	)

	Total			$	104,094	$	(49,951	)	$	114,857	$	(46,434	)


(1)	Fully amortized intangible assets are not included.

(2)	Geothermal lease rights relate to undeveloped properties at The Geysers. Certain of these properties were no longer probable of development, and we recorded an impairment charge of approximately $11.4 mil-

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	lion in the period ended December 31, 2005. This charge is reflected in the “Equipment, development project and other impairments” line item of the Consolidated Statements of Operations. See Note 6 for more information regarding the impairment of our development projects.

Amortization expense of Other intangible assets was $4.0 million, $4.6 million and $4.9 million, in 2005, 2004 and 2003, respectively. Assuming no future impairments of these assets or additions as the result of acquisitions, annual amortization expense will be $3.9 million in 2006, $4.0 million in 2007, $4.0 million in 2008, $4.0 million in 2009 and $3.0 million in 2010.


9.	Acquisitions

As a result of the bankruptcy filings, we are not currently evaluating any opportunities to acquire power generating facilities or other significant assets and there were no mergers or acquisitions consummated during the year ended December 31, 2005. In prior years, acquisition activity was dependent on the availability of financing on attractive terms and the expectation of returns that met our long-term requirements. The following material mergers and acquisitions were consummated during the years ended December 31, 2004 and 2003. For all business combinations, the results of operations of the acquired companies were incorporated into our consolidated financial statements commencing on the date of acquisition.


	*2004 Acquisitions*


	Calpine Cogeneration Company Transaction

On March 23, 2004, we completed the acquisition of the remaining 20% interest in Calpine Cogen, which held interests in six power facilities, from NRG Energy, Inc. for approximately $2.5 million. We purchased our initial 80% interest in Calpine Cogen (formerly known as Cogeneration Corporation of America) from NRG in 1999. Prior to the 2004 acquisition, we consolidated the assets of Calpine Cogen in our financial statements and reflected the 20% interest held by NRG as a minority interest. NRG’s minority interest had a carrying value of approximately $37.5 million at the time of acquisition. The carrying value of the underlying assets was adjusted downward on a pro-rata basis for the difference between the purchase price and the carrying value of NRG’s minority interest. As a result of this transaction, we had a 100% interest in the Newark, Parlin, Morris and Pryor facilities, an 83% interest in the Philadelphia Water Project and a 50% interest in the Grays Ferry Power Plant. In 2005, we sold our interests in the Grays Ferry Power Plant and the Morris facility.


	Aries Transaction

On March 26, 2004, we acquired the remaining 50% interest in the Aries Power Plant from a subsidiary of Aquila, Inc. (we refer to Aquila and its subsidiaries collectively as “Aquila”). At the same time, Aries terminated a tolling contract with another subsidiary of Aquila. Aquila paid $5 million in cash and assigned certain transmission and other rights to us. We and Aquila also amended a master netting agreement between us, and as a result, we returned cash margin deposits totaling $10.8 million to Aquila. Contemporaneous with the closing of the acquisition, Aries’ existing construction loan was converted to two term loans totaling $178.8 million. We contributed $15 million of equity to Aries in connection with the term out of the construction loan.

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The amounts below represent 50% of the fair value of the assets acquired and liabilities assumed in the transaction as of the closing date. These amounts together with 50% of the investment owned by us prior to the acquisition are now fully consolidated into our financial statements.


	Debit/ (Credit)

Current assets	$	1,028
Contracts		2,505
Property, plant and equipment		100,793
Other assets		1,902
Current liabilities		(1,978	)
Derivative liability		(16,022	)
Long-term debt		(88,228	)


	Brazos Valley Power Plant Transaction

On March 31, 2004, we closed on the purchase of the 570-MW natural gas-fired Brazos Valley Power Plant located in Fort Bend County, Texas, for total consideration of approximately $181.1 million. We used the net proceeds from the sale in January 2004 of our 50% undivided interest in the Lost Pines 1 facility and cash on hand to acquire Brazos Valley in a transaction structured as a tax deferred like-kind exchange under IRS Section 1031. The equity interests in Brazos Valley were pledged as part of the collateral package supporting the CCFC notes and term loans. The fair value of the Brazos Valley facility was equal to the purchase price and as a result, the entire purchase price was allocated to the power plant assets and is recorded in property plant and equipment in our Consolidated Balance Sheets.


	*2003 Acquisitions*


	Thomassen Turbine Systems Transaction

On February 26, 2003, we, through our wholly owned subsidiary Calpine European Finance, LLC, purchased 100% of the outstanding stock of BBPTS from its parent company, Babcock Borsig. Immediately following the acquisition, the BBPTS name was changed to Thomassen Turbine Systems, B.V. Our total cost of the acquisition was $12.0 million and was comprised of two pieces. The first was a $7.0 million cash payment to Babcock Borsig to acquire the outstanding stock of TTS. Included in this payment was the right to a note receivable valued at 11.9 million Euro (approximately US$12.9 million on the acquisition date) due from TTS, which we acquired from Babcock Borsig for $1.00. Additionally, as of the date of the acquisition, TTS owed $5.0 million in payments to another of our wholly owned subsidiaries, PSM, under a pre-existing license agreement. Because of the acquisition, TTS ceased to exist as a third party debtor to us, thereby resulting in a reduction of third party receivables of $5.0 million from our consolidated perspective. In December 2005, we deconsolidated TTS along with most of our Canadian and other foreign subsidiaries. See Note 10 for more information on the deconsolidation.

Pro Forma Effects of Acquisitions

Acquired businesses are consolidated upon the closing date of the acquisition. The table below reflects the unaudited pro forma combined results of operations for all business combinations during 2004 and 2003, as

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if the acquisitions had taken place at the beginning of fiscal year 2003. Our consolidated financial statements include the effects of Calpine Cogen, Aries, Brazos Valley and TTS:


	2004			2003

	(in thousands, except per
	share amounts)
Total revenue	$	8,938,746		$	8,714,609
Income (loss) before discontinued operations and cumulative effect of accounting changes	$	(485,746	)	$	(62,163	)
Net income (loss)	$	(250,176	)	$	266,743
Net income (loss) per basic share	$	(0.58	)	$	0.68
Net income (loss) per diluted share	$	(0.58	)	$	0.67

In management’s opinion, these unaudited pro forma amounts are not necessarily indicative of what the actual combined results of operations might have been if the 2004 and 2003 acquisitions had been effective at the beginning of fiscal year 2003. In addition, they are not intended to be a projection of future results and do not reflect all the synergies that might be achieved from combined operations.


10.	Investments

Our investments in power projects are integral to our operations. As discussed in Note 2, our joint venture investments were evaluated under FIN 46-R to determine which, if any, entities were VIEs. Based on this evaluation, we determined that Acadia PP, Whitby, Valladolid, Greenfield LP and AELLC were VIEs, in which we held a significant variable interest. During the latter half of 2005, due to the restructuring of the CES tolling arrangement with Acadia PP, we reconsidered our investment in Acadia PP under FIN 46-R. As a result, we determined that we were the “Primary Beneficiary” under FIN 46-R and, accordingly, have consolidated Acadia PP as discussed below. In the fourth quarter of 2004, we changed from the equity method to the cost method to account for our investment in AELLC as discussed below. In the fourth quarter of 2005, we also deconsolidated most of our Canadian and other foreign entities, including Whitby, and began to account for them under the cost method. We continue to account for our unconsolidated joint venture investments in Valladolid (prior to its sale in April 2006) and Greenfield LP in accordance with APB Opinion No. 18, “The Equity Method of Accounting For Investments in Common Stock” and FIN 35, “Criteria for Applying the Equity Method of Accounting for Investments in Common Stock (An Interpretation of APB Opinion No. 18).”

Valladolid is the owner of a 525-MW natural gas-fired energy center currently under construction sponsored by CFE at Valladolid, Mexico in the Yucatan Peninsula. The project was a joint venture between us, Mitsui and Chubu, both headquartered in Japan. As of December 31, 2005, we owned 45% of the entity, while Mitsui and Chubu each owned 27.5%. Our maximum potential exposure to loss at December 31, 2005, was limited to the book value of our investment of approximately $42.9 million. See Note 34 regarding the subsequent sale of our interest in Valladolid. Also, see Note 6 regarding the impairment charge due to the other-than-temporary decline in value of this investment.

Greenfield LP is the owner of a 1,005-MW combined cycle generation facility under construction in the Township of St. Clair in Ontario, Canada. In April 2005, Greenfield LP entered into a 20-year Clean Energy Supply Contract with the Ontario Power Authority to sell clean energy from the power plant. In November 2005 we contributed three combustion gas turbine generators and one steam turbine generator with a book value of approximately $154.1 million in exchange for a 50% interest in Greenfield LP. Mitsui owns the other 50% interest. As of December 31, 2005 our investment interest in the project was $40.7 million, representing the fair value of the turbines of approximately $60.9 million less a receivable of approximately $20.2 million from Mitsui that was recorded upon transfer of the turbines, which represented a return of capital. This

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receivable is reflected in the “Other assets” line of the Consolidated Balance Sheet as of December 31, 2005. Our maximum potential exposure to loss at December 31, 2005, is limited to the book value of our investment of approximately $40.7 million. Also, see Note 6 regarding the impairment charge due to the other-than-temporary decline in value of this investment.

AELLC is the owner of Androscoggin Energy Center, a 136-MW natural gas-fired cogeneration facility located in Maine and is a joint venture between us, affiliates of Wisvest Corporation and IP. On November 3, 2004, a jury verdict was rendered against AELLC in a breach of contract dispute with IP. See Note 3 for more information about the legal proceeding. We recorded our $11.6 million share of the award amount in the third quarter of 2004. On November 26, 2004, AELLC filed a voluntary petition for relief under Chapter 11 of the Bankruptcy Code. As a result of the bankruptcy filing by AELLC, we have lost significant influence and control of the project and have adopted the cost method of accounting for our investment in AELLC. Also, in December 2004, we determined that our investment in AELLC, including outstanding notes receivable and O&M receivable, was impaired and recorded a $5.0 million impairment reserve. The facility had third-party debt of $63.4 million outstanding as of December 31, 2004, primarily consisting of $60.3 million in construction debt. The debt was non-recourse to Calpine Corporation. On April 12, 2005, AELLC sold three fixed-price gas contracts to Merrill Lynch Commodities Canada, ULC, and used a portion of the proceeds to pay down its remaining construction debt. As of December 31, 2005, the facility had third-party debt outstanding of $3.1 million. Subsequent to December 31, 2005, AELLC received confirmation of its reorganization plan. See Note 31 for more information.

Whitby is the owner of a 50-MW natural gas-fired cogeneration facility located in Ontario, Canada and is a joint venture between us and a privately held enterprise. The below-mentioned deconsolidation of our Canadian and other foreign entities included our subsidiary that held the 50% ownership interest in the Whitby joint venture. Consequently, we considered our ownership interest in Whitby as a part of the deconsolidation and fully impaired it. We use the cost method to account for this investment.

SFAS No. 94, “Consolidation of All Majority-Owned Subsidiaries” requires consolidation of all majority-owned subsidiaries unless control is temporary or does not rest with the majority owner (as, for instance, where the subsidiary is in legal reorganization or in bankruptcy). Upon filing for bankruptcy in the United States and Canada on December 20, 2005, we determined that it was necessary to deconsolidate most of our Canadian and other foreign subsidiaries because the Canadian debtor cases are not administered within the same jurisdiction as the bankruptcy cases of Calpine Corporation and the other U.S. Debtors, and as a result, we had lost the elements of control (as described in SFAS No. 94) necessary to continue to consolidate these Canadian and other foreign subsidiaries. We deconsolidated these subsidiaries as of December 20, 2005 and have subsequently accounted for our investment in our Canadian and other foreign subsidiaries under the cost method. Upon adoption of the cost method, we evaluated our investment balances and intercompany notes receivable from these entities for impairment. We determined that our entire investment in these entities had experienced other-than-temporary decline in value and was impaired. We also concluded that all intercompany notes receivable balances from these entities were uncollectible, as the notes were unsecured and protected by the automatic stay under the CCAA. Consequently, we fully impaired these investment and receivable assets at December 31, 2005, resulting in a $879.1 million charge to reorganization items. After full impairment of our investment in these subsidiaries, our cost basis is $0 at December 31, 2005.

When we deconsolidated our Canadian and other foreign subsidiaries, we deconsolidated approximately $2.0 billion of debt to third parties issued by certain of these subsidiaries. See Note 24 for a description of these debt instruments. Additionally, Calpine Corporation has guaranteed the debt obligations to the security holders of certain of the deconsolidated debt, in some cases through redundant or overlapping arrangements. The beneficiaries of those guarantees, including the security holders, may submit claims against us in the U.S. Bankruptcy Court (on the bais of such guarantees). Consequently, in accordance with SOP 90-7, we

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have also recorded approximately $3.8 billion of LSTC and reorganization item expense, which is our assessment of the probable allowable claims. This is notwithstanding the fact that we expect that the ultimate settlement of the claims will be capped at the amount actually owed to the applicable holders of the deconsolidated debt, or approximately $2 billion.

Acadia PP is the owner of a 1,210-MW electric wholesale generation facility located in Louisiana and is a partnership between us and a subsidiary of Cleco. On May 12, 2003, we completed the restructuring of our interest in Acadia PP. As part of the transaction, the partnership terminated its 580-MW, 20-year tolling arrangement with a subsidiary of Aquila, Inc. in return for a cash payment of $105.5 million. Acadia PP recorded a gain of $105.5 million and then made a $105.5 million distribution to us. Contemporaneously, our wholly owned subsidiary, CES, entered into a new 20-year, 580-MW tolling contract with Acadia PP. CES now markets all of the output from the Acadia Energy Center under the terms of this new contract and an existing 20-year tolling agreement. Cleco receives priority cash distributions as its consideration for the restructuring. Also, as a result of this transaction, we recorded, as our share of the termination payment from the Aquila subsidiary, a $52.8 million gain as of December 31, 2003, which was recorded within “Income from unconsolidated investments” in the Consolidated Statements of Operations. Due to the restructuring of our interest in Acadia PP, we were required to reconsider our investment in the entity under FIN 46 and determined that we were not the “Primary Beneficiary” and accordingly we continued to account for our investment using the equity method. As mentioned above, in the second half of 2005, CES restructured its tolling agreement with Acadia PP to include additional payments from CES to Acadia Power Holdings, a Cleco subsidiary that holds its investment in Acadia PP. This restructuring of the tolling and related agreements caused us to re-evaluate our economic interest in the partnership. Based on our reassessment, we determined that we became the “Primary Beneficiary” of this VIE and we now consolidate Acadia PP. Our consolidated financial statements include the assets and liabilities of Acadia PP at December 31, 2005. We have also reflected Cleco’s 50% interest in the partnership, approximately $275.4 million, as a minority interest in our balance sheet at December 31, 2005. See also Note 3 for a legal proceeding involving Acadia PP.

Of the following investments, Valladolid III Energy Center and Greenfield Energy Center are accounted for under the equity method while Androscoggin Energy Center, Whitby Cogeneration and the Canadian and other foreign subsidiaries are accounted for under the cost method (in thousands):


		Ownership			Investment Balance at
		Interest as of			December 31,
		December 31,
		2005			2005		2004

Valladolid III Energy Center(1)			45.0	%	$	42,900	$	77,401
Greenfield Energy Centre(2)			50.0	%		40,698		—
Androscoggin Energy Center(3)			32.3	%		—		—
Whitby Cogeneration(3)			50.0	%		—		32,528
Other Canadian and other foreign subsidiaries(3)			100.0	%		—		—
Grays Ferry Power Plant(4)			50.0	%		—		48,558
Acadia Energy Center(5)			50.0	%		—		214,501
Other			—			22		120

	Total investments in power projects				$	83,620	$	373,108


(1)	Subsequent to December 31, 2005, we sold our 45% interest in Valladolid to Mitsui and Chubu. See Notes 6 and 34 for more information.

(2)	In addition to our investment in Greenfield LP, as of December 31, 2005 we had a receivable from Mitsui of approximately $20.2 million.

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(3)	These investments were fully impaired at December 31, 2005. Also, the investment in Androscoggin Energy Center excludes certain Notes Receivable. See Note 10 for more information on such notes receivable.

(4)	On July 8, 2005, we completed the sale of the Grays Ferry Power Plant, in which we held a 50% interest, for gross proceeds of $37.4 million. In June 2005, we recorded to the “Other expense (income), net” line of the Consolidated Condensed Statement of Operations an $18.5 million impairment charge. This transaction did not qualify as a discontinued operation under the guidance of SFAS No. 144, which specifically excludes equity method investments from its scope, unless the investment is part of a larger disposal group.

(5)	As discussed above, this investment is consolidated into our financial statements as of December 31, 2005.

The following details our income and distributions from investments in unconsolidated power projects (in thousands):


		Income (Loss) from Unconsolidated
		Investments in Power Projects									Distributions

		For the Years Ended December 31,

		2005			2004			2003			2005		2004		2003

Valladolid III Energy Center		$	(213	)	$	76		$	—		$	—	$	—	$	—
Androscoggin Energy Center			—			(23,566	)		(7,478	)		—		—		—
Whitby Cogeneration			2,234			1,433			303			4,533		1,499		—
Grays Ferry Power Plant			(739	)		(2,761	)		(1,380	)		—		—		—
Acadia Energy Center			10,872			14,142			75,272			20,231		21,394		136,977
Aries Power Plant(1)			—			(4,264	)		(3,442	)		—		—		—
Calpine Natural Gas Trust(2)			—			—			—			—		6,127		1,959
Gordonsville Power Plant(3)			—			—			11,985			—		—		2,672
Other			(35	)		12			(1	)		198		849		19

	Total	$	12,119		$	(14,928	)	$	75,259		$	24,962	$	29,869	$	141,627

Interest income on loans to power projects(4)		$	—		$	840		$	465

Total		$	12,119		$	(14,088	)	$	75,724


(1)	On March 26, 2004, we acquired the remaining 50% interest in the Aries Power Plant. See Note 9 for a discussion of the acquisition.

(2)	On September 2, 2004, we completed the sale of our equity investment in CNGT. See Note 13 for more information on the 2004 sale of the Canadian natural gas reserves and petroleum assets.

(3)	On November 26, 2003, we completed the sale of our 50% interest in the Gordonsville Power Plant. Under the terms of the transaction, we received $36.2 million in cash for our $25.4 million investment and recorded a pre-tax gain of $7.1 million.

(4)	At December 31, 2005 and 2004, loans to power projects represented an outstanding loan to our 32.3% owned investment, AELLC, in the amount of $4.0, million after impairment charges and reserves.

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The combined summarized results of operations and financial position of 50% or less owned investments are summarized below (in thousands):


			December 31,

			2005			2004			2003

Condensed statements of operations:
	Revenue		$	171,065		$	237,983		$	416,506
	Gross profit(1)			112,551			45,994			147,247
	Income (loss) from continuing operations before extraordinary items and cumulative effect of a change in accounting principle			(30,930	)		(9,230	)		174,730
	Net income (loss)			(30,930	)		(9,230	)		174,730
Condensed balance sheets:
	Current assets		$	101,538		$	67,022
	Non-current assets			456,201			897,574

		Total assets	$	557,739		$	964,596

	Current liabilities		$	199,468		$	150,716
	Non-current liabilities			226,680			114,597

		Total liabilities	$	426,148		$	265,313


(1)	The 2005 gross profit primarily consists of revenue AELLC received from the April 2005 sale of fixed price gas contracts as explained above.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The summarized results of operations from the date of deconsolidation to December 31, 2005, and financial position as of December 31, 2005, of our Canadian and other foreign subsidiaries are summarized below (in thousands):


			December 31,
			2005

Condensed statements of operations:
	Revenue		$	12,453
	Gross profit			(1,355	)
	Loss from continuing operations before extraordinary items and cumulative effect of a change in accounting principle			(55,898	)
	Net loss			(55,898	)
Condensed balance sheets:
	Current assets		$	250,969
	Non-current assets			571,288

		Total assets	$	822,257

	Current liabilities		$	122,962
	Non-current liabilities			41,587

		Total liabilities not subject to compromise	$	164,549

		Liabilities subject to compromise	$	2,171,893

The debt on the books of the unconsolidated investments is not reflected on our balance sheet. At December 31, 2005 and 2004, investee debt was approximately $2,161.7 million and $133.9 million, respectively. Approximately $1,971.2 million, related to our deconsolidated Canadian and other foreign subsidiaries at December 31, 2005. Based on our pro rata ownership share of each of the investments, our share of such debt would be approximately $2,057.7 million and $46.6 million for the respective periods. However, except for the debt of the deconsolidated Canadian and other foreign entities, as previously mentioned, all such debt is non-recourse to us.


	*Related-Party Transactions with Unconsolidated Investments*

We and certain of our equity and cost method affiliates have entered into various service agreements with respect to power projects. Following is a general description of each of the various agreements:

Operation and Maintenance Agreements — We operate and maintain the Androscoggin Energy Center. This includes routine maintenance, but not major maintenance, which is typically performed under agreements with the equipment manufacturers. Responsibilities include development of annual budgets and operating plans. Payments include reimbursement of costs, including our internal personnel and other costs, and annual fixed fees.

Construction Management Services Agreements — We provide construction management services to Valladolid and Greenfield LP. Payments include reimbursement of costs, including our internal personnel and other costs. See Note 34 for an update on the sale of Valladolid.

Administrative Services Agreements — We handle administrative matters such as bookkeeping for certain unconsolidated investments. Payment is on a cost reimbursement basis, including our internal costs, with no additional fee.

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Capital Lease Agreement — See Note 18 for a complete discussion of our capital lease agreement with CPIF, a related party.

Power Marketing Agreement — CES enters into trading agreements with CES Canada to buy and sell power under the terms of the Edison Electric Institute.

Gas Supply Agreement — CES also enters into trading agreements with CES Canada to buy and sell gas under the terms of the North American Energy Standards Board.

The power and gas supply contracts with CES are accounted for as either purchase and sale arrangements or as tolling arrangements. In a purchase and sale arrangement, title and risk of loss associated with the purchase of gas is transferred from CES to the project at the gas delivery point. In a tolling arrangement, title to fuel provided to the project does not transfer, and CES pays the project a capacity and variable fee based on the specific terms of the power marketing and/or gas supply agreement. CES maintains two tolling agreements with Acadia PP. The two tolling agreements are included in the amounts below through the fourth quarter of 2005 at which time we began consolidating Acadia PP. In addition to the power marketing agreements and gas supply agreements, CES enters into standard industry financial instruments with CES Canada. The related party balances as of December 31, 2005 and 2004, reflected in the accompanying consolidated balance sheets, and the related party transactions for the years ended December 31, 2005, 2004 and 2003, reflected in the accompanying consolidated statements of operations, are summarized as follows (in thousands):


As of December 31,	2005		2004

Accounts receivable	$	5,073	$	765
Note receivable		4,037		4,037
Other receivables		641		—
Accounts payable		352		9,489
Other current liabilities		24,645		—
Liabilities subject to compromise		6,193,798		—


	For the Years Ended December 31,

	2005		2004		2003

Revenue	$	4,814	$	1,241	$	3,493
Cost of revenue		79,248		115,008		82,205
Interest expense		58		—		—
Interest income		—		840		1,117
Gain on sale of assets		—		6,240		62,176
Reorganization items		4,654,202		—		—

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


11.	Notes Receivable and Other Receivables

As of December 31, 2005 and 2004, the components of notes receivable were (in thousands):


			2005			2004

PG&E (Gilroy) note			$	135,045		$	145,853
Panda note				12,946			38,644
Eastman note				19,413			19,748
Androscoggin note				4,037			4,037
Other				6,419			7,168

	Total notes receivable			177,860			215,450
	Less: Notes receivable, current portion included in other current assets			(12,736	)		(11,770	)

		Notes receivable, net of current portion	$	165,124		$	203,680


	*Gilroy Note*

Gilroy had a long-term PPA with PG&E for the sale of energy through 2018. The terms of the PPA provided for 120 MW of firm capacity and up to 10 MW of as-delivered capacity. On December 2, 1999, the CPUC approved the restructuring of the PPA between Gilroy and PG&E. Under the terms of the restructuring, PG&E and Gilroy were each released from performance under the PPA effective November 1, 2002, and, in addition to the normal capacity revenue Gilroy earned for the period from September 1999 to October 2002, Gilroy was also entitled to restructured capacity revenue it would have earned over the November 2002 through March 2018 time period, for which PG&E issued notes to us. These notes are scheduled to be paid by PG&E during the period from February 2003 to September 2014.

On December 4, 2003, we announced that we had sold to a group of institutional investors our right to receive payments from PG&E under the notes for $133.4 million in cash. Because the transaction did not satisfy the criteria for sales treatment under SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities — a Replacement of FASB Statement No. 125,” it was reflected in the consolidated financial statements as a secured financing, with a note payable of $133.4 million. The receivable balance and note payable balance are both reduced as PG&E makes payments to the buyers of the Gilroy notes issued by PG&E. The $24.1 million difference between the $157.5 million book value of the Gilroy notes at the transaction date and the $133.4 million cash received is recognized as additional interest expense over the repayment term. We will continue to record interest income over the repayment term and interest expense will be accreted on the amortizing note payable balance.

Pursuant to the applicable transaction agreements, each of Gilroy and Gilroy 1, the general partner of Gilroy, has been established as an entity with its existence separate from us and other subsidiaries of ours. We consolidate these entities.


	*Panda Note*

In June 2000, we entered into a series of agreements to acquire turbines and development rights related to the construction, ownership and operation of the Oneta facility from Panda. PLC, a subsidiary of Panda, retained an interest in a portion of the income generated from Oneta as part of the consideration. As part of the transaction, we extended PLC a loan bearing an interest rate of LIBOR plus 5%. The loan is collateralized by PLC’s carried interest in the income generated from Oneta, which achieved full commercial operations in June 2003, and is guaranteed by Panda.

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On November 5, 2003, Panda filed suit against us and certain of our affiliates alleging, among other things, that we breached duties of care and loyalty allegedly owed to them by failing to correctly construct and operate the Oneta facility in accordance with Panda’s original plans. Panda alleges that it is entitled to a portion of the profits from Oneta and that our actions reduced the profits from Oneta, thereby undermining Panda’s ability to repay monies owed to us under the loan. We have filed a counterclaim against PLC and a motion to dismiss as to the causes of action alleging federal and state securities laws violations. The court recently granted our motion to dismiss, but allowed Panda an opportunity to re-plead. This litigation was stayed as a result of our bankruptcy filings on December 20, 2005. See Note 31 for more information on the litigation.

Panda defaulted on the loan, which was due on December 1, 2003. We continue to calculate interest income using the default interest rate of 9.0%, but have fully reserved the interest since that the default date. Based upon our qualitative and quantitative analysis (using a discounted cash flow model at a market interest rate commensurate with the risks currently associated with the collateral) as of December 31, 2005, the fair value of the collateral securing the Panda note appears to be reduced. Therefore, the note receivable is impaired, as the primary source of recovery is through the collateral value. We have written down the note balance as of December 31, 2005, to the estimated fair value of the collateral (see Note 6).


	*Eastman Note*

In August 2000, we entered into an ESA with Eastman at its Columbia facility in South Carolina. As part of the ESA, we financed the construction of the HTM facilities. Under this ESA, Eastman will repay us $20.0 million for the HTM financed facilities over a period of 20 years beginning in April 2004 at an annual interest rate of 9.76%.


	*Androscoggin Note*

We have a note receivable from our unconsolidated cost method investee AELLC, the owner of the Androscoggin facility. We ceased accruing interest income on our note receivable related to unreimbursed administration costs associated with our management of the project after a jury verdict was rendered against AELLC in a breach of contract dispute. In December 2004, we determined that our investment in Androscoggin was impaired and recorded a $5.0 million impairment reserve. On December 31, 2005 and 2004, the carrying value after reserves of our notes receivable balance due from AELLC was $4.0 million. See Note 10 for further information.


12.	Canadian Power and Gas Trusts

Calpine Power Income Fund — On August 29, 2002, we announced we had completed a Cdn$230 million (US$147.5 million) initial public offering of our Canadian income fund, CPIF. The 23 million trust units issued to the public were priced at Cdn$10 per trust unit, with an initial yield of 9.35% per annum. On September 20, 2002, the syndicate of underwriters fully exercised the over-allotment option that it was granted as part of the initial public offering of trust units and acquired 3,450,000 additional trust units of CPIF at Cdn$10 per trust unit, generating Cdn$34.5 million (US$21.9 million). CPIF used the proceeds of the initial offering and over-allotment to purchase an equity interest in CPLP, which holds two of our Canadian power generating assets, the Island Cogeneration Facility and the Calgary Energy Centre. CPIF also used a portion of the proceeds to make a loan to a subsidiary of ours which owns our other Canadian power generating asset, the equity investment in the Whitby cogeneration plant. Combined, these assets represent approximately 168.3 net MW of power generating capacity.

On February 13, 2003, we completed a secondary offering of 17,034,234 warranted units of CPIF for gross proceeds of Cdn$153.3 million (US$100.9 million). The warranted units were sold to a syndicate of

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underwriters at a price of Cdn$9.00. Each warranted unit consisted of one trust unit and one-half of one trust unit purchase warrant. Each warrant entitled the holder to purchase one trust unit at a price of Cdn$9.00 per trust unit at any time on or prior to December 30, 2003, after which time the warrant became null and void. During 2003 a total of 8,508,517 warrants were exercised, resulting in cash proceeds to us of Cdn$76.6 million (US$56.7 million). CPIF used the proceeds from the secondary offering and warrant exercise to purchase an additional equity interest in CPLP.

We currently hold less than 1% of CPIF’s trust units; however, we retain a 30% subordinated equity interest in CPLP and have a significant continuing involvement in the assets transferred to CPLP. The assets of CPLP were included in our consolidated balance sheet under the guidance of SFAS No. 66, “Accounting for Sales of Real Estate” due to our significant continuing involvement in the assets transferred to CPLP until CPLP was deconsolidated along with most of our Canadian and other foreign subsidiaries as further discussed in Note 10. The financial results of CPLP were also consolidated in our financial statements until December 20, 2005.

The proceeds from the initial public offering, the exercise of the underwriters over-allotment, the proceeds from the secondary offering of warranted units and the proceeds from the exercise of warrants represented CPIF’s 70% equity interest in CPLP and its underlying generating assets and were recorded as minority interests in our consolidated balance sheet prior to the deconsolidation of most of our Canadian and other foreign subsidiaries as described in Note 10. Because of our equity ownership in CPLP, we consider CPIF a related party. See Note 18 for a discussion of the capital lease transaction with CPIF.

Calpine Natural Gas Trust — On October 15, 2003, we closed the initial public offering of CNGT. A total of 18,454,200 trust units were issued at a price of Cdn$10.00 per trust unit for gross proceeds of approximately Cdn$184.5 million (US$139.4 million). CNGT acquired select natural gas and petroleum properties from us with the proceeds from the initial public offering, Cdn$61.5 million (US$46.5 million) proceeds from a concurrent issuance of units to a Canadian affiliate of ours, and Cdn$40.0 million (US$30.2 million) proceeds from bank debt. Net proceeds to us totaled approximately Cdn$207.9 million (US$157.1 million), reflecting a gain of $62.2 million on the sale of the properties. On October 22, 2003, the syndicate of underwriters fully exercised the over-allotment option associated with the initial public offering of trust units, resulting in additional cash to the CNGT. As a result of the exercise of the over-allotment option, we acquired an additional 615,140 trust units at Cdn$10.0 per trust unit for a cash payment to the CNGT of Cdn$6.2 million (US$4.7 million). Prior to the subsequent sale of this investment, we held 25 percent of the outstanding trust units of CNGT and accounted for it using the equity method.

On September 2, 2004, we completed the sale of our equity investment in the CNGT. In accordance with SFAS No. 144 our 25% equity method investment in the CNGT was considered part of the larger disposal group and therefore evaluated and accounted for as a discontinued operation. See Note 13 for more information on the sale of the Canadian natural gas reserves and petroleum assets. In addition, we considered CNGT a related party and disclosed all transactions up through the date of sale as such. See Note 10 for more information on related party transactions with unconsolidated investments.


13.	Discontinued Operations

Prior to our bankruptcy filings in December 2005, we had adopted a strategy of conserving our core strategic assets and selectively disposing of certain less strategically important assets. Our historical reportable segments under SFAS No. 131 consisted of “Oil and Gas Production and Marketing,” “Electric Generation and Marketing,” and “Other.” After the sale of our remaining oil and gas assets in July 2005, we eliminated the Oil and Gas Production and Marketing segment from our SFAS No. 131 disclosures in Note 32. Set forth below are our asset disposals by our historical reportable segments that impacted our consolidated financial statements as of December 31, 2005, 2004 and 2003.

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	*Oil and Gas Production and Marketing*

On November 20, 2003, we completed the sale of our Alvin South Field oil and gas assets located near Alvin, Texas for approximately $0.06 million to Cornerstone Energy, Inc. As a result of the sale, we recognized a pre-tax loss of $0.2 million.

On September 1, 2004, we along with our subsidiary CNGLP, completed the sale of our Rocky Mountain oil and gas assets, which were primarily concentrated in two geographic areas: the Colorado Piceance Basin and the New Mexico San Juan Basin. Together, these assets represented approximately 120 Bcfe of proved gas reserves, producing approximately 16.3 Mmcfe per day of gas. Under the terms of the agreement we received net cash payments of approximately $218.7 million, and recorded a pre-tax gain of approximately $103.7 million.

In connection with the sale of the Rocky Mountain gas reserves, the New Mexico San Juan Basin sales agreement allows for the buyer and us to execute a ten-year gas purchase agreement for 100% of the underlying gas production of sold reserves, at market index prices. Any agreement would be subject to mutually agreeable collateral requirements and other customary terms and provisions.

On September 2, 2004, we completed the sale of our Canadian oil and gas assets. These Canadian assets represented approximately 221 Bcfe of proved reserves, producing approximately 61 Mmcfe per day. Included in this sale was our 25% interest in approximately 80 Bcfe of proved reserves (net of royalties) and 32 Mmcfe per day of production owned by the CNGT. In accordance with SFAS No. 144, our 25% equity method investment in the CNGT was considered part of the larger disposal group (i.e., assets to be disposed of together as a group in a single transaction to the same buyer), and therefore evaluated and accounted for as discontinued operations. Under the terms of the agreement, we received cash payments of approximately Cdn$808.1 million, or approximately US$626.4 million. We recorded a pre-tax gain of approximately $104.5 million on the sale of these Canadian assets net of $20.1 million in foreign exchange losses recorded in connection with the settlement of forward contracts entered into to preserve the US dollar value of the Canadian proceeds.

In connection with the sale of our Canadian oil and gas assets, we entered into a seven-year gas purchase agreement beginning on March 31, 2005, and expiring on October 31, 2011, that allows, but does not require, us to purchase gas from the buyer at current market index prices. The agreement is not asset specific and can be settled by any production that the buyer has available.

We believe that all final terms of the gas purchase agreements described above are on a market value and arm’s length basis. If we elect in the future to exercise a call option over production from the disposed components, we will consider the call obligation to have been met as if the actual production delivered to us under the call was from assets other than those constituting the disposed components.

On July 7, 2005, we completed the sale of substantially all of our remaining oil and gas assets to Rosetta for $1.05 billion, less approximately $60 million of estimated transaction fees and expenses. We recorded a pre-tax gain of approximately $340.1 million, which is reflected in discontinued operations in the year ended December 31, 2005. Approximately $75 million of the purchase price is being withheld pending the transfer of certain properties with a book value as of December 31, 2005 of approximately $39 million.

In connection with the sale of the oil and gas assets to Rosetta, we entered into a two-year gas purchase agreement with Rosetta, expiring on December 31, 2009, for 100% of the production of the Sacramento basin assets, which represent approximately 44% of the reserve assets sold to Rosetta. We will pay the prevailing current market index price for all gas purchased under the agreement. We believe the gas purchase agreement was negotiated on an arm’s length basis and represents fair value for the production. Therefore, the agreement

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does not provide us with significant influence over Rosetta’s ability to realize the economic risks and rewards of owning the assets.

The following summary disclosures have been made in accordance with SFAS No. 69, “Disclosures About Oil and Gas Producing Activities (An Amendment of FASB Statements 19, 25, 33 and 39).” This data is a summary of the historical information which, prior to the divesture of substantially all of our remaining oil and gas assets in July 2005, had been provided as Supplemental Information in our 2004 Annual Report on Form 10-K. We no longer own sufficient oil and gas assets to remain subject to the SFAS No. 69 disclosure requirements, but have provided this summary information for the benefit of the user in understanding our historical oil and gas assets. Users of this information should be aware that the process of estimating quantities of proved, proved developed and proved undeveloped crude oil and natural gas reserves has in the past been very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir could change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to reserve estimates have in the past occurred from time to time. The significance of the subjective decisions required and variances in available data for various reservoirs makes these estimates generally less precise than other estimates presented in connection with financial statement disclosures.

Proved reserves represent estimated quantities of natural gas and crude oil that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. Estimates of proved reserves as of December 31, 2004, 2003 and 2002, were based on estimates made by independent petroleum reservoir engineers.


	Net Proved Reserve Summary — Unaudited

The following table sets forth our historical net proved reserves at December 31 for each of the three years in the period ended December 31, 2004, as estimated by our independent petroleum consultants.

During 2004 we revised downward our estimate of continuing proved reserves by a total of approximately 58 Bcfe or 12%. Approximately 69% of the total revision was attributable to the downward revision of the estimate of proved reserves in our South Texas fields. The downward revisions of the estimates were due to information received from production results and drilling activity that occurred during 2004. As a result of the decreases in proved reserves, a non-cash impairment charge of approximately $202.1 million was recorded for the year ended December 31, 2004, which was reclassified to discontinued operations. For the years ended December 31, 2003 and 2002, the impairment charge reclassified to discontinued operations was $2.9 million

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and $3.4 million, respectively. The following data relates to our oil and gas assets which were reclassified to held-for-sale in the corresponding balance sheets as of the dates indicated.


			Unaudited

(Bcfe)(1) equivalents(4):
	Net proved reserves at December 31, 2002			978
	Net proved reserves at December 31, 2003			821
	Net proved reserves at December 31, 2004			389
Net proved developed reserves:
	Natural gas (Bcf)(1)
		December 31, 2002		640
		December 31, 2003		545
		December 31, 2004		256
	Natural gas liquids and crude oil (MBbl)(2)(3)
		December 31, 2002		14,132
		December 31, 2003		8,690
		December 31, 2004		1,402
	Bcf(1) equivalents(4)
		December 31, 2002		725
		December 31, 2003		596
		December 31, 2004		264


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

(2)	Thousand barrels.

(3)	Includes crude oil, condensate and natural gas liquids.

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


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

The following information was developed utilizing procedures prescribed by SFAS No. 69 and based on natural gas and crude oil reserve and production volumes estimated by independent petroleum reservoir engineers. This information should not be relied upon in evaluating us or our performance, as substantially all of our remaining oil and gas assets were sold in July 2005. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the value of our historical oil and gas assets, which were classified as held-for-sale in our balance sheet as of the dates indicated. The discounted future net cash flows presented below were based on sales prices, cost rates and statutory income tax rates in existence as of the date of the projections. Estimates of natural gas and crude oil reserves may have been revised in future periods, development and production of the reserves may have occurred in periods other than those assumed, and actual prices realized and costs incurred may have varied significantly from those used. Income tax expense was computed using expected future tax rates and giving effect to tax deductions and credits available, under then existing current laws, and which relate to oil and gas producing activities. Management did not rely upon the following information in making investment and

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operating decisions. Such decisions were based upon a wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may have been anticipated.


		Unaudited
		(in millions)

December 31, 2004:
	Standardized measure of discounted future net cash flows relating to proved gas, natural gas liquids and crude oil reserves	$	653
December 31, 2003:
	Standardized measure of discounted future net cash flows relating to proved gas, natural gas liquids and crude oil reserves	$	1,341
December 31, 2002:
	Standardized measure of discounted future net cash flows relating to proved gas, natural gas liquids and crude oil reserves	$	1,259


	*Electric Generation and Marketing*

On January 15, 2004, we completed the sale of our 50% undivided interest in the 545-MW Lost Pines 1 Power Project to GenTex Power Corporation, an affiliate of the LCRA. Under the terms of the agreement, we received a cash payment of $148.6 million and recorded a pre-tax gain of $35.3 million. In addition, CES entered into a tolling agreement with LCRA providing CES the option to purchase 250 MW of electricity through December 31, 2004.

On July 28, 2005, we completed the sale of our 1,200-MW Saltend Energy Centre for approximately $862.9 million, $14.5 million of which related to estimated working capital adjustments. We recorded a pre-tax gain in 2005 of approximately $22.2 million, which is reflected in discontinued operations, as a result of the disposal. As described in Note 31, certain bondholders filed a lawsuit concerning the use of proceeds from the sale of Saltend.

On August 2, 2005, we completed the sale of our interest in the 156-MW Morris Energy Center in Illinois for $84.5 million. We had previously determined that the facility was impaired at June 30, 2005. We recorded an impairment charge of $106.2 million upon our commitment to a plan of divesture of the facility and based on the difference between the estimated sale price and the facility’s book value. This charge was reclassified to discontinued operations once the sale had closed. We also recorded a pre-tax loss on the sale of $0.4 million, which is reflected in discontinued operations.

On October 6, 2005, we completed the sale for $212.3 million of our 561-MW Ontelaunee Energy Center in Pennsylvania, which is reflected in the Consolidated Condensed Balance Sheets at December 31, 2004, as current and long-term assets and liabilities held for sale, in accordance with SFAS No. 144. We recorded an impairment charge of $137.1 million for the difference between the estimated sale price of the facility (less estimated selling costs) and its book value upon our commitment to a plan of divesture of the facility. This charge is reflected in discontinued operations as of December 31, 2005.

In connection with the sale of Ontelaunee, we entered into a ten-year LTSA with the buyer, under which we will provide major maintenance services and parts supply for the significant equipment of the facility, and a five-year O&M agreement under which we provide services related to the day-to-day operations and maintenance of the facility. Pricing of the LTSA and O&M service contracts is based on actual cost plus a margin and will result in estimated annual gross cash inflows of approximately $3.3 million and $2.7 million, respectively. We also entered into a six-month ESA under which CES provides power management, fuel

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management, risk management, and other services related to the Ontelaunee facility, with expected gross cash inflows of approximately $0.4 million annually. The ESA can be renewed after six months upon the mutual agreement of the parties. Under the terms of the ESA, CES functions in an agency role and has no delivery or price risk and has no economic risk or reward of ownership in the operations of the Ontelaunee facility. The gross cash flows associated with the LTSA, O&M and ESA agreements are insignificant to us and are considered indirect cash flows under EITF No. 03-13. Also, we have no significant continuing involvement in the financial and economic decision making of the disposed facility.


	*Other*

On July 31, 2003, we completed the sale of our specialty data center engineering business and recorded a pre-tax loss on the sale of $11.6 million.


	*Summary*

We made reclassifications to current and prior period financial statements to reflect the sale of these oil and gas, power plant and other assets and liabilities and to separately reclassify the operating results of the assets sold and the gain (loss) on sale of those assets from the operating results of continuing operations to discontinued operations.

Current assets held for sale as of December 31, 2005, were approximately $39.5 million, which represent the book value of the remaining oil and gas properties, which are being held in escrow until consents can be

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obtained. The table below present the assets and liabilities held for sale by segment as of December 31, 2004 (in thousands).


			December 31, 2004

			Electric		Oil and Gas
			Generation		Production
			and Marketing		and Marketing		Total

Assets
	Cash and cash equivalents		$	65,405	$	—	$	65,405
	Accounts receivable, net			54,095		—		54,095
	Inventories			7,756		—		7,756
	Prepaid expenses			14,840		—		14,840

		Total current assets held for sale		142,096		—		142,096

	Property, plant and equipment			1,632,131		606,520		2,238,651
	Other assets			20,826		924		21,750

		Total long-term assets held for sale	$	1,652,957	$	607,444	$	2,260,401

Liabilities
	Accounts payable		$	34,070	$	—	$	34,070
	Current derivative liabilities			8,935		—		8,935
	Other current liabilities			42,187		1,266		43,453

		Total current liabilities held for sale		85,192		1,266		86,458

	Deferred income taxes, net of current portion			135,985		—		135,985
	Long-term derivative liabilities			10,367		—		10,367
	Other liabilities			21,562		8,384		29,946

		Total long-term liabilities held for sale	$	167,914	$	8,384	$	176,298

The tables below present significant components of our income from discontinued operations for the years ended December 31, 2005, 2004 and 2003, respectively (in thousands):


	2005

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

Total revenue	$	369,796		$	25,129	$	—	$	394,925

Gain on disposal before taxes	$	21,537		$	336,894	$	—	$	358,431
Operating income (loss) from discontinued operations before taxes		(318,499	)		33,560		—		(284,939	)

Income from discontinued operations before taxes	$	(296,962	)	$	370,454	$		$	73,492
Income tax provision (benefit)	$	(9,027	)	$	140,773	$		$	131,746

(Loss) from discontinued operations, net of tax	$	(287,935	)	$	229,681	$		$	(58,254	)

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	2004

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

Total revenue	$	525,177	$	91,421		$	$	616,598

Gain on disposal before taxes	$	35,327	$	208,172		$	$	243,499
Operating income (loss) from discontinued operations before taxes		41,607		(99,024	)			(57,417	)

Income from discontinued operations before taxes	$	76,934	$	109,148		$	$	186,082
Income tax provision (benefit)	$	14,066	$	(5,206	)	$	$	8,860

Income from discontinued operations, net of tax	$	62,868	$	114,354		$	$	177,222


	2003

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

Total revenue	$	466,074		$	106,412		$	3,748		$	576,234

Loss on disposal before taxes	$	—		$	(235	)	$	(11,571	)	$	(11,806	)
Operating income (loss) from discontinued operations before taxes		(16,738	)		170,326			(6,918	)		146,670

Income (loss) from discontinued operations before taxes	$	(16,738	)	$	170,091		$	(18,489	)	$	134,864
Income tax provision (benefit)		1,038			26,501			(7,026	)		20,513

Income from discontinued operations, net of tax	$	(17,776	)	$	143,590		$	(11,463	)	$	114,351

We allocate interest to discontinued operations in accordance with EITF Issue No. 87-24, “Allocation of Interest to Discontinued Operations.” We include interest expense on debt which is required to be repaid as a result of a disposal transaction in discontinued operations. Additionally, other interest expense that cannot be attributed to our other operations is allocated based on the ratio of net assets to be sold less debt that is required to be paid as a result of the disposal transaction to the sum of our total net assets plus our consolidated debt, excluding (a) debt of the discontinued operation that will be assumed by the buyer,

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(b) debt that is required to be paid as a result of the disposal transaction and (c) debt that can be directly attributed to our other operations.


			(in thousands)
Interest Expense Allocation			2005		2004		2003

Electric generation and marketing
	Saltend Energy Centre		$	45,080	$	14,613	$	7,203
	Ontelaunee Energy Center			12,264		13,304		11,724
	Morris Energy Center and Lost Pines			3,662		7,295		8,563

		Total	$	61,006	$	35,212	$	27,490

Oil and gas production and marketing
	Canadian and Rockies		$	—	$	17,893	$	19,797
	Remaining oil and gas assets			10,295		8,518		3,426

		Total	$	10,295	$	26,411	$	23,223


14.	Debt

On December 20 and 21, 2005, we and many of our wholly owned direct and indirect subsidiaries filed for bankruptcy protection as discussed in Note 3.

In accordance with SOP 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code,” we continue to accrue and recognize interest expense on debt that is considered to be fully secured or of Non-Debtor entities.

Throughout Notes 14 through 24, amounts outstanding represent the carrying value of the debt instrument, which is the face value of the debt net of any unamortized discount or premium.

Due to the bankruptcy filings, which generally constituted events of default under the majority of our debt instruments, and our failure to comply with certain other financial covenants thereunder as a result of such filings, we are in technical default on most of our pre-petition debt obligations. Except as otherwise may be determined by the Bankruptcy Courts, the automatic stay protection afforded by the Chapter 11 and CCAA proceedings prevents any action from being taken against any of the Calpine Debtors with regard to any of the defaults under the pre-petition debt obligations. However, as a result of being in violation of most of our pre-petition debt obligations, a significant portion of our outstanding debt maturities has been reclassified

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to current liabilities. The following table represents the maturities of our pre-petition debt obligations in accordance with SFAS No. 78 “Classification of Obligations that are Callable by the Creditor.”


	(in thousands)
	December 31, 2005

	Current		Long-Term		Total

Notes payable and other borrowings	$	188,221	$	558,353	$	746,574
Preferred interests		9,479		583,417		592,896
Capital lease obligations		191,497		95,260		286,757
CCFC financing		784,513		—		784,513
CalGen financing		2,437,982		—		2,437,982
Construction/project financing		1,160,593		1,200,432		2,361,025
DIP Facility		—		25,000		25,000
Senior notes and term loans		641,652		—		641,652

	$	5,413,937	$	2,462,462	$	7,876,399

The table below represents the contractual maturities of our pre-petition debt obligations if we had not made the bankruptcy filings and had not otherwise triggered any events of default thereunder.


	(in thousands)						(in thousands)
	December 31, 2005						December 31, 2004

	Current		Long-Term		Total		Current		Long-Term		Total

Notes payable and other borrowings	$	188,221	$	558,353	$	746,574	$	200,076	$	769,490	$	969,566
Notes payable to Calpine Capital Trusts		—		—		—		—		517,500		517,500
Preferred interests		9,479		583,417		592,896		8,641		497,896		506,537
Capital lease obligations		8,133		278,624		286,757		5,490		283,429		288,919
CCFC financing		3,208		781,305		784,513		3,208		783,542		786,750
CalGen financing		—		2,437,982		2,437,982		—		2,395,332		2,395,332
Construction/project financing		79,594		2,281,431		2,361,025		93,393		1,905,658		1,999,051
DIP Facility		—		25,000		25,000		—		—		—
Senior notes and term loans		—		641,652		641,652		718,449		8,532,664		9,251,113
Convertible Senior Notes		—		—		—		—		1,255,298		1,255,298

	$	288,635	$	7,587,764	$	7,876,399	$	1,029,257	$	16,940,809	$	17,970,066

Annual Debt Maturities — Certain notes payable, preferred interests, capital lease obligations, the CCFC and CalGen financings, construction/project financings (excluding Aries) and the First Priority Notes are currently considered not subject to compromise under the bankruptcy cases either because they are considered to be fully secured or because the entity that issued the debt has not filed for bankruptcy protection. The

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contractual annual principal repayments or maturities (assuming no events of default) of these debt instruments, as of December 31, 2005, are as follows (in thousands):


2006			$	288,635
2007				335,037
2008				242,242
2009				1,438,381
2010				1,264,277
Thereafter				4,365,852

	Total debt			7,934,424
(Discount)/ Premium				(58,025	)

		Total	$	7,876,399

Debt Extinguishments — Senior Notes extinguished through open market repurchases and unscheduled payments during 2005 and 2004 totaled $917.1 million and $1,668.3 million, respectively, in aggregate outstanding principal amount for a repurchase price of $685.5 million and $1,394.0 million, respectively, plus accrued interest. In 2005, we recorded a pre-tax gain on these transactions in the amount of $220.1 million, which was $231.6 million, net of write-offs of $9.3 million of unamortized deferred financing costs and $2.2 million of unamortized premiums or discounts and legal costs. In 2004 we recorded a pre-tax gain on these transactions in the amount of $254.8 million, which was $274.4 million, net of write-offs of $19.1 million of unamortized deferred financing costs and $0.5 million of unamortized premiums or discounts.


	(in millions)
	2005				2004

	Principal		Amount		Principal		Amount
Debt Security	Amount		Paid		Amount		Paid

2006 Convertible Notes	$	—	$	—	$	658.7	$	657.7
2023 Convertible Notes		—		—		266.2		177.0
9⁵/8 % First Priority Senior Notes Due 2014		138.9		138.9		—		—
8¹/4 % Senior Notes Due 2005		4.0		4.0		38.9		34.9
10¹/2 % Senior Notes Due 2006		13.5		12.4		13.9		12.4
7⁵/8 % Senior Notes Due 2006		9.4		8.7		103.1		96.5
8³/4 % Senior Notes Due 2007		5.0		3.2		30.8		24.4
7⁷/8 % Senior Notes Due 2008		53.5		39.6		78.4		56.5
8¹/2 % Senior Notes Due 2008		159.8		102.6		344.3		249.4
8³/8 % Senior Notes Due 2008		—		—		6.1		4.0
7³/4 % Senior Notes Due 2009		41.0		24.8		11.0		8.1
8⁵/8 % Senior Notes Due 2010		86.2		59.1		—		—
8¹/2 % Senior Notes Due 2011		405.8		292.2		116.9		73.1

	$	917.1	$	685.5	$	1,668.3	$	1,394.0

See Notes 15 — 24 below for a description of each of our debt obligations.

Debt, Lease and Indenture Covenant Compliance — Our DIP Facility contains financial and other restrictive covenants that limit or prohibit our ability to incur indebtedness, make prepayments on or purchase indebtedness in whole or in part, pay dividends, make investments, lease properties, engage in transactions

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with affiliates, create liens, consolidate or merge with another entity or allow one of our subsidiaries to do so, sell assets, and acquire facilities or other businesses. We are currently in compliance, or have received waivers of any non-compliance, with all of such financial and other restrictive covenants. Any failure to comply could give the lenders the right to accelerate the maturity of all debt outstanding thereunder if the default was not cured or waived. In addition, certain instruments related to our non-debtor entities contain financial and other restrictive covenants which, if violated, would permit the holders of such debt to elect to accelerate the maturity of their debt.

In addition, our debt instruments, including our senior notes indentures and our credit facilities, including our project financings, contain financial and other restrictive covenants and events of default that limit or prohibit our ability to incur indebtedness, make prepayments on or purchase indebtedness in whole or in part, pay dividends, make investments, lease properties, engage in transactions with affiliates, create liens, consolidate or merge with another entity or allow one of our subsidiaries to do so, sell assets, and acquire facilities or other businesses. In particular, our bankruptcy filings constituted an event of default or otherwise triggered repayment obligations under the instruments governing substantially all of our outstanding indebtedness, other than indebtedness of our subsidiaries or affiliates that are not Calpine Debtors. As a result of the events of default, the debt outstanding under the affected debt instruments generally became automatically and immediately due and payable. We believe that any efforts to enforce such payment obligations are stayed as a result of the bankruptcy filings and subject to our bankruptcy cases.

If, in addition to the events of default caused by our bankruptcy filings, we were to breach the financial or other restrictive covenants under certain of our debt instruments, it could give holders of debt under the relevant instruments the right to accelerate the maturity of all debt outstanding thereunder (if such debt were not already accelerated) if the default were not cured or waived. Currently, except as described further below, we believe that we are in compliance with our obligations under the various indentures and debt and lease instruments of Non-Debtor entities, or that any non-compliance thereunder has been cured or waived.

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


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

	•	We sold our remaining oil and gas assets on July 7, 2005. The gas component of such sale constituted a sale of “designated assets” under certain of our indentures, which restrict the use of the proceeds of sales of designated assets. In accordance with the indentures, we used $138.9 million of the net proceeds of $902.8 million from the sale to repurchase First Priority Notes from holders pursuant to an offer to purchase. We used approximately $308.2 million, plus accrued interest, of the net proceeds to purchase natural gas assets in storage, and the remaining $406.9 million remains in a restricted designated asset sale proceeds account pursuant to the indentures governing the First and Second Priority Notes. As further described in Note 31, the Delaware Chancery Court found in November 2005 that our use of the approximately $308.2 million of proceeds to make purchases of gas assets in storage was in violation of such indentures and ordered that amount to be returned to a designated asset sale proceeds account. The Delaware Supreme Court affirmed the Delaware Chancery Court’s decision in December 2005. To date, we have not been able to refund the proceeds that were used to purchase gas assets to such account.

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In addition, we own a 50% interest in Acadia Power Partners, LLC through our wholly owned subsidiary, Calpine Acadia Holdings, LLC, which is a U.S. Debtor. The remaining 50% is owned by a subsidiary of Cleco, Acadia Power Holdings, LLC. Calpine Acadia and Acadia Power Holdings are subject to a limited liability company agreement which, among other things, governs their relationship with regard to ownership of Acadia Power Partners. The limited liability company agreement provides that bankruptcy of Calpine Acadia is an event of default under such agreement and sets forth certain exclusive remedies in the event that an event of default occurs, including winding up Acadia Power Partners or permitting the non-defaulting party to buy out the defaulting party’s interest at market value less 20%. However, we believe that any efforts to enforce such remedies would be stayed as a result of the bankruptcy filings and subject to our bankruptcy cases.

In connection with the sale/leaseback transaction at the Agnews power plant, we are technically not in compliance with the insurance requirements set forth in the financing documents. We have obtained a partial waiver from the financing parties regarding the insurance requirements and are currently seeking to obtain a complete waiver. In addition, Agnews has failed to deliver to the financing parties certain financial reports and operational reports as required under the financing documents. Such failure, may, with the passage of time and the giving of notice, constitute an event of default under the financing documents. We expect that Agnews will deliver such information prior to an event of default occurring.


	*Non-Debtor Entities*

Blue Spruce Energy Center. In connection with the project financing transaction by Blue Spruce, an event of default existed under the project credit agreement as of December 31, 2005, due to cross default provisions related to the bankruptcy filing by CES. We are in the process of negotiating an amendment and waiver under the project credit agreement from the lender. Nonetheless, although the debt has not been accelerated, we have determined that we are required to classify the debt as current until such waiver is executed.

CCFC. In connection with the note and term loan financing at CCFC, CCFC has entered into waiver agreements under the indenture governing its notes and the credit agreement governing its term loans. The waiver agreements provide for the waiver of certain defaults that occurred following our bankruptcy filings as a result of the failure of CES to make certain payments to CCFC under a PPA with CCFC. The waiver agreements were executed upon the receipt by CCFC of the consent of a majority of the holders of CCFC’s notes and the agreement of a majority of the CCFC term loan lenders pursuant to a consent solicitation and request for amendment initiated on February 22, 2006. CCFC made a consent payment of $1.89783 per each $1,000 principal amount of notes or term loans held by consenting noteholders or term loan lenders, as applicable. On April 11, 2006, CCFC notified its noteholders and term loan lenders that, as of April 7, 2006, a default had occurred under the indenture and credit agreement due to the failure of CES to make a payment with respect to a hedging transaction under the PPA with CCFC. If such default is not cured, or the PPA is not replaced with a substantially similar agreement, within 60 days following the occurrence of the default, such default will become an “event of default” under the note indenture and the term loan credit agreement. In addition, CCFC has not yet provided certain financial and other information required to be delivered to its noteholders and term loan lenders. Such failure may, with the passage of time and the giving of notice, constitute an event of default. We expect that CCFC will deliver such information prior to an event of default occurring. As a result of such failure, the CCFC notes and term loans have been classified as current.

CCFCP. In connection with the redeemable preferred shares issued by CCFCP, CCFCP has entered into an agreement with its preferred members holding a majority of the CCFCP redeemable preferred shares amending its LLC operating agreement. The amendment agreement, among other things, acknowledges that the waiver agreements under the CCFC indenture and credit agreement satisfied the provisions of a standstill agreement entered into on February 24, 2006, between CCFCP and its preferred members pursuant to which

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the preferred members had agreed not to declare a “Voting Rights Trigger Event,” as defined in CCFCP’s LLC operating agreement, to have occurred or to seek to appoint replacement directors to the board of CCFCP, provided that certain conditions were met, including obtaining such waiver agreements. Accordingly, the terms of the standstill agreement were satisfied. A new Voting Rights Trigger Event may occur if the defaults under the CCFC indenture and credit agreement described above become events of default. In addition, CCFCP has not yet provided certain financial and other information required to be delivered to its preferred members. Such failure may, with the passage of time and the giving of notice, constitute a Voting Rights Trigger Event. We expect that CCFCP will deliver such information prior to a Voting Rights Trigger Event occurring. Upon the occurrence of a CCFCP Voting Rights Trigger Event, the holders of the CCFCP redeemable preferred shares may, at their option, remove and replace the existing CCFCP directors unless and until the CCFCP Voting Rights Trigger Event has been waived by the holders of a majority of the CCFCP redeemable preferred shares or until the consequences of the CCFCP Voting Rights Trigger Event have been fully cured.

Fox Energy Center. In connection with the sale/leaseback transaction at the Fox power plant, the bankruptcy filings by certain affiliates of Fox on December 20, 2005, constituted an event of default under the lease and certain other agreements relating to the sale/leaseback transaction. In addition, we failed to pay a portion of the rent payment due on March 30, 2006, which payment default is also an event of default under the lease and certain other agreements relating to the sale/leaseback transaction. We have entered into forbearance agreements with the Fox owner lessor and owner participant, pursuant to which they have agreed not to exercise certain rights and remedies under the lease and other agreements relating to such events of default. The forbearance agreements have been extended for seven-day periods while we seek to resolve the defaults. We are considering all options with respect to the Fox power plant, which is one of the designated projects for which further funding has been limited in connection with our bankruptcy cases, including a possible sale of our interest in the facility. As a result of the outstanding events of default, our obligations with respect to the Fox sale/leaseback transaction are classified as current.

Freeport Energy Center and Mankato Energy Center. In connection with the project financing transaction by Freeport and Mankato, an event of default existed under the project credit agreement as of December 31, 2005, due to cross default provisions related to the bankruptcy filings by certain Calpine affiliates. Subsequent to December 31, 2005, the lenders under the project credit agreement provided a waiver of the event of default.

Metcalf Energy Center. In connection with the financing transactions by Metcalf, certain events of default occurred under the Metcalf credit agreement as a result of our bankruptcy filings and related failures to fulfill certain payment obligations under a PPA between CES and Metcalf. Metcalf and the lenders under the credit agreement entered into a Debt Waiver Agreement, dated as of April 18, 2006, pursuant to which the lenders have agreed to waive such defaults. Such events of default also triggered a “Voting Rights Trigger Event” under Metcalf’s LLC agreement, which contains the terms of Metcalf’s redeemable preferred shares. Upon the occurrence of a Metcalf Voting Rights Trigger Event, the holders of the Metcalf redeemable preferred shares may, at their option, remove and replace the existing Metcalf directors unless and until the Metcalf Voting Rights Trigger Event has been waived by the holders of a majority of the Metcalf redeemable preferred shares or until the consequences of the Metcalf Voting Rights Trigger Event have been fully cured. Metcalf has entered into a waiver agreement with the requisite lenders under the credit agreement waiving the foregoing events of default in exchange for a fee of 20 basis points (0.20%) of the total outstanding amounts of the loans and Metcalf’s commitment to assert claims in the bankruptcy cases against Calpine, CES, and CCMC. Metcalf is currently seeking to resolve any issues with the holders of its redeemable preferred shares with respect to the Voting Rights Trigger Event through waivers or other means.

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Newark Power Plant and Parlin Power Plant. In connection with our financing transaction at the Newark and Parlin power plants, both of which are designated projects for which further funding has been limited in connection with our bankruptcy cases, we have been unable to fully comply with respect to certain covenants under the credit agreement relating to the financing due to our bankruptcy filings and the failure to fulfill requirements relating to the payment of certain obligations, and to otherwise comply with terms of certain of the Newark and Parlin project agreements. We are in the process of seeking a cooperation agreement with the lender including at least a short term waiver or forbearance with respect to any potential defaults that may have occurred with respect to these projects.

Pasadena Power Plant. In connection with our Pasadena lease financing transaction, the bankruptcy filings by us and certain of our subsidiaries on December 20, 2005, constituted an event of default under Pasadena’s facility lease and certain other agreements relating to the transaction, which resulted in events of default under the indenture governing certain notes issued by the Pasadena owner lessor. We have entered into a forbearance agreement with the holders of a majority of the outstanding notes pursuant to which the noteholders have agreed to forebear from taking any action with respect to such events of default, which forbearance agreement has been extend from month to month until May 1, 2006. We are currently seeking a further extension of the forbearance agreement while we seek to resolve the defaults through waivers or other means. As a result of such defaults our obligations with respect to this lease financing have been classified as current.

Riverside Energy Center and Rocky Mountain Energy Center. In connection with the project financing transactions by Riverside and Rocky Mountain, an event of default occurred under the project credit agreements as of December 31, 2005, due to cross default provisions related to the bankruptcy filings by certain Calpine affiliates. Subsequent to December 31, 2005, the lenders under the project credit agreements provided an omnibus amendment and waiver of such events of default.


15.	Notes Payable and Other Borrowings

The components of notes payable and other borrowings and related issued letters of credit are (in thousands):


		Borrowings Outstanding				Letters of Credit Issued
		December 31,				December 31,

		2005		2004		2005		2004

Corporate Cash Collateralized Letter of Credit Facility		$	—	$	—	$	140,270	$	233,271
Calpine Northbrook Energy Marketing, LLC note			29,442		52,294		—		—
Calpine Commercial Trust			—		34,255		—		—
Power Contract Financing III, LLC			56,316		51,592		—		—
Power Contract Financing, L.L.C.			540,269		688,366		—		—
Gilroy note payable(1)			117,719		125,478		—		—
Other			2,828		17,581		4,591		6,158

	Total notes payable and other borrowings	$	746,574	$	969,566	$	144,861	$	239,429
	Less: notes payable and other borrowings, current portion		188,221		200,076		—		—

Notes payable and other borrowings, net of current portion		$	558,353	$	769,490	$	144,861	$	239,429


(1)	See Note 11 for information regarding the Gilroy note payable.

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	*Notes Payable and Other Borrowings*

Corporate Cash Collateralized Letter of Credit Facility — On September 30, 2004, we established a $255 million Cash Collateralized Letter of Credit Facility with Bayerische Landesbank, to which all letters of credit issued under our previously-existing $300 million working capital revolver and $200 million cash collateralized letter of credit facility were transitioned. No new letters of credit can be issued under this facility subsequent to the Petition Date. Bayerische Landesbank has reimbursed beneficiaries for Letter of Credit draws made on certain letters of credit, which has subsequently reduced our cash collateral.

Calpine Northbrook Energy Marketing, LLC Note — On September 23, 2003, CNEM, a wholly owned stand-alone subsidiary of CNEM Holdings, LLC, which is a wholly owned indirect subsidiary of CES, amended and restated a May 14, 2003, credit agreement with affiliates of Deutsche Bank providing for an $82.8 million loan facility secured by an existing PPA with the BPA. Under the 100-MW fixed-price PPA, CNEM delivers baseload power to BPA through December 31, 2006. As a part of the secured transaction, CNEM entered into a PPA with a third party to purchase a like amount of power based on spot prices and a fixed-price swap agreement with an affiliate of Deutsche Bank, which together effectively locked in the price of the purchased power. The terms of both PPAs are through December 31, 2006. To complete the transactions, CNEM then entered into the amended and restated credit agreement and borrowed $82.8 million secured by the BPA contract, the spot market PPA, the fixed price swap agreement and the equity interests in CNEM. The spread between the price for power under the BPA contract and the price for power under the fixed price swap agreement provides the cash flow to pay CNEM’s debt and other expenses. Proceeds from the borrowing were used by CNEM primarily to purchase the PPA with BPA from CES, which then used the proceeds for general corporate purposes as well as to pay fees and expenses associated with this transaction. CNEM will make quarterly principal and interest payments on the loan, which matures on December 31, 2006. The effective interest rate, after amortization of deferred financing charges, was 12.3% and 12.2% per annum at December 31, 2005 and 2004, respectively.

Pursuant to the applicable transaction agreements, each of CNEM and its parent, CNEM Holdings, LLC, have been established as an entity with its existence separate from us and our subsidiaries. In accordance with FIN 46-R, we consolidate these entities. The above-mentioned PPA with BPA, which was acquired by CNEM from CES, the spot market PPA with a third party and the swap agreement, which were entered into by CNEM and the $82.8 million loan, are assets and liabilities of CNEM, separate from our assets and liabilities and those of our other subsidiaries. The only significant asset of CNEM Holdings, LLC is its equity interest in CNEM. CNEM is a Non-Debtor entity. Consequently, the loan is not deemed to be subject to compromise.

Calpine Commercial Trust — In May 2004, in connection with the King City transaction, Calpine Canada Power Limited, a wholly owned subsidiary of ours, entered into a loan with Calpine Commercial Trust. Interest on the loan accrues at 13% per annum, and the loan has principal and interest payments scheduled through maturity in December 2010. The effective interest rate of this loan is 17% for 2005 and 2004. We deconsolidated Calpine Canada Power Limited in December 2005 as described in Note 10 and this note payable is now reflected on our balance sheet as a related party Note Payable subject to compromise.

Power Contract Financing III, LLC — On June 2, 2004, our wholly owned subsidiary PCF III issued $85.0 million of notes collateralized by PCF III’s ownership interest in PCF. PCF III owns all of the equity interests in PCF, which holds the PSA with CDWR described below, and maintains a debt reserve fund which had a balance of approximately $94.4 million at December 31, 2005 and 2004. PCF III received cash proceeds of approximately $49.8 million from the issuance of the notes, which was distributed to us. At December 31, 2005 and 2004, the effective interest rate on the PCF III notes was 12.0% per annum. PCF III is a Non-Debtor entity. Consequently, the PCF III notes are not deemed to be subject to compromise.

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Power Contract Financing, L.L.C. — On June 13, 2003, PCF, an indirect wholly owned subsidiary of ours, completed an offering of $339.9 million of 5.2% Senior Secured Notes Due 2006 and $462.3 million of 6.256% Senior Secured Notes Due 2010. The two tranches of PCF’s Senior Secured Notes are secured by fixed cash flows from a fixed-priced, long-term power sales agreement with CDWR, pursuant to which PCF sells electricity to CDWR, and a fixed-priced, long-term PPA with a third party, pursuant to which PCF purchases from the third party the electricity necessary to fulfill its obligations to CDWR under the power sales agreement. The spread between the price for power under the CDWR power sales agreement and the price for power under the third party PPA provides the cash flow to pay debt service on the Senior Secured Notes and PCF’s other expenses. The Senior Secured Notes are non-recourse to us and our other subsidiaries. At December 31, 2005, the two tranches of Senior Secured Notes were rated Baa2 by Moody’s and BBB (with a negative outlook) by S&P. During the years 2005 and 2004, $148.1 million and $113.9 million of the 5.2% Senior Secured Notes was repaid, based on the Senior Secured Notes’ repayment schedules. The effective interest rates on the 5.2% Senior Secured Notes and 6.256% Senior Secured Notes, after amortization of deferred financing costs, was 8.4% and 9.5% per annum, respectively, at December 31, 2005, and 8.4% and 9.4% per annum, respectively, at December 31, 2004.

Pursuant to the applicable transaction agreements, PCF has been established as an entity with its existence separate from us and other subsidiaries of ours. In accordance with FIN 46-R, we consolidate this entity. See Note 2 for more information on FIN 46-R. The power sales agreement with CDWR and the PPA with the third party, which were acquired by PCF from CES, and the Senior Secured Notes are assets and liabilities of PCF, separate from our assets and liabilities and those of other subsidiaries of ours. The proceeds of the Senior Secured Notes were primarily used by PCF to purchase from CES the power sales agreement with CDWR and PPA with the third party. PCF is a non-debtor entity. Consequently, the Senior Secured Notes are not deemed to be subject to compromise.


16.	Notes Payable to Calpine Capital Trusts

In 1999 and 2000, we, through our wholly owned subsidiaries, Calpine Capital Trust, Calpine Capital Trust II, and Calpine Capital Trust III, statutory business trusts created under Delaware law, completed offerings of HIGH TIDES at a value of $50.00 per HIGH TIDES. A summary of these offerings follows in the table below ($ in thousands):


										Conversion
										Ratio —
										Number of
					Stated					Common		First		Initial
					Interest			Offering		Shares per		Redemption		Redemption
	Issue Date		Shares		Rate			Amount		1 High Tide		Date		Price

HIGH TIDES I		October 1999		5,520,000		5.75	%	$	276,000		3.4620		November 5, 2002		101.440	%
HIGH TIDES II		January and February 2000		7,200,000		5.50	%		360,000		1.9524		February 5, 2003		101.375	%
HIGH TIDES III		August 2000		10,350,000		5.00	%		517,500		1.1510		August 5, 2003		101.250	%

				23,070,000				$	1,153,500

The net proceeds from each of the offerings were used by the Calpine Capital Trusts to purchase convertible debentures of ours, which represented substantially all of the respective Trusts’ assets. We effectively guaranteed all of the respective Calpine Capital Trusts’ obligations under the HIGH TIDES. The HIGH TIDES had liquidation values of $50.00 per HIGH TIDES, or $1.2 billion in total for all of the issuances.

During 2004 we exchanged 24.3 million shares of Calpine common stock in privately negotiated transactions for approximately $115.0 million par value of HIGH TIDES I and HIGH TIDES II. Also, in

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2004, we repurchased, in a privately negotiated transaction, par value of $115.0 million HIGH TIDES III for cash of $111.6 million. Due to the deconsolidation of the Trusts upon the adoption of FIN 46 as of December 31, 2003, the terms of the underlying debentures and the requirements of SFAS 140, the repurchased HIGH TIDES I, II and III preferred securities could not be offset against the convertible subordinated debentures and were accounted for as available-for-sale securities and recorded in Other assets at fair market value at December 31, 2004, with the difference from their repurchase price recorded in OCI.

On October 20, 2004, we repaid the $276.0 million and $360.0 million convertible debentures held by Trust I and Trust II, respectively. The proceeds were used by Trust I to redeem its outstanding 5³/4% HIGH TIDES I and by Trust II to redeem its outstanding 5¹/2 % HIGH TIDES II. The redemption price paid per each $50 principal amount of such HIGH TIDES I and HIGH TIDES II was $50 plus accrued and unpaid distributions to the redemption date. The redemption included the $115.0 million par value of HIGH TIDES I and II previously purchased and held by us and resulted in a net loss of $7.8 million, comprised of a gain of $6.1 million related to the HIGH TIDES I and II available-for-sale securities previously purchased in privately negotiated transactions, against a write-off of $13.9 million of unamortized deferred financing costs.

On July 13, 2005, we repaid the $517.5 million convertible debenture held by Trust III, which then applied the proceeds to redeem the HIGH TIDES III. The redemption price paid per each $50 principal amount of such HIGH TIDES III was $50 plus accrued and unpaid distributions to the redemption date. The redemption included the $115 million of HIGH TIDES III previously purchased and held by us and resulted in a net loss of $8.5 million, comprised of a gain of $4.4 million related to the HIGH TIDES III available-for-sale securities previously purchased in privately negotiated transactions, against a write-off of $12.9 million of unamortized deferred financing costs.


17.	Preferred Interests

The components of Preferred Interests are (in thousands:)


		Borrowings Outstanding
		December 31,

		2005		2004

Preferred interest in Auburndale Power Plant		$	78,076	$	79,135
Preferred interest in Gilroy Energy Center, LLC			59,820		67,402
Preferred interest in Calpine Jersey I and II			—		360,000
Preferred interest in Metcalf Energy Center, LLC			155,000		—
Preferred interest in CCFC Preferred Holdings, LLC			300,000		—

	Total preferred interests	$	592,896	$	506,537
	Less: preferred interests, current portion		9,479		8,641

Preferred interests, net of current portion, and term loan		$	583,417	$	497,896

In May 2003, FASB issued SFAS No. 150, which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 applies specifically to a number of financial instruments that companies have historically presented within their financial statements either as equity or between the liabilities section and the equity section, rather than as liabilities. SFAS No. 150 was effective for financial instruments entered into or modified after May 31, 2003, and otherwise was effective at the beginning of the first interim period beginning after June 15, 2003. We adopted SFAS No. 150 on July 1, 2003. For those instruments required to be recorded as debt, SFAS No. 150 does not permit reclassification of prior period amounts to conform to the current period presentation. The adoption of SFAS No. 150 and related balance sheet reclassifications did not have an effect

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on net income or total stockholders’ equity (deficit) but have impacted our debt-to-equity and debt-to-capitalization ratios.

Auburndale Power Plant — On September 3, 2003, we announced that our subsidiary, Auburndale Holdings, LLC had completed the sale of a 70% preferred interest in our Auburndale power plant to Pomifer Power Funding, LLC, a subsidiary of ArcLight Energy Partners Fund I, L.P., for $88.0 million. This preferred interest meets the criteria of a mandatorily redeemable financial instrument and has been classified as debt under the guidance of SFAS No. 150, due to certain preferential distributions to Pomifer Power Fundings LLC. The preferential distributions are to be paid quarterly beginning in November 2003 and total approximately $204.7 million over an 11-year period. The preferred interest holders’ recourse is limited to the net assets of the entity and distribution terms are defined in the amended and restated LLC operating agreement. We have not guaranteed the payment of these preferential distributions. We hold the remaining interest in the facility and provide it with O&M services. Although we cannot readily determine the potential cost to repurchase the interest in Auburndale Holdings, LLC, the carrying value at December 31, 2005 and 2004, of the preferred interest was $78.1 million and $79.1 million, respectively. The effective interest rate on the preferred interest, after amortization of deferred financing charges, was 16.6% and 17.1% per annum at December 31, 2005 and 2004, respectively. Auburndale is a Non-Debtor entity. Consequently, these debt instruments are not deemed to be subject to compromise.

Gilroy Energy Center, LLC — On September 30, 2003, GEC, a wholly owned subsidiary of our subsidiary GEC Holdings, LLC, completed an offering of $301.7 million of 4% Senior Secured Notes Due 2011. See Note 21 for more information on this secured financing in connection with which GEC acquired a long-term power sales agreement with CDWR by means of a series of capital contributions by CES and certain of its affiliates. In connection with the issuance of the secured notes, we received funding on a third party preferred equity investment in GEC Holdings, LLC totaling $74.0 million. This preferred interest meets the criteria of a mandatorily redeemable financial instrument and has been classified as debt under the guidance of SFAS No. 150, due to certain preferential distributions to the third party. The preferential distributions are due semi-annually beginning in March 2004 through September 2011 and total approximately $113.3 million over the eight-year period. Although we cannot readily determine the potential cost to repurchase the interest in GEC Holdings, LLC, the carrying value at December 31, 2005 and 2004, of the preferred interest was $59.8 million and $67.4 million, respectively. The effective interest rate on the preferred interest, after amortization of deferred financing charges, was 14.6% and 12.2% per annum at December 31, 2005 and 2004, respectively. GEC is a Non-Debtor entity. Consequently, these instruments are not deemed to be subject to compromise.

Pursuant to the applicable transaction agreements, GEC has been established as an entity with its existence separate from us and other subsidiaries of ours. We consolidate this entity. A long-term PPA between CES and the CDWR has been acquired by GEC by means of a series of capital contributions by CES and certain of its affiliates and is an asset of GEC, and the secured notes and preferred interest are liabilities of GEC, separate from the assets and liabilities of Calpine and our other subsidiaries. In addition to the PPA and eleven peaker power plants owned directly or indirectly by GEC, GEC’s assets include cash and a 100% equity interest in each of Creed and Goose Haven, each of which is a wholly owned subsidiary of GEC and a guarantor of the 4% Senior Secured Notes Due 2011 issued by GEC. Each of Creed and Goose Haven has been established as an entity with its existence separate from us and other subsidiaries of ours. Creed and Goose Haven each have assets consisting of various power plants and other assets. GEC, Creed and Goose Haven are Non-Debtor entities. Consequently, the 4% Senior Secured Notes Due 2011 and the preferred interest are not deemed to be subject to compromise.

Calpine Jersey I and II — On October 26, 2004, our indirect, wholly owned subsidiary Calpine Jersey I completed a $360 million offering of two-year redeemable preferred shares priced at LIBOR plus 700 basis

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

points. On January 31, 2005, our indirect, wholly owned subsidiary Calpine Jersey II completed a $260 million offering of redeemable preferred shares due July 30, 2005, priced at LIBOR plus 850 basis points.

The redeemable preferred shares issued by Calpine Jersey I and Calpine Jersey II were repurchased on July 28, 2005, when we completed the sale of Saltend. Of the total gross proceeds of $862.9 million from the sale of Saltend, approximately $647.1 million was used to redeem the $360.0 million two-year redeemable preferred shares issued by Calpine Jersey I, and the $260.0 million redeemable preferred shares due June 20, 2005, issued by Calpine Jersey II, including interest and termination fees of $16.3 million and $10.8 million, respectively. As discussed in Note 31, certain bondholders initiated a lawsuit concerning the use of the remaining proceeds from the sale of Saltend.

Metcalf Energy Center, LLC — On June 20, 2005, our indirect subsidiary Metcalf, completed a $155.0 million offering of 5.5-year redeemable preferred shares priced at LIBOR plus 900 basis points. Concurrent with the closing, Metcalf entered into a five-year, $100.0 million senior term loan at LIBOR plus 300 basis points. Proceeds from the senior term loan were used to refinance all outstanding indebtedness under Metcalf’s existing $100.0 million non-recourse construction credit facility. The effective interest rate on the redeemable preferred shares, after amortization of deferred financing charges, was 12.2% per annum at December 31, 2005. The redeemable preferred shares are accounted for as long-term debt in accordance with SFAS No. 150. Metcalf is a Non-Debtor entity. Consequently, these instruments are not deemed to be subject to compromise.

CCFC Preferred Holdings, LLC — On August 12, 2005, our subsidiary CCFCP, an indirect parent of CCFC, issued $150.0 million of Class A Redeemable Preferred Shares due 2006 priced at LIBOR plus 950 basis points. The Class A redeemable preferred shares were repurchased in full on October 14, 2005.

On October 14, 2005, CCFCP issued $300.0 million of 6-year redeemable preferred shares priced at LIBOR plus 950 basis points. The 6-year redeemable preferred shares are mandatorily redeemable on the maturity date and are accounted for as long-term debt in accordance with SFAS No. 150. Any related preferred dividends will be accounted for as interest expense in accordance with SFAS No. 150. The effective interest rate, after amortization of deferred financing charges, was 14.2% per annum at December 31, 2005. CCFCP is a Non-Debtor entity. Consequently, these instruments are not deemed to be subject to compromise.


18.	Capital Lease Obligations

In the first quarter of 2004, CPIF, a related party, acquired the King City power plant from a third party lessor in a transaction that closed May 19, 2004. See Note 12 for a discussion of our relationship with CPIF. CPIF became the new lessor of the facility, which it purchased subject to our pre-existing operating lease. We restructured certain provisions of the operating lease, including a 10-year extension and the elimination of the collateral requirements necessary to support the original lease payments. The base term of the restructured lease expires in 2028 with a renewal option at the then fair market rental value of the facility. Due to the lease extension and other modifications to the original lease, the lease was reevaluated under SFAS No. 13, “Accounting for Leases,” and determined to be a capital lease. The present value of the minimum lease payments totaled approximately $114.9 million which represented more than 90% of the fair value of the facility. As a result, we recorded a capital lease asset of $114.9 million as property, plant and equipment in the Consolidated Balance Sheets. This asset will be depreciated over the 24-year base lease term. In recording the capital lease obligation, the outstanding deferred lease incentive liability ($53.7 million including the current portion as of December 31, 2003) recorded as part of the original operating lease transaction, and the prepaid operating lease payments asset ($69.4 million including the current portion as of December 31, 2003) accumulated under the original operating lease terms, were eliminated. The difference between these two balances on May 19, 2004, was approximately $19.9 million and is reflected as a discount to the $114.9 million

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

capital lease obligation. This discount will be accreted as additional interest expense using the effective interest method over the 24-year base lease term. The net capital lease obligation originally recorded as debt in the Consolidated Balance Sheet was $94.9 million.

Pursuant to the applicable transaction agreements, each of Calpine King City Cogen, LLC, Calpine Securities Company, L.P., a parent company of Calpine King City Cogen, LLC and Calpine King City, LLC, an indirect parent company of Calpine Securities Company, L.P., has been established as an entity with its existence separate from us and other subsidiaries of ours. We consolidate these entities.

Calpine Corporation’s bankruptcy filing has resulted in an event of default under King City Cogen’s lease agreement with King City, L.P., and under a loan agreement between King City, L.P. and GE VFS Financing Holdings, Inc., an affiliate of GE, entered into in connection with the King City Cogen leveraged lease financing. Pursuant to the leveraged lease financing, King City, L.P. has assigned its rights under the lease to GE VFS. On December 20, 2005, King City Cogen entered into a forbearance agreement with GE VFS, whereby GE VFS agreed to forbear from taking any action arising from any events of default or potential events of default occurring as a result of our bankruptcy filings through April 20, 2006. On April 13, 2006, the forbearance agreement was extended through January 1, 2007. Upon expiration of the forbearance agreement, GE VFS may exercise remedies including accelerating its loan with King City, L.P. and/or requiring King City, L.P. to take certain measures including acceleration of the lease obligations of King City Cogen.

We assumed and consolidated other capital leases in conjunction with certain acquisitions. As of December 31, 2005 and 2004, the asset balances for the leased assets totaled $322.0 million and $322.3 million, respectively, with accumulated amortization of $54.1 million and $41.8 million, respectively. Of these balances, as of December 31, 2005 and 2004, $114.9 million of leased assets and $7.4 million and $2.7 million, respectively, of accumulated amortization related to the King City power plant, which is leased from a related party. The primary types of property leased by us are power plants and related equipment. The leases generally provide for the lessee to pay taxes, maintenance, insurance, and certain other operating costs of the leased property. The lease terms range up to 28 years. Some of the lease agreements contain customary restrictions on dividends, additional debt and further encumbrances similar to those typically found in project financing agreements. In determining whether a lease qualifies for capital lease treatment, in accordance with SFAS No. 13, “Accounting for Leases,” we include all increases due to step rent provisions/escalation clauses in our minimum lease payments for our capital lease obligations. Certain capital improvements associated with leased facilities may be deemed to be leasehold improvements and are amortized over the shorter of the term of the lease or the economic life of the capital improvement. Lease concessions including taxes and insurance are excluded from the minimum lease payments. Our minimum lease payments are not tied to an existing variable index or rate.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following is a schedule by years of future minimum lease payments under capital leases together with the present value of the net minimum lease payments as of December 31, 2005 (in thousands):


			King City
			Capital Lease		Other
			with Related		Capital
			Party		Leases		Total

Years Ending December 31:
	2006		$	33,158	$	20,298	$	53,456
	2007			16,552		20,460		37,012
	2008			16,199		21,855		38,054
	2009			16,592		21,600		38,192
	2010			19,526		22,447		41,973
	Thereafter			157,047		245,864		402,911

		Total minimum lease payments		259,074		352,524		611,598
Less: Amount representing interest(1)				162,095		162,746		324,841

	Present value of net minimum lease payments			96,979		189,778		286,757
Less: Capital lease obligations, current portion				2,360		189,137		191,497

	Capital lease obligations, net of current portion		$	94,619	$	641	$	95,260


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

Due to the bankruptcy filing, which generally constituted an event default and our failure to comply with certain financial covenants under the majority of our debt instruments, we are in technical default on most of our pre-petition debt obligations. Except as otherwise may be determined by the Bankruptcy Court, the automatic stay protection afforded by the Chapter 11 proceedings prevents any action from being taken against any of the Calpine Debtors with regard to any of the defaults under the pre-petition debt obligations. However, as a result of being in violation of most of our pre-petition debt obligations, a significant portion of our outstanding capital lease obligation has been reclassified to current liabilities.


19.	CCFC Financing

The components of CCFC financing as of December 31, 2005 and 2004, are (in thousands):


		Outstanding at
		December 31,

		2005(1)		2004

Second Priority Senior Secured Floating Rate Notes Due 2011		$	409,539	$	408,568
First Priority Senior Secured Institutional Term Loans Due 2009			374,974		378,182

	Total CCFC financing		784,513		786,750
Less: Current portion			784,513		3,208

	CCFC financing, net of current portion	$	—	$	783,542


(1)	Due to technical default under the indenture, all amounts are recorded as current liabilities as of December 31, 2005.

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In November 1999, our subsidiary, CCFC, entered into a $1.0 billion non-recourse revolving construction credit facility with a consortium of banks. The lead arranger was The Bank of Nova Scotia and the lead syndication agent was Credit Suisse First Boston. The CCFC credit facility was utilized to finance the construction of certain of our gas-fired power plants. We repaid the outstanding balance of $880.1 million in August 2003 in connection with the financing described below.

On August 14, 2003, CCFC and its wholly owned subsidiary, CCFC Finance Corp., closed an institutional term loan and secured notes financing, realizing gross proceeds of $750 million. The financing included $385.0 million of First Priority Senior Secured Institutional Term Loans Due 2009 offered at 98% of par and priced at LIBOR plus 600 basis points, with a LIBOR floor of 150 basis points, and $365.0 million of Second Priority Senior Secured Floating Rate Notes Due 2011 offered at 98% of par and priced at LIBOR plus 850 basis points, with a LIBOR floor of 125 basis points. Net proceeds (after payment of transaction fees and expenses, including the fee payable to J. Aron & Company, the counterparty to a six-year index hedge with CCFC) were utilized to repay a majority of CCFC’s indebtedness under the CCFC credit facility, which was scheduled to mature in the fourth quarter of 2003. On September 25, 2003, CCFC and CCFC Finance Corp. closed on an additional $50.0 million of the CCFC Senior Notes offered at 99% of par. The CCFC Term Loans and Secured Notes are collateralized through a combination of pledges of the equity interests in and/or assets (other than excluded assets) of CCFC and its subsidiaries, other than CCFC Finance Corp. The CCFC Secured Noteholders’ and Term Loan lenders’ recourse is limited to such collateral and none of the CCFC indebtedness is guaranteed by us. S&P has assigned a CCC- (with a negative outlook) corporate credit rating to CCFC, a CCC rating (with a negative outlook) to the CCFC Term Loans and a CC rating (with a negative outlook) to the CCFC Senior Notes. The effective interest rate of the CCFC Senior Notes, after amortization of discount and deferred financing costs, was 12.4% per annum at December 31, 2005, and 10.8% at December 31, 2004. The effective interest rate of the CCFC Term Loans, after amortization of discount and deferred financing costs, was 10.2% per annum at December 31, 2005, and 8.5% at December 31, 2004. CCFC and its subsidiaries, including CCFC Finance Corp., are Non-Debtor entities. Consequently, the CCFC Term Loans and CCFC Senior Notes are not deemed to be subject to compromise.


20.	CalGen Financing

The components of the CalGen financing as of December 31, 2005 and 2004, are (in thousands):


						Letters of Credit
		Outstanding at				Outstanding at
		December 31,				December 31,

		2005		2004		2005		2004

First Priority Secured Floating Rate Notes Due 2009		$	235,000	$	235,000	$	—	$	—
Second Priority Secured Floating Rate Notes Due 2010			633,239		631,639		—		—
Third Priority Secured Floating Rate Notes Due 2011			680,000		680,000		—		—
Third Priority Secured Fixed Rate Notes Due 2011			150,000		150,000		—		—
First Priority Secured Term Loans Due 2009			600,000		600,000		—		—
Second Priority Secured Term Loans Due 2010			98,944		98,693		—		—
First Priority Secured Revolving Loans			40,799		—		158,335		189,958

	Total CalGen financing(1)	$	2,437,982	$	2,395,332	$	158,335	$	189,958


(1)	Due to the defaults occurring as a result of the Chapter 11 filings of Calgen and its subsidiaries, including CalGen Finance Corp., under the CalGen Secured Note indentures and the CalGen Term Loan agreements, all amounts are recorded as current liabilities.

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In October 2000, our wholly owned subsidiary CalGen (then called Calpine Construction Finance Company II, LLC) entered into a $2.5 billion non-recourse revolving construction credit facility with a consortium of banks. The lead arrangers were The Bank of Nova Scotia and Credit Suisse First Boston. The CalGen credit facility was utilized to finance the construction of certain of our gas-fired power plants. We repaid the outstanding balance of this debt in March 2004 from the proceeds of the financing described below.

On March 23, 2004, CalGen and its wholly owned subsidiary, CalGen Finance Corp., closed an institutional term loan (the “CalGen Term Loans”) and secured notes (the “CalGen Secured Notes”) financing realizing net proceeds (after payment of transaction fees and expenses, including the fee payable to Morgan Stanley, the counterparty to a three-year index hedge with CalGen) in the approximate amount of $2.3 billion. The interest rates associated with the CalGen Term Loans and Secured Notes are as follows:


Description		Interest Rate

First Priority Secured Floating Rate Notes Due 2009		LIBOR plus 375 basis points
Second Priority Secured Floating Rate Notes Due 2010		LIBOR plus 575 basis points
Third Priority Secured Floating Rate Notes Due 2011		LIBOR plus 900 basis points
Third Priority Secured Fixed Rate Notes Due 2011		11.50%
First Priority Secured Term Loans Due 2009		LIBOR plus 375 basis points(1)
Second Priority Secured Term Loans Due 2010		LIBOR plus 575 basis points(2)
First Priority Secured Revolving Loans		LIBOR plus 350 basis points(3)


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

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

(3)	We may also elect a Base Rate plus 250 basis points.

The CalGen Term Loans and Secured Notes are collateralized through a combination of pledges of the equity interests in CalGen and its first tier subsidiary, CalGen Expansion Company, liens on the assets of 13 of CalGen’s 14 power generating facilities (all of CalGen’s facilities other than its Goldendale facility) and related assets located throughout the United States. The CalGen Term Loan lenders’ and Secured Noteholders’ recourse is limited to such collateral, and none of the indebtedness is guaranteed by us. Net proceeds were used to refinance amounts outstanding under the CalGen credit facility, which was scheduled to mature in November 2004, and to pay fees and transaction costs associated with the refinancing. Concurrently with this refinancing, we amended and restated the CalGen credit facility to reduce the commitments under the facility to $200.0 million and extend its maturity to March 2007. Borrowings under the amended and restated CalGen credit facility bear interest at LIBOR plus 350 basis points (or, at our

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election, the Base Rate plus 250 basis points). Interest rates and effective interest rates, after amortization of deferred financing costs are as follows:


	2005 Effective Interest			2004 Effective Interest
	Rate after Amortization of			Rate after Amortization of
	Deferred Financing Costs			Deferred Financing Costs

First Priority Secured Floating Rate Notes Due 2009		7.5	%		5.8	%
Second Priority Secured Floating Rate Notes Due 2010		9.7	%		8.1	%
Third Priority Secured Floating Rate Notes Due 2011		12.6	%		10.9	%
Third Priority Secured Fixed Rate Notes Due 2011		11.8	%		11.8	%
First Priority Secured Term Loans Due 2009		7.6	%		5.8	%
Second Priority Secured Term Loans Due 2010		9.8	%		8.0	%
First Priority Secured Revolving Loans		14.6	%		17.5	%

CalGen and its subsidiaries, including CalGen Finance Corp., are U.S. Debtors, but the CalGen Term Loans and Secured Notes and the CalGen credit facility are considered to be fully secured. Consequently, the CalGen Term Loans, CalGen Secured Notes and CalGen credit facility are not deemed to be subject to compromise.

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21.	Other Construction/ Project Financing

The components of our other construction/project financing as of December 31, 2005 and 2004, are (in thousands):


						Letters of Credit
		Outstanding at				Outstanding at
		December 31,				December 31,

Projects		2005		2004		2005		2004

Pasadena Cogeneration, L.P.		$	282,222	$	282,896	$	—	$	—
Broad River Energy LLC			265,217		275,112		—		—
Otay Mesa Energy Center, LLC — Ground Lease			7,000		7,000		—		—
Gilroy Energy Center, LLC			223,218		261,382		—		—
Blue Spruce Energy Center, LLC			96,395		98,272		—		—
Riverside Energy Center, LLC			355,293		368,500		—		—
Rocky Mountain Energy Center, LLC			245,872		264,900		—		—
Calpine Fox LLC			347,828		266,075		10,000		75,000
Metcalf Energy Center, LLC			100,000		—		—		—
Mankato Energy Center, LLC			151,230		—		25,000		—
Freeport Energy Center, LP			163,603		—		25,000		—
MEP Pleasant Hill, LLC(1)			—		174,914		—		—
Bethpage Energy Center 3, LLC			123,147		—		—		—

	Total		2,361,025		1,999,051	$	60,000	$	75,000

Less: Current portion			1,160,593		93,393

Long-term construction/project financing		$	1,200,432	$	1,905,658


(1)	Classified as liability subject to compromise as of December 21, 2005, due to our bankruptcy filings on December 20, 2005.

Pasadena Cogeneration, L.P. — In September 2000, we completed the financing, which matures in 2048, for both Phase I and Phase II of the Pasadena, Texas cogeneration project. Under the terms of the financing, we received $400.0 million in gross proceeds. The actual interest rate at December 31, 2005 and 2004, was 8.6%. The effective interest rate, after amortization of deferred financing charges, was 8.7% at December 31, 2005 and 2004. Pasadena Cogeneration, LP is a Non-Debtor entity and therefore the debt amounts are not subject to compromise. However, due to certain defaults or events of default these debt amounts have been reclassified as current liabilities. (See Note 14 for a discussion of covenant compliance.)

Broad River Energy LLC — In October 2001, we completed the financing, which matures in 2041, for the Broad River Energy Center in South Carolina. Under the terms of the financing, we received $300.0 million in gross proceeds. The actual interest rate at December 31, 2005 and 2004, was 8.1%. The effective interest rate, after amortization of deferred financing charges, was also 8.1% at December 31, 2005 and 2004. Broad River Energy LLC is a U.S. Debtor. Therefore the debt amounts are not subject to compromise. Due to certain defaults or events of default these debt amounts have been reclassified as current liabilities.

Otay Mesa Energy Center, LLC — On July 8, 2003, Otay Mesa Generating Company, LLC, entered into a $7.0 million ground lease and easement agreement with D&D Landholdings. Otay Mesa Generating

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Company, LLC was merged into Calpine Corporation on July 16, 2003. The ground lease and easement agreements were subsequently transferred to Otay Mesa Energy Center, LLC, which was formed in October 2003. The lease and easement agreement expires on December 1, 2033. The actual interest rate at December 31, 2005 and 2004, was 12.7% and 12.6%, respectively. The effective interest rate after amortization of deferred financing charges was 12.9% and 12.8% at December 31, 2005 and 2004, respectively. Otay Mesa Energy Center, LLC is a Non-Debtor entity and therefore the debt amounts are not subject to compromise. See Note 34 for a discussion of the potential disposition of this facility.

Gilroy Energy Center, LLC — On September 30, 2003, GEC, a wholly owned subsidiary of our subsidiary GEC Holdings, LLC, completed an offering of $301.7 million of 4% Senior Secured Notes Due 2011. The GEC notes are secured by GEC’s and its subsidiaries’ 11 peaking units located at nine power-generating sites in northern California. The GEC notes also are secured by a long-term PPA with CDWR for 495 MW of peaking capacity, which is being served by the 11 peaking units. In addition, payment of the principal and interest on the GEC notes when due is insured by an unconditional and irrevocable financial guaranty insurance policy that was issued by a third party simultaneously with the delivery of the GEC notes. Proceeds of the GEC notes offering (after payment of transaction expenses, including payment of the financial guaranty insurance premium, which are capitalized and included in deferred financing costs on our Consolidated Balance Sheets) were used to reimburse costs incurred in connection with the development and construction of the peaker projects. The GEC noteholders’ recourse is limited to the financial guaranty insurance policy and, to the extent payment is not made under such policy, to the assets of GEC and its subsidiaries. We have not guaranteed the GEC notes. The actual interest rate at December 31, 2005 and 2004, was 4%. The effective interest rate, after amortization of deferred financing charges, was 7.4% and 6.7% at December 31, 2005 and 2004, respectively. In connection with this offering, we received funding on a third party preferred equity investment in GEC Holdings, LLC totaling $74.0 million. See Note 17 for more information regarding this preferred equity interest. GEC is a Non-Debtor entity and therefore the debt amounts are not subject to compromise.

Blue Spruce Energy Center, LLC — On November 7, 2003, we completed a $140.0 million term loan financing for the Blue Spruce Energy Center. The term loan is made up of two facilities, Tranche A (for $100 million) and Tranche B (for $40 million), which have 15-year and 6-year repayment terms, respectively. At December 31, 2005 and 2004, there was $96.4 and $98.3 million, respectively, outstanding under Tranche A. Tranche B was fully repaid during 2004 and may not be reborrowed. The actual interest rate for Tranche A at December 31, 2005 and 2004, was 11.0% and 9.1%, respectively. The effective interest rate for Tranche A, after amortization of deferred financing costs, was 10.6% and 9.1%, respectively, at December 31, 2005 and 2004. Blue Spruce Energy Center, LLC is a U.S. NonDebtor and therefore the debt amounts are not subject to compromise. However, due to certain defaults or events of default these debt amounts have been reclassified as current liabilities. (See Note 14 for a discussion of covenant compliance.)

Riverside Energy Center, LLC and Rocky Mountain Energy Center, LLC — On February 20, 2004, we completed $250.0 million of non-recourse project financing for Rocky Mountain Energy Center and, on August 25, 2003, we completed $230.0 million of non-recourse project financing for Riverside Energy Center. These loans were refinanced on June 29, 2004, with the proceeds from $633.4 million of First Priority Secured Floating Rate Term Loans Due 2011 priced at LIBOR plus 425 basis points and a $28.1 million letter of credit-linked deposit facility provided to Rocky Mountain Energy Center, LLC and Riverside Energy Center, LLC, wholly owned stand-alone subsidiaries of Calpine Riverside Holdings, LLC. In connection with this refinancing, we wrote off $13.2 million in deferred financing costs. In addition, approximately $160.0 million was used to reimburse us for costs incurred in connection with the development and construction of the Rocky Mountain and Riverside facilities. We also received approximately $79.0 million in proceeds via a combination of cash and increased credit capacity as a result of the elimination of certain reserves and cancellation of letters of credit associated with the original non-recourse project financings. The actual interest rate of the

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Rocky Mountain facility at December 31, 2005 and 2004, was 8.6%. The effective interest rate of the Rocky Mountain facility at December 31, 2005 and 2004, after amortization of deferred financing costs, was 9.9% and 10.2%, respectively. The actual interest rate of the Riverside facility at December 31, 2005 and 2004, was 8.8% and 6.4%, respectively. The effective interest rate of the Riverside facility, after amortization of deferred financing costs, was 9.4% and 9.2%, at December 31, 2005 and 2004, respectively. Riverside Energy Center, LLC and Rocky Mountain Energy Center, LLC are Non-Debtor entities and therefore the debt amounts are not subject to compromise.

Calpine Fox LLC — On November 19, 2004, we entered into a $400 million 25-year, non-recourse sale/leaseback transaction with affiliates of GECF for the 560-MW Fox Energy Center then under construction in Wisconsin. The proceeds were used to reimburse us for construction capital spent on the project, repay existing debt associated with equipment for the project and complete the construction of the facility. Once construction was completed, we leased the Fox power plant from GECF under a 25-year facility lease. The lease is renewable at our option for a 15-year term. Due to significant continuing involvement, as defined in SFAS No. 98, “Accounting for Leases,” the transaction does not currently qualify for sale lease-back accounting under that statement and has been accounted for as a financing. The proceeds received from GECF are recorded as debt in our Consolidated Balance Sheets. For so long as we continue to lease the facility, the power plant assets will be depreciated over their estimated useful life and the lease payments will be applied to principal and interest expense using the effective interest method until such time as our continuing involvement is removed, expires or is otherwise eliminated. Once we no longer have significant continuing involvement in the power plant assets, the legal sale will be recognized for accounting purposes and the underlying lease will be evaluated and classified in accordance with SFAS No. 13, “Accounting for Leases.” The actual interest rate at December 31, 2005 and 2004, was 8.3% and 7.1%, respectively. The effective interest rate after amortization of deferred financing charges at December 31, 2005 and 2004, was 8.8% and 7.4%, respectively. The Fox Energy Center was subsequently identified as one of a number of designated projects that, absent the consent of the creditor committees or unless ordered by the U.S. Bankruptcy Court, may not receive further funding, other than certain limited amounts that were agreed to by the creditor committees. We are currently evaluating options with respect to this facility. Calpine Fox LLC is a Non-Debtor entity and therefore the debt amounts are not subject to compromise. However, due to certain defaults or events of default these debt amounts have been reclassified as current liabilities. (See Note 14 for a discussion of covenant compliance.)

Metcalf Energy Center, LLC — On January 28, 2005, Metcalf entered into a $100.0 million, non-recourse construction credit facility for the 602-MW natural gas-fired Metcalf Energy Center in San Jose, California. Loans extended to Metcalf under the construction credit facility were used to fund the balance of construction activities for the power plant. This credit facility was refinanced on June 20, 2005, with the proceeds of Metcalf’s five-year, $100.0 million senior term loan priced at LIBOR plus 300 basis points. Concurrently with the refinancing of the construction credit facility with the proceeds of the senior term loan, Metcalf consummated the sale of $155.0 million of 5.5-year redeemable preferred shares priced at LIBOR plus 900 basis points. See Note 17 for more information regarding the redeemable preferred shares. The actual and effective interest rates after amortization of deferred financing charges under the senior term loan, were 7.4% and 7.7%, respectively, at December 31, 2005. Metcalf Energy Center, LLC is a Non-Debtor entity and therefore the debt amounts are not subject to compromise.

Mankato Energy Center, LLC and Freeport Energy Center, LP — On March 1, 2005, our indirect subsidiary, Calpine Steamboat Holdings, LLC, closed on a $503.0 million non-recourse project finance facility that provided $466.5 million to complete the construction of the Mankato Energy Center in Blue Earth County, Minnesota, and the Freeport Energy Center in Freeport, Texas. The remaining $36.5 million of the facility provides a letter of credit for Mankato ($25 million in use as of December 31, 2005) that is required pursuant to Mankato’s PPA with Northern States Power Company. The project finance facility is structured

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as a construction loan, converting to a term loan upon commercial operation of the plants, and matures in December 2011. The facility was initially priced at LIBOR plus 1.75%. The actual interest rate at December 31, 2005, was 6.1% for both Mankato and Freeport. The effective interest rate after amortization of deferred financing charges at December 31, 2005, was 6.5% and 5.9% for Mankato and Freeport, respectively. Mankato Energy Center, LLC and Freeport Energy Center, LP are Non-Debtor entities and therefore the debt amounts are not subject to compromise.

Bethpage Energy Center 3, LLC — On June 30, 2005, we received funding on a $123.1 million non-recourse project finance facility to complete the construction of the 79.9-MW Bethpage Energy Center 3. The financing is comprised of a $108.5 million first lien loan and a $14.6 million second lien loan, carrying a term of 20 years and 15 years, respectively. Approximately $74.4 million of the funding was used to reimburse us for costs spent on the project. The balance of funds were used for transaction expenses, the final completion of the project, and to fund certain reserve accounts. The actual and effective interest rates after amortization of deferred financing charges under the first lien loan at December 31, 2005, were 6.1% and 6.8%, respectively. The actual and effective interest rates after amortization of deferred financing charges under the second lien loan at December 31, 2005, were 7.9% and 8.6%, respectively. Bethpage Energy Center 3, LLC is a U.S. Debtor, however, the project financing is considered to be fully secured. Consequently, this debt financing is not deemed to be subject to compromise. Due to certain defaults or events of default these debt amounts have been reclassified as current liabilities.


22.	DIP Facility

On December 22, 2005, Calpine Corporation, as borrower, entered into the DIP Facility with Deutsche Bank Securities, Inc. and Credit Suisse, as joint syndication agents, Deutsche Bank Trust Company Americas as administrative agent for the first priority lenders and Credit Suisse as administrative agent for the second priority lenders. The DIP Facility is guaranteed by each of the other U.S. Debtors. On January 26, 2006, the U.S. Bankruptcy Court granted final approval of the DIP Facility, and on February 23, 2006, the DIP Facility was amended and restated and the term loans were funded. On May 3, 2006, the DIP Facility was further amended. See Note 34 for more information.

Pursuant to the DIP Facility, and applicable orders of the U.S. Bankruptcy Court, the lenders have made available to Calpine up to $2 billion comprising a $1 billion revolving loan and letter of credit facility, a $400 million first priority term loan facility and a $600 million second priority term loan facility. The proceeds of borrowings and letters of credit issued under the DIP Facility will be used, among other things, for working capital and other general corporate purposes. A portion of the DIP Facility was used to purchase The Geysers, including the redemption of the lesser notes. In addition, pursuant to the May 3, 2006 amendment, borrowings under the DIP Facility may be used to repay a portion of the First Priority Notes. We had borrowed $25 million under the DIP Facility as of December 31, 2005.


		December 22, 2005

		(In thousands)
First Priority Facility Commitments
	Revolving Credit Facility(1)(2)	$	1,000,000
	First Priority Term Loan(2)		400,000
Second Priority Facility Commitments
	Second Priority Term Loan(2)	$	600,000


(1)	Commitments for letters of credit ($300 million) and swingline loans ($10 million) can be drawn against the revolving credit facility. The DIP Facility will remain in place until the earlier of an effective plan of reorganization on December 20, 2007.

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(2)	Pursuant to the interim order issued by the US Bankruptcy Court on December 22, 2005, the US Debtors were only authorized to borrow an aggregate amount up to $500,000,000 under the Revolving Credit Facility and nothing under either term facility until the final order was issued by the US Bankruptcy Court on January 26, 2006.

Interest terms on Eurodollar loans are Eurodollar rate (LIBOR) plus a margin, as follows:


	Margin
	December 22, 2005

Revolving Loans and Swingline Loans		2.25	%
First Priority Term Loan		2.25	%
Second Priority Term Loan		4.00	%

The DIP Facility is secured by first priority liens on all of the U.S. Debtors’ unencumbered assets, in particular all of The Geysers assets, and junior liens on all of the U.S. Debtors’ encumbered assets.

Covenant Restrictions — Our DIP Facility includes financial and other covenants that impose substantial restrictions on our financial and business operations. Our ability to comply with these covenants depends in part on our ability to implement our restructuring program during the bankruptcy cases. The DIP Facility contains events of default customary for DIP financings of this type, including cross defaults and certain change of control events. These restrictions limit or prohibit our ability to, among other things:


	•	incur additional indebtedness and issue preferred stock;

	•	make prepayments on or purchase indebtedness in whole or in part;

	•	pay dividends and other distributions with respect to our capital stock or repurchase our capital stock or make other restricted payments;

	•	make certain investments;

	•	enter into transactions with affiliates;

	•	create or incur liens to secure debt;

	•	consolidate or merge with another entity, or allow one of our subsidiaries to do so;

	•	lease, transfer or sell assets and use proceeds of permitted asset leases, transfers or sales;

	•	incur dividend or other payment restrictions affecting certain subsidiaries;

	•	make capital expenditures;

	•	engage in certain business activities; and

	•	acquire facilities or other businesses.

Our ability to comply with these covenants may be affected by events beyond our control, and any material deviations from our forecasts could require us to seek waivers or amendments of covenants or alternative sources of financing or to reduce expenditures, however, we cannot assure you that such efforts would be successful. If they are not, and we are unable to comply with the terms of the DIP Facility, it could adversely impact the timing of, and our ultimate ability to successfully implement, a plan of reorganization.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


23.	Senior Notes


	*First Priority Senior Secured Notes Due 2014*

Senior Notes not subject to compromise consist of the following as of December 31, 2005 and 2004, (in thousands):

Amount Outstanding as

Fair Value as of

First

of December 31,

December 31,

Interest

Call

Rates

Date

2005

2004

2005

2004

First Priority Senior Secured Notes Due 2014

9⁵/8%

(12

)

$641,652

$778,971

$660,902

$801,367

On September 30, 2004, we issued $785 million of First Priority Notes, offered at 99.212% of par. The First Priority Notes are secured by substantially all of the assets owned directly by Calpine Corporation, and by the stock of substantially all of Calpine Corporation’s first-tier subsidiaries. We may redeem some or all of the First Priority Notes at any time on or after October 1, 2009, at specified redemption prices plus accrued and unpaid interest. At any time prior to October 1, 2009, we may redeem some or all of the First Priority Notes at a price equal to 100% of their principal amount plus an applicable premium and accrued and unpaid interest. In addition, at any time prior to October 1, 2007, we may redeem up to 35% of the aggregate principal amount of the First Priority Notes with the net proceeds from one or more public equity offerings at a stated redemption price. Interest is payable on the First Priority Notes on April 1 and October 1 of each year, beginning on April 1, 2005. The First Priority Notes mature on September 30, 2014. At December 31, 2005, the book and face value of these notes were $641.7 million and $646.1 million, respectively. The effective interest rate on these notes, after amortization of deferred financing costs, was approximately 10.0% per annum at December 31, 2005 and 2004.

The U.S. Bankruptcy Court approved our motion to repay the outstanding principal amount of First Priority Notes at par ($646.1 million) plus accrued and unpaid interest by order dated May 10, 2006, as amended by its amended order dated May 17, 2006. We expect to use the approximately $412 million of cash that remains on deposit in a restricted designated asset sale proceeds account relating to the July 2005 sale of our oil and gas reserves, with the balance of the funds necessary to effect the repayment coming from borrowings under the DIP Facility. Such repayment would not include a “make whole” premium to which holders of the First Priority Notes claim they are entitled, however, the repayment would be without prejudice to the rights of the holders of the First Priority Notes to pursue their claim to such “make whole” premium.

For information regarding liabilities of our subsidiaries not subject to compromise, see Notes 14 through 23.


24.	Liabilities Subject to Compromise

Liabilities Subject to Compromise — Liabilities subject to compromise include unsecured and undersecured liabilities incurred prior to the Petition Date and exclude liabilities that are fully secured or liabilities of our subsidiaries or affiliates that have not made bankruptcy filings and other approved payments such as taxes and payroll. In accordance with SOP 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code,” we ceased to accrue and recognize interest expense on liabilities subject to compromise, except that paid pursuant to the Cash Collateral Order. In addition, deferred financing costs and debt discounts related to LSTC were adjusted to reflect the related debt at its expected probable allowed claim amount, which resulted in the write-off of approximately $148.1 million to reorganization items. However, we are making periodic cash payments to second lien lenders through June 30, 2006, in accordance with the Cash Collateral Order. The amounts of various categories of liabilities of which we are aware that are subject to compromise are set forth below. These amounts represent our best estimates of known or potential pre-petition liabilities that are probable of resulting in an allowed claim against us in connection with the

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bankruptcy filings and are recorded at the estimated amount of the allowed claim which may differ from the amount for which the liability will be settled. Such claims remain subject to future adjustments. Adjustments may result from negotiations, actions of the Bankruptcy Courts, rejection of executory contracts and unexpired leases, the determination as to the value of any collateral securing claims, proofs of claim or other events. We expect that the liabilities of the Calpine Debtors will exceed the fair value of their assets. This is expected to result in claims being paid at less than 100% of their face value, and the equity of Calpine’s stockholders could be diluted or eliminated entirely. In addition, the claims bar dates — the dates by which claims against the Calpine Debtors must be filed with the applicable Bankruptcy Court — have been set for August 1, 2006 by the U.S. Bankruptcy Court with respect to claims against the U.S. Debtors and June 30, 2006 by the Canadian Court with respect to claims against the Canadian Debtors. Accordingly, not all potential claims would have been filed as of December 31, 2005, and we expect that additional claims will be filed against us prior to the claims bar dates; however, the amount of such claims cannot be estimated at this time. Any claims filed may result in additional liabilities, some or all of which may be subject to compromise, and the amounts of which may be material to us.

The amounts of LSTC at December 31, 2005 consisted of the following millions:


Accounts payable and accrued liabilities		$	724.2
Derivative liabilities			133.6
Project financing			166.5
Convertible notes			1,823.5
Second priority senior secured notes			3,671.9
Unsecured senior notes			1,880.0
Notes payable and other liabilities — related party			1,078.0
Provision for allowable claims			5,132.4

	Total liabilities subject to compromise	$	14,610.1

As a result of our bankruptcy filings, the fair value cannot be reasonably determined for the outstanding debt that is included in Liabilities Subject to Compromise on the Consolidated Balance Sheet.


	*Project Financing*

MEP Pleasant Hill, LLC — On March 26, 2004, in connection with the closing of our acquisition of Aquila’s 50% interest in the Aries Power Plant, the existing construction loan related to this project was converted to two term loans totaling $178.8 million. At December 31, 2005 and 2004, the Tranche A term loan had an aggregate principal amount of $119.8 million and $126.8 million, respectively, with quarterly payments due through and maturity in December 2016. At December 31, 2005 and 2004, the Tranche B term loan had an aggregate principal amount of $46.7 million and $48.1 million, respectively, with quarterly payments due through maturity in December 2019. After taking interest rate swaps into consideration, the effective interest rate on the Tranche A term loan at December 31, 2005 and 2004, was 13.4% and 8.2%, respectively. After taking interest rate swaps into consideration, the effective interest rate on the Tranche B term loan at December 31, 2005 and 2004, was 10.3% and 8.6%, respectively. MEP Pleasant Hill, LLC is a U.S. Debtor and, based on our analysis, the debt balance exceeded the fair value of the underlying facility. Consequently, the debt was under-secured and is deemed to be subject to compromise.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Convertible Notes*


										Fair Value as of
						December 31,				December 31,
			Interest
			Rates			2005		2004		2005		2004

Convertible Notes
	2006 Convertible Notes			4	%	$	1,311	$	1,326	$	1,311	$	1,326
	2023 Convertible Notes			4³/4	%		633,775		633,775		160,424		633,775
	2014 Convertible Notes			6	%(1)		538,374		620,197		108,011		716,055
	2015 Convertible Notes			7³/4	%		650,000		—		327,275		—

		Total Convertible Notes				$	1,823,460	$	1,255,298	$	597,021	$	1,351,156

(1)

The 2014 Convertible Notes pay interest each March 30 and September 30 at the rate of 6% per annum, except that no interest is paid on or accrues for the March 30 and September 30, 2007, 2008 and 2009 interest payment dates. Instead, beginning on September 30, 2006, the original principal amount of $839 per note increases by $0.1469 daily to $1,000 principal amount per note at September 30, 2009. Thereafter, the principal amount of the notes does not increase, and the notes resume paying interest on each March 30 and September 30 at the rate of 6% per annum.


	4% Convertible Senior Notes Due 2006

In December 2001 and January 2002, we completed the issuance of $1.2 billion in aggregate principal amount of 2006 Convertible Notes. The 2006 Convertible Notes are convertible, at the option of the holder, into shares of our common stock at a price of $18.07. Holders had the right to require us to repurchase all or a portion of their 2006 Convertible Notes on December 26, 2004, at 100% of their principal amount plus any accrued and unpaid interest for (at our option) cash, shares of our common stock, or a combination of cash and stock. During 2004 and 2003 we repurchased approximately $658.7 million and $474.9 million, respectively, in aggregate outstanding principal amount of the 2006 Convertible Notes at a repurchase price of $657.7 million and $458.8 million, respectively, plus accrued interest. Additionally, during 2003 approximately $65.0 million in aggregate outstanding principal amount of the 2006 Convertible Notes were exchanged for 12.0 million shares of Calpine common stock in privately negotiated transactions. During 2004 and 2003 we recorded a pre-tax loss of $5.3 million and a pre-tax gain of $13.6 million, respectively, on these transactions, net of write-offs of the associated unamortized deferred financing costs and unamortized premiums or discounts. There were no transactions related to the 2006 Convertible Notes during 2005. The effective interest rate on these notes at December 31, 2005 and 2004, after amortization of deferred financing costs, was 4.0% and 4.6% per annum, respectively. At December 31, 2005, approximately $1.3 million of the 2006 Convertible Notes remained outstanding.


	4³/4% Contingent Convertible Senior Notes Due 2023

On November 17, 2003, we completed the issuance of $650 million of 2023 Convertible Notes and, on January 9, 2004, one of the initial purchasers of the 2023 Convertible Notes exercised in full its option to purchase an additional $250.0 million of these notes. The 2023 Convertible Notes are convertible, at the option of the holder, into cash and into a variable number of shares of our common stock based on a conversion value derived from the conversion price of $6.50 per share. The number of shares to be delivered upon conversion will be determined by the market price of our common shares at the time of conversion. Holders have the right to require us to repurchase all or a portion of the 2023 Convertible Notes on November 15, 2009, November 15, 2013, and November 15, 2018, at 100% of their principal amount plus any

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

accrued and unpaid interest and liquidated damages, if any, up to the date of repurchase. Otherwise, conversion is subject to certain conditions, including (1) a common stock price condition, which requires that our common stock price for at least 20 trading days in the period of 30 consecutive trading days ending on the last trading day of the calendar quarter preceding the quarter in which the conversion occurs, at more than 120% of the conversion price per share of our common stock in effect on that 30th trading day and (2) a trading price condition, which requires that the trading price of $1,000 principal amount of the 2023 Convertible Notes for each day of a five-day period be less than 95% of the product of the closing sale price of our common stock on that day multiplied by the applicable conversion rate. Holders have a limited amount of time to convert their 2023 Convertible Notes once a conversion condition has been achieved. Generally, upon conversion, we would be required to deliver the par value of the 2023 Convertible Notes in cash and any additional conversion value in common stock. However, if the 2023 Convertible Notes are put back to us on November 15, 2009, November 15, 2013 or November 15, 2018, we have the right to pay the repurchase price in cash, shares of our common stock, or a combination of cash and stock. In addition, if the 2023 Convertible Notes are converted during certain events of default, including the event of default that has occurred as a result of our bankruptcy filings, we are required to deliver the par value of the notes solely in shares of our common stock. For a summary of the theoretical maximum additional shares potentially issuable under our contingent convertible notes, see Note 30.

During 2004, we repurchased approximately $266.2 million in aggregate outstanding principal amount of 2023 Convertible Notes at a repurchase price of $177.0 million plus accrued interest. At December 31, 2005, there was $633.8 million in outstanding principal amount of 2023 Convertible Notes. The effective interest rate on these notes, after amortization of deferred financing costs, was approximately 5.2% and 5.3% per annum at December 31, 2005 and 2004, respectively.


	Contingent Convertible Notes Due 2014

On September 30, 2004, we completed the issuance of $736 million aggregate principal amount at maturity of 2014 Convertible Notes, offered at 83.9% of par. The 2014 Convertible Notes are convertible into cash and into a variable number of shares of our common stock based on a conversion value derived from the conversion price of $3.85 per share. The number of shares to be delivered upon conversion will be determined by the market price of Calpine common shares at the time of conversion. However, conversion is subject to certain conditions, including (1) a common stock price condition, which requires that our common stock price for at least 20 trading days in the period of 30 consecutive trading days ending on the last trading day of the calendar quarter preceding the quarter in which the conversion occurs, at more than 120% of the conversion price per share of our common stock in effect on that 30th trading day and (2) a trading price condition, which requires that the trading price of $1,000 principal amount at maturity of the 2014 Convertible Notes for each day of a five-day period be less than 95% of the product of the closing sale price of our common stock on that day multiplied by the applicable conversion rate. Holders have a limited amount of time to convert their notes once a conversion condition has been achieved.

The 2014 Convertible Notes pay cash interest at a rate of 6%, except that in years three, four and five, in lieu of interest, the original principal amount of $839 per note will accrete daily beginning September 30, 2006, to the full principal amount of $1,000 per note at September 30, 2009. For accounting purposes, we have calculated the effective interest rate of the 2014 Convertible Notes capturing the 6% stated rate and the 16.1% discount and are recording interest expense over the 10-year term of the instrument using the effective interest method in accordance with paragraphs 13-15 of APB Opinion No. 21, “Interest on Receivables and Payables.” Generally, upon conversion of the 2014 Convertible Notes, we are required to deliver the accreted principal amount of the notes in cash and any additional conversion value in common stock. However, if the 2014 Convertible Notes are converted during certain events of default, including the event of default that has occurred as a result of our bankruptcy filings, we are required to deliver the par value of the notes solely in

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shares of our common stock. For a summary of the theoretical maximum additional shares potentially issuable under our contingent convertible notes, see Note 30.

On June 28, 2005, we exchanged 27.5 million shares of Calpine common stock in privately negotiated transactions for $94.3 million in aggregate principal amount at maturity of our 2014 Convertible Notes. This resulted in a pre-tax loss of $8.3 million, comprised of a gain of $8.9 million, net of write-offs of $2.8 million unamortized deferred financing costs and $14.4 million unamortized discount and legal costs.

At December 31, 2005, there was $538.4 million in aggregate outstanding principal amount of these notes. The effective interest rate on these notes, after amortization of deferred financing costs, was approximately 7.0% and 6.3% per annum at December 31, 2005 and 2004, respectively.

In conjunction with the issuance of the 2014 Convertible Notes offering, we entered into a ten-year Share Lending Agreement with DB London, under which we loaned DB London 89 million shares of newly issued Calpine common stock. DB London sold the entire 89 million shares on September 30, 2004, at a price of $2.75 per share in a registered public offering. We did not receive any of the proceeds of the public offering. DB London is required to return the loaned shares to us no later than the end of the ten-year term of the Share Lending Agreement, or earlier under certain circumstances. Once loaned shares are returned, they may not be re-borrowed under the Share Lending Agreement. Under the Share Lending Agreement, DB London is required to post and maintain collateral in the form of cash, government securities, certificates of deposit, high-grade commercial paper of U.S. issuers or money market shares at least equal to 100% of the market value of the loaned shares as security for the obligation of DB London to return the loaned shares to us. This collateral is held in an account at a DB London affiliate. We have no access to the collateral unless DB London defaults under its obligations.

The Share Lending Agreement is similar to an accelerated share repurchase transaction which is addressed by EITF Issue No. 99-07, “Accounting for an Accelerated Share Repurchase Program.” This EITF issue requires an accelerated share repurchase transaction to be accounted for as two transactions: a treasury stock purchase and a forward sales contract. The Share Lending Agreement involved the issuance of 89 million shares of our common stock in exchange for a physically settling forward contract for the reacquisition of the shares at a future date. We recorded the issuance of shares in equity at the fair value of the common stock on the date of issuance in the amount of $258.1 million. As there was minimal cash consideration in the transaction, the requirement for the return of these shares is considered to be a prepaid forward purchase contract. We have evaluated the prepaid forward contract under the guidance of SFAS No. 133, and determined that the instrument was not a derivative in its entirety and that the embedded derivative would not require separate accounting. The hybrid contract was classified similar to a shareholder loan which was recorded in equity at the fair value of the common stock on the date of issuance in the amount of $258.1 million.

Under SFAS No. 150, entities that have entered into a forward contract that requires physical settlement by repurchase of a fixed number of the issuer’s equity shares of common stock in exchange for cash shall exclude the common shares to be redeemed or repurchased when calculating basic and diluted EPS. The Share Lending Agreement does not provide for cash settlement, but rather physical settlement is required (i.e. the shares must be returned by the end of the arrangement). We analogize to the guidance in SFAS No. 150 such that the prepaid forward contract results in a reduction in the number of outstanding shares used to calculate basic and diluted EPS. Consequently, the 89 million shares of common stock subject to the Share Lending Agreement are excluded from the EPS calculation.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	7³/4% Contingent Convertible Notes Due 2015

On June 23, 2005, we completed the issuance of $650 million of 2015 Convertible Notes. We used a portion of the net proceeds to repurchase $338 million of our 8¹/2 % Senior Notes due 2011 (included in Senior Notes repurchase amounts below (see “— Second Priority and Unsecured Senior Notes Subject to Compromise”). We used the remaining net proceeds of $402.5 million towards the redemption in full of the HIGH TIDES III. See Note 16 for more information regarding the redemption of the HIGH TIDES III and the related underlying debentures.

The 2015 Convertible Notes are convertible, at the option of the holder, into cash and into a variable number of shares of our common stock based on a conversion value derived from the conversion price of $4.00 per share. The number of shares to be delivered upon conversion will be determined by the market price of Calpine common shares at the time of conversion. However, conversion is subject to certain conditions, including (1) a common stock price condition, which requires that our common stock price for at least 20 trading days in the period of 30 consecutive trading days ending on the last trading day of the calendar quarter preceding the quarter in which the conversion occurs at more than 120% of the conversion price per share of our common stock in effect on that 30th trading day and (2) a trading price condition, which requires that the trading price of $1,000 principal amount of the 2015 Convertible Notes for each day of a five-day period be less than 95% of the product of the closing sale price of our common stock on that day multiplied by the applicable conversion rate. Holders of the 2015 Convertible Notes have a limited amount of time to convert their notes once a conversion condition has been achieved. Generally, upon conversion of the 2015 Convertible Notes, we are required to deliver the par value of the 2015 Convertible Notes in cash and any additional conversion value in common stock. However, if the 2015 Convertible Notes are converted during certain bankruptcy-related events of default, including the event of default that has occurred as a result of our bankruptcy filings, we are required to deliver the par value of the 2015 Convertible Notes solely in shares of our common stock. For a summary of the theoretical maximum additional shares potentially issuable under our contingent convertible notes, see Note 30.

If a conversion event were to occur under any of the contingent convertible notes, the outstanding principal amount due under these notes would effectively become a demand note during the conversion window and such outstanding principal amount would be reflected as a current liability on our consolidated balance sheet. In addition, if a conversion event were to occur and contingent convertible notes were tendered for conversion, provisions of our outstanding indentures may require us to refinance such tendered notes in order to comply with our conversion obligations.

At December 31, 2005, there was $650 million in outstanding borrowings under these notes. The effective interest rate on those notes after amortization of deferred financing costs, was approximately 8.0% per annum at December 31, 2005.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Second Priority Senior Secured Notes and Term Loans*

Second Priority Senior Secured Notes and Term Loans subject to compromise consist of the following as of December 31, 2005 and 2004 (in thousands):


															Fair Value as of
								First			December 31,				December 31, (3)
					Interest			Call
					Rates			Date			2005		2004		2005		2004

Second Priority Senior Secured Notes and Term Loans
	Second Priority Senior Secured Term Loan B Due 2007						(4)		(5	)	$	733,125	$	740,625	$	687,305	$	677,672
	Second Priority Senior Secured Floating Rate Notes Due 2007						(6)		(2	)		488,750		493,750		453,316		449,313
	Second Priority Senior Secured Notes Due 2010					8¹/2	%		(2	)		1,150,000		1,150,000		922,875		987,563
	Second Priority Senior Secured Notes Due 2011					9⁷/8	%		(1	)		400,000		393,150		312,000		344,006
	Second Priority Senior Secured Notes Due 2013					8³/4	%		(2	)		900,000		900,000		724,500		740,250

		Total Second Priority Senior Secured Notes and Term Loans										3,671,875		3,677,525		3,099,996		3,198,804

			Less: Second Priority Senior Secured Notes and Term Loans, current portion									—		12,500		—		12,500

				Second Priority Senior Secured Notes and Term Loans, net of current portion							$	3,671,875	$	3,665,025	$	3,099,996	$	3,186,304


(1)	Not redeemable prior to maturity.

(2)	At any time before July 15, 2005, with respect to the Second Priority Senior Secured Floating Rate Notes Due 2007 (the “2007 notes”) and before July 15, 2006, with respect to the Second Priority Senior Secured Notes Due 2010 (the “2010 notes”) and the Second Priority Senior Secured Notes Due 2013 (the “2013 notes”), on one or more occasions, we can choose to redeem up to 35% of the outstanding principal amount of the applicable series of notes, including any additional notes issued in such series, with the net cash proceeds of any one or more public equity offerings so long as (1) we pay holders of the notes a redemption price equal to par plus the applicable Eurodollar rate then in effect with respect to the 2007 notes, 108.500% with respect to the 2010 notes, and 108.750% with respect to the 2013 notes, at the face amount of the notes we redeem, plus accrued interest; (2) we must redeem the notes within 45 days of such public equity offering; and (3) at least 65% of the aggregate principal amount of the applicable series of notes originally issued under the applicable indenture, including the principal amount of any additional notes, remains outstanding immediately after each such redemption.

(3)	Represents the market value of the notes at the respective dates.

(4)	U.S. Prime Rate in combination with the Federal Funds Effective Rate, plus a spread.

(5)	We may not voluntarily prepay these notes prior to July 15, 2005, except that we may on any one or more occasions make such prepayment with the proceeds of one or more public equity offerings.

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(6)	British Bankers Association LIBOR Rate for deposits in U.S. dollars for a period of three months, plus a spread.


	Second Priority Senior Secured Term Loan B Due 2007

We must repay these term loans in 16 consecutive quarterly installments, commencing on October 15, 2003, and ending on July 15, 2007, the first fifteen of which installments will be 0.25% of the original principal amount of the notes. The final installment, on July 15, 2007, will be 96.25% of the original principal amount. Interest is payable on each quarterly payment date occurring after the closing date of July 16, 2003. At December 31, 2005, both the book and face value of these notes was $733.1 million. The effective interest rate, after amortization of deferred financing costs, was 9.6% and 7.8% per annum at December 31, 2005 and 2004, respectively.


	Second Priority Senior Secured Floating Rate Notes Due 2007

We must repay these notes in 16 consecutive quarterly installments, commencing on October 15, 2003, and ending on July 15, 2007, the first fifteen of which installments will be 0.25% of the original principal amount of the notes. The final installment, on July 15, 2007, will be 96.25% of the original principal amount. Interest is payable on each quarterly payment date occurring after the closing date of July 16, 2003. At December 31, 2005, both the book and face value of these notes was $488.8 million. The effective interest rate, after amortization of deferred financing costs, was 9.7% and 7.8% per annum at December 31, 2005 and 2004, respectively.


	8¹/2% Second Priority Senior Secured Notes Due 2010

Interest is payable on these notes on January 15 and July 15 of each year. The notes will mature on July 15, 2010. On or before July 15, 2006, on one or more occasions, we may use the proceeds from one or more public equity offerings to redeem up to 35% of the aggregate principal amount of the notes at the stated redemption price of 108.5%. At December 31, 2005, both the book and face value of these notes were $1,150.0 million. The effective interest rate, after amortization of deferred financing costs, was 8.9% per annum at December 31, 2005 and 2004.


	9⁷/8% Second Priority Senior Secured Notes Due 2011

Interest is payable on these notes on June 1 and December 1 of each year, commencing on June 1, 2004. The notes will mature on December 1, 2011, and are not redeemable prior to maturity. At December 31, 2005, the book and face value of these notes were $400.0 million. The effective interest rate, after amortization of deferred financing costs, was 10.7% per annum at December 31, 2005 and 2004.


	8³/4% Second Priority Senior Secured Notes Due 2013

Interest is payable on these notes on January 15 and July 15 of each year. The notes will mature on July 15, 2013. On or before July 15, 2006, on one or more occasions, we may use the proceeds from one or more public equity offerings to redeem up to 35% of the aggregate principal amount of the notes at the stated redemption price of 108.75%. At December 31, 2005, both the book and face value of these notes were $900.0 million. The effective interest rate, after amortization of deferred financing costs, was 9.0% per annum at December 31, 2005 and 2004.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Unsecured Senior Notes

We have completed a series of public and private debt offerings since 1994. Interest on such debt is payable quarterly or semiannually at specified rates. Deferred financing costs are amortized over the respective lives of the notes using the effective interest method. There are no sinking fund or mandatory redemptions of principal before the maturity dates of each series of debt. Certain of the Senior Note indentures limit our ability to incur additional debt, pay dividends, sell assets and enter into certain transactions. As of December 31, 2005, as a result of our bankruptcy filings, we were in default under each series of our Senior Notes. The effective interest rates for each of our Senior Notes outstanding at December 31, 2005, are consistent with the respective notes outstanding during 2004, unless otherwise noted.

Unsecured Senior Notes which are subject to compromise consist of the following as of December 31, 2005 and 2004, (in thousands):


												Fair Value as of
					First			December 31,				December 31, (3)
		Interest			Call
		Rates			Date			2005		2004		2005		2004

Unsecured Senior Notes
Senior Notes Due 2005			8¹/4	%			(2)	$	—	$	185,949	$	—	$	188,424
Senior Notes Due 2006			10¹/2	%		2001			139,205		152,695		57,625		151,359
Senior Notes Due 2006			7⁵/8	%			(1)		102,194		111,563		42,921		109,332
Senior Notes Due 2007			8³/4	%		2002			190,299		195,305		79,926		177,728
* Senior Notes Due 2007(4)			8³/4	%			(2)		—		165,572		—		150,671
Senior Notes Due 2008			7⁷/8	%			(1)		173,761		227,071		67,332		191,875
* Senior Notes Due 2008			8¹/2	%			(2)		—		1,581,539		—		1,347,472
* Senior Notes Due 2008(5)			8³/8	%			(2)		—		160,050		—		121,638
Senior Notes Due 2009			7³/4	%			(1)		180,602		221,539		75,853		177,231
Senior Notes Due 2010			8⁵/8	%			(2)		411,137		496,973		131,564		402,548
Senior Notes Due 2011			8¹/2	%			(2)		682,791		1,063,850		211,665		792,568
* Senior Notes Due 2011(6)			8⁷/8	%			(2)		—		232,511		—		167,989

	Total Unsecured Senior Notes							$	1,879,989	$	4,794,617	$	666,886	$	3,978,835


*	Due to Canadian Bankruptcy filing, these Senior Notes have been deconsolidated as of December 20, 2005, and appear for 2004 for historical purposes only. At December 31, 2005, the outstanding balances were: $170.9 million for the 8³/4% Senior Notes Due 2007; $1,422.7 million for the 8¹/2% Senior Notes Due 2008; $139.3 million for the 8³/8% Senior Notes Due 2008; and $210.0 million for the 8⁷/8 % Senior Notes Due 2011.

(1)	Not redeemable prior to maturity.

(2)	Redeemable by us at any time prior to maturity.

(3)	Represents the market values of the Senior Notes at the respective dates.

(4)	Issued and payable in Canadian dollars.

(5)	Issued and payable in Euros.

(6)	Issued and payable in Sterling.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Unsecured Senior Notes Due 2005

Interest on the 8¹/4% notes was payable semi-annually on February 15 and August 15. The notes matured on August 15, 2005, and the remaining outstanding 8¹/4 % notes were repaid at face value for a total of $182.1 million plus accrued interest. The effective interest rate, after amortization of deferred financing costs, was 8.7% per annum at each of December 31, 2005 and 2004.


	Unsecured Senior Notes Due 2006

Interest on the 10¹/2% notes is payable semi-annually on May 15 and November 15 each year. The notes mature on May 15, 2006, and are redeemable, at our option, at any time on or after May 15, 2001, at various redemption prices. In addition, we may redeem up to $63.0 million of the 10¹/2 % notes from the proceeds of any public equity offering. At December 31, 2005, both the book value and face value of these notes were $139.2 million. The effective interest rate, after amortization of deferred financing costs, was 11.2% per annum at December 31, 2005, and 11.0% per annum at December 31, 2004.

Interest on the 7⁵/8 % notes is payable semi-annually on April 15 and October 15 each year. These notes matured on April 15, 2006, and were not redeemable prior to maturity. At December 31, 2005, the book value and face value of these notes were $102.2 million. The effective interest rate, after amortization of deferred financing costs, was 8.3% and 8.0% per annum at December 31, 2005 and 2004, respectively.


	Unsecured Senior Notes Due 2007

Interest on the 8³/4 % notes maturing on July 15, 2007, is payable semi-annually on January 15 and July 15 each year. These notes are redeemable, at our option, at any time on or after July 15, 2002, at various redemption prices. In addition, we may redeem up to $96.3 million of these notes from the proceeds of any public equity offering. At December 31, 2005, both the book value and face value of these notes were $190.3 million. The effective interest rate, after amortization of deferred financing costs, was 9.3% and 9.2% per annum at December 31, 2005 and 2004, respectively.

Interest on the 8³/4 % notes issued by our subsidiary, ULC I, and maturing on October 15, 2007, is payable semi-annually on April 15 and October 15 each year. These notes may be redeemed prior to maturity, at any time in whole or from time to time in part, at a redemption price equal to the greater of (a) the “Discounted Value,” which equals the sum of the present values of all remaining scheduled payments of principal and interest, or (b) 100% of the principal amount plus accrued and unpaid interest to the redemption date. These notes are fully and unconditionally guaranteed by us. At December 31, 2005, the book value of these notes was $170.9 million. The effective interest rate, after amortization of deferred financing costs and the effect of cross currency swaps, was 9.4% at December 31, 2004. We deconsolidated most of our Canadian and other foreign subsidiaries, including ULC I, on December 20, 2005. See Note 10 for information regarding the Canadian deconsolidation.


	Unsecured Senior Notes Due 2008

Interest on the 7⁷/8 % notes is payable semi-annually on April 1 and October 1 each year. These notes mature on April 1, 2008, and are not redeemable prior to maturity. At December 31, 2004, the book value and face value of these notes were $173.8 million. The effective interest rate, after amortization of deferred financing costs, was 8.2% per annum at December 31, 2005, and 8.1% at December 31, 2004. The notes are fully and unconditionally guaranteed by us.

Interest on the 8¹/2 % notes issued by our subsidiary ULC I is payable semi-annually on May 1 and November 1 each year. The notes mature on May 1, 2008, or may be redeemed prior to maturity at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest plus a make-whole

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

premium. At December 31, 2005, the book value and face value of these notes were $1,422.7 million. The effective interest rate, after amortization of deferred financing costs, was 8.8% per annum at December 31, 2004. These notes are fully and unconditionally guaranteed by us. We deconsolidated most of our Canadian and other foreign subsidiaries, including ULC I, on December 20, 2005. See Note 10 for information regarding the deconsolidation.

Interest on the 8³/8 % notes issued by our subsidiary ULC II is payable semi-annually on April 15 and October 15 each year. These notes mature on October 15, 2008, or may be redeemed prior to maturity at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest plus a make-whole premium. These notes are fully and unconditionally guaranteed by us. At December 31, 2005, the book value of these notes was $139.3 million. The effective interest rate, after amortization of deferred financing costs and the effect of cross currency swaps, was 8.6% per annum at December 31, 2004. We deconsolidated most of our Canadian and other foreign subsidiaries, including ULC II, on December 20, 2005. See Note 10 for information regarding the deconsolidation.


	Unsecured Senior Notes Due 2009

Interest on these 7³/4 % notes is payable semi-annually on April 15 and October 15 each year. The notes mature on April 15, 2009, and are not redeemable prior to maturity. At December 31, 2005, the book value and face value of these notes were $180.6 million. The effective interest rate, after amortization of deferred financing costs, was 8.0% per annum at December 31, 2005 and 2004.


	Unsecured Senior Notes Due 2010

Interest on these 8⁵/8 % notes is payable semi-annually on August 15 and February 15 each year. The notes mature on August 15, 2010, and may be redeemed at any time prior to maturity at a redemption price equal to 100% of their principal amount plus accrued and unpaid interest plus a make-whole premium. At December 31, 2005, the book value and face value of these notes were $411.1 million. The effective interest rate, after amortization of deferred financing costs, was 8.8% per annum at December 31, 2005 and 2004.


	Unsecured Senior Notes Due 2011

Interest on the 8¹/2 % notes is payable semi-annually on February 15 and August 15 each year. The notes mature on February 15, 2011, and may be redeemed prior to maturity at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest plus a make-whole premium. At December 31, 2005, the book value and face value of these notes were $682.8 million. The effective interest rate, after amortization of deferred financing costs and the effect of interest rate swaps, was 9.0% and 8.4% per annum at December 31, 2005 and 2004, respectively.

Interest on the 8⁷/8% notes issued by our subsidiary ULC II is payable semi-annually on April 15 and October 15 each year. The 8⁷/8 % notes mature on October 15, 2011, and may be redeemed prior to maturity at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest plus a make-whole premium. These notes are fully and unconditionally guaranteed by us. At December 31, 2005, the book value of these notes was $210.0 million. The effective interest rate, after amortization of deferred financing costs and the effect of cross currency swaps, was 9.3% per annum at December 31, 2004. We deconsolidated most of our Canadian and other foreign subsidiaries, including ULC II, on December 20, 2005. See Note 10 for information regarding the deconsolidation.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Notes Payable and Other Liabilities — Related Party*

The Notes payable and other liabilities-related party balance at December 31, 2005, was $1.1 billion. Prior to our deconsolidation of the majority of our Canadian and other foreign subsidiaries on December 20, 2005, these liabilities were eliminated in consolidation. However, as a result of the deconsolidation, these liabilities are considered subject to compromise.


	*Provision for Allowable Claims*

In conjunction with the deconsolidation, we reviewed all intercompany guarantees. We identified guarantees by U.S. parent entities of debt (and accrued interest payable) of approximately $5.1 billion issued by certain of our deconsolidated Canadian entities as constituting probable allowable claims against the U.S. parent entities. Some of the guarantee exposures are redundant, such as the Calpine Corporation guarantee to ULC I security holders and the Calpine Corporation guarantee of QCH’s subscription agreement obligations associated with the hybrid notes structure in support of the ULC I Unsecured Notes. Under the guidance of SOP 90-7 “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code,” we determined the duplicative guarantees were probable of being allowed into the claim pool by the U.S. Bankruptcy Court. We accrued an additional amount of approximately $3.8 billion as reorganization items related to these duplicative guarantees.


25.	Provision for Income Taxes

The jurisdictional components of income (loss) from continuing operations and before provision for income taxes at December 31, 2005, 2004, and 2003, are as follows (in thousands):


	2005			2004			2003

U.S.	$	(9,971,966	)	$	(406,577	)	$	(92,335	)
International		(650,386	)		(248,420	)		52,630

Income (loss) before provision for income taxes	$	(10,622,352	)	$	(654,997	)	$	(39,705	)

The components of the provision (benefit) for income taxes for the years ended December 31, 2005, 2004, and 2003, consists of the following (in thousands):


				2005			2004			2003

Current:
	Federal			$	51,913		$	—		$	350
	State				5,410			1,198			—
	Foreign				78,431			1,296			—

		Total Current			135,754			2,494			350
Deferred:
	Federal				(779,490	)		(140,726	)		(44,661	)
	State				(67,573	)		24,184			(1,893	)
	Foreign				(30,089	)		(121,266	)		19,771

		Total Deferred			(877,152	)		(237,808	)		(26,783	)

			Total provision (benefit)	$	(741,398	)	$	(235,314	)	$	(26,433	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

A reconciliation of our overall actual effective tax rate (benefit) to the statutory U.S. Federal income tax rate of 35% to pretax income from continuing operations is as follows for the years ended December 31:


	2005			2004			2003

Expected tax (benefit) rate at United States statutory tax rate		(35.00	)%		(35.00	)%		(35.00	)%
State income tax (benefit), net of federal benefit		(0.58	)%		2.39	%		(2.03	)%
Depletion and other permanent items		(0.02	)%		0.50	%		1.41	%
Valuation allowances against future tax benefits		13.14	%		4.54	%		—
Tax credits		(0.01	)%		(0.21	)%		(4.10	)%
Foreign tax at rates other than U.S. statutory rate		1.55	%		(8.12	)%		(12.95	)%
Non-deductible reorganization items		13.27	%		—			—
Other, net (including U.S. tax on Foreign Income)		0.65	%		—			(13.93	)%

Effective income tax (benefit) rate		(7.00	)%		(35.90	)%		(66.60	)%

The components of the deferred income taxes, net as of December 31, 2005 and 2004, are as follows (in thousands):


				2005			2004

Deferred tax assets:
	Net operating loss and credit carryforwards			$	1,174,980		$	1,095,688
	Taxes related to risk management activities and SFAS No. 133				89,122			71,226
	Reorganization and impairments				837,762			—
	Other differences(1)				—			324,040

		Deferred tax assets before valuation allowance			2,101,864			1,490,954
	Valuation allowance				(1,639,222	)		(62,822	)

		Total Deferred tax assets			462,642			1,428,132

Deferred tax liabilities:
	Property differences				(706,661	)		(2,238,278	)
	Other differences(1)				(122,317	)		—

		Total Deferred tax liabilities			(828,978	)		(2,238,278	)

	Net deferred tax liability				(366,336	)		(810,146	)
	Less: Current portion: asset/(liability)(1)				(12,950	)		75,608

			Deferred income taxes, net of current portion	$	(353,386	)	$	(885,754	)


(1)	Current portion of net deferred income taxes are classified within other current liabilities in 2005 and other current assets in 2004 on the Consolidated Balance Sheets.

The NOL carryforward consists of federal carryforwards of approximately $2.9 billion which expire between 2023 and 2025. The federal NOL carryforwards available are subject to limitations on their annual usage. We have provided a valuation allowance of $1.6 billion on certain federal, state and foreign tax jurisdiction deferred tax assets to reduce the gross amount of these assets to the extent necessary to result in an amount that is more likely than not of being realized.

SFAS 109 requires all available evidence, both positive and negative, to 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

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sufficient taxable income of the appropriate character within the carryback or carryforward periods available under the tax law.

During the fourth quarter of 2005, we filed for bankruptcy and recorded significant restructuring charges. As a result, management determined that the realization of deferred tax assets from future profitable operations is not more likely than not as of December 31, 2005. Under these circumstances, deferred tax assets may only be recognized to the extent such benefits may be realized through future reversals of taxable temporary differences. We have performed such an analysis, and a valuation allowance has been provided against deferred tax assets to the extent they cannot be used to offset future income arising from the expected reversal of taxable differences.

Further, as per Section 382 of the Internal Revenue code which stipulates that certain transfers of our equity, or issuances of equity in connection with our restructuring, may impair our ability to utilize our federal income tax net operating loss carryforwards in the future. Under federal income tax law, a corporation is generally permitted to deduct from taxable income in any year net operating losses carried forward from prior years. As mentioned above, we have NOL carryforwards of approximately $2.9 billion as of December 31, 2005. Our ability to deduct NOL carryforwards could be subject to a significant limitation if we were to undergo an “ownership change” during or as a result of our Chapter 11 filings. During the pendency of these proceedings, the U.S. Bankruptcy Court has entered an order that places certain limitations on trading in our common stock or certain securities, including options, convertible into our common stock. However, we can provide no assurances that these limitations will prevent an “ownership change” or that our ability to utilize our net loss carryforwards may not be significantly limited as a result of our reorganization. Primarily due to the inability under generally accepted accounting principles to assume future profits and due to our reduced ability to implement tax planning strategies to utilize our NOLs while in bankruptcy, we concluded that valuation allowances on a portion of our deferred tax assets were required. In addition, we expect that a portion of the losses that we expect to incur in 2006 will not generate tax benefits and, therefore, additional valuation allowances may be required.

For the years ended December 31, 2005, 2004 and 2003, the net change in the valuation allowance was an increase (decrease) of $1,576 million, $43.5 million and $(7.3) million, respectively, and is primarily related to loss carryforwards that are not currently realizable.

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

Our foreign subsidiaries had no cumulative undistributed earnings at December 31, 2005. No tax benefit was provided on certain reorganization items attributable to the guarantee of deconsolidated foreign subsidiary debts due to the uncertainty of our ability to realize future tax deductions.

On October 22, 2004, the American Jobs Creation Act of 2004 was signed into law. This legislation contains a number of changes to the Internal Revenue Code. We have analyzed the law in order to determine its effects. The two most notable provisions are those dealing with the reduced tax rate on the repatriation of money from foreign operations and the deduction for domestic-based manufacturing activity. We determined that we qualify for both of these provisions. Since we are projecting that we will continue to generate NOLs for at least the next twelve months, we cannot take advantage of the domestic-based manufacturing deduction at this time.

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26.	Employee Benefit Plans


	*Retirement Savings Plans*

The Company maintains two defined contribution savings plans that are intended to be tax exempt under Sections 401(a) and 501(a) of the Internal Revenue Code. One plan generally covers employees who are not covered by a collective bargaining agreement (the “Non-Union Plan”), and the other plan covers employees who are covered by a collective bargaining agreement (the “Union Plan”). Employees eligible to participate in the Non-Union Plan may begin participating immediately upon hire. Employees eligible to participate in the Union Plan must complete four months of service before commencing participation. The Non-Union Plan provides for tax deferred salary deductions, after-tax employee contributions and employer profit-sharing contributions in cash of 4% of employees’ salaries up to IRS limits. The maximum employer contributions to the Non-Union Plan per employee was $8,400 for 2005, $8,200 for 2004 and $8,000 for 2003. Employer profit-sharing contributions to the Non-Union Plan in 2005, 2004, and 2003 totaled $12.3 million, $12.4 million, and $10.4 million, respectively. The Union Plan provides for tax deferred salary deductions, after-tax employee contributions, employer matching contributions of 50% of employee deferrals up to a maximum of 6% of compensation, and employer profit-sharing contributions in cash of 6% of employees’ salaries up to IRS limits. The maximum employer contributions to the Union Plan per employee was $18,900 for 2005, $18,450 for 2004 and $18,000 for 2003. Employer matching contributions to the Union Plan in 2005, 2004, and 2003 totaled $107,093, $117,396, and $90,914, respectively and employer profit-sharing contributions to the Union Plan in 2005, 2004, and 2003 totaled $250,734, $271,212, and $216,739, respectively.


	*2000 Employee Stock Purchase Plan*

We adopted the 2000 ESPP in May 2000; the ESPP was suspended effective November 29, 2005. Prior to the suspension, eligible employees could purchase, in the aggregate, up to 28,000,000 shares of common stock at semi-annual intervals through periodic payroll deductions. The purchase price for shares under the ESPP was 85% of the lower of (i) the fair market value of the common stock on the participant’s entry date into the offering period, or (ii) the fair market value on the semi-annual purchase date. The purchase price discount was significant enough to cause the ESPP to be considered compensatory under SFAS No. 123. As a result, awards under the ESPP are accounted for as stock-based compensation in accordance with SFAS No. 123. Purchases under the ESPP were limited to a maximum value of $25,000 per calendar year based on the Internal Revenue Code Section 423 limitation. Shares could be purchased on May 31 and November 30 of each year until termination of the ESPP on May 31, 2010, limited to 2,400 shares per purchase interval. Under the ESPP, 2,408,378 and 4,545,858 shares were issued at a weighted average fair value of $2.53 and $3.26 per share in 2005 and 2004, respectively. As a result of the suspension of the ESPP effective November 29, 2005, no shares were issued on the scheduled purchase date of November 30, 2005. See Note 2 for information related to our stock-based compensation expense.


	*1996 Stock Incentive Plan*

We adopted the SIP in September 1996. The SIP succeeded our previously adopted stock option program. Prior to our adoption of SFAS No. 123 prospectively on January 1, 2003, we accounted for the SIP under APB Opinion No. 25, under which no compensation cost was recognized through December 31, 2002. See Note 2 for the effects the SIP would have on our financial statements if stock-based compensation had been accounted for under SFAS No. 123 prior to January 1, 2003.

For the year ended December 31, 2005, we granted options to purchase 8,242,710 shares of common stock and issued 1,247,427 restricted shares of which 946,222 shares were unvested and 301,205 were cancelled. Over the life of the SIP, options exercised have equaled 5,353,308, leaving 37,090,268 granted and not yet exercised. Under the SIP, the option exercise price generally equals the stock’s fair market value on

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date of grant. The SIP options generally vest ratably over four years with a maximum exercise period of 7 or 10 years after grant date.

In connection with the merger with Encal in 2001, we adopted Encal’s existing stock option plan. All outstanding options under the Encal stock option plan were converted at the time of the merger into options to purchase our common stock. No new options may be granted under the Encal stock option plan. As of December 31, 2005, there were no options granted and exercisable under the Encal and Calpine 1992 stock option plans due to expiration of option awards thereunder during 2005.

Changes in options outstanding, granted, exercisable and canceled during the years 2005, 2004, and 2003, under the option plans of Calpine and Encal are as follows:


								Weighted
		Available for			Outstanding			Average
		Option or			Number of			Exercise
		Award			Options			Price

Outstanding January 1, 2003			10,161,914			30,104,947		$	9.30
	Granted		(5,998,585	)		5,998,585			3.93
	Exercised		—			(536,730	)		2.01
	Canceled		1,725,221			(1,725,221	)		13.59
	Canceled options(1)		(72,470	)		—			—
	Share awards		—			(3,150	)		4.03

Outstanding December 31, 2003			5,816,080			33,838,431		$	8.25
	Additional shares reserved		21,000,000			—			—
	Granted		(5,660,262	)		5,660,262			5.47
	Exercised		—			(3,629,824	)		0.83
	Canceled		1,089,032			(1,089,032	)		18.21
	Canceled options(1)		(38,945	)		—			—
	Share awards		—			(1,980	)		4.33

Outstanding December 31, 2004			22,205,905			34,777,857			8.42
	Granted		(8,242,710	)		8,242,710			3.38
	Exercised		—			(1,679,650	)		1.25
	Canceled		4,250,649			(4,250,649	)		8.58
	Canceled options(1)		(425,232	)		—			—
	Restricted award shares		(1,247,427	)		—			3.32
	Canceled restricted award shares		301,205			—			—

Outstanding December 31, 2005			16,842,390			37,090,268		$	7.62
Options exercisable:
	December 31, 2003					22,953,781			8.02
	December 31, 2004					22,949,497			9.30
	December 31, 2005					27,185,497			8.78


(1)	Represents cessation of options awarded under the Encal and the Calpine 1992 stock option plans.

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The following table summarizes information concerning outstanding and exercisable options at December 31, 2005:


			Weighted
			Average		Weighted				Weighted
	Number of		Remaining		Average		Number of		Average
	Options		Contractual		Exercise		Options		Exercise
Range of Exercise Prices	Outstanding		Life in Years		Price		Exercisable		Price

$ 0.645 - $ 2.640		3,916,638		2.42	$	2.144		3,831,638	$	2.134
$ 2.650 - $ 3.320		6,222,204		6.16		3.317		1,656,864		3.315
$ 3.440 - $ 3.860		4,502,400		3.75		3.841		4,490,900		3.842
$ 3.910 - $ 3.980		4,735,074		7.03		3.980		3,147,397		3.980
$ 4.010 - $ 5.240		2,670,284		6.32		5.146		2,127,788		5.123
$ 5.330 - $ 5.560		4,626,019		8.15		5.560		2,084,052		5.559
$ 5.565 - $ 9.955		5,972,331		4.84		8.715		5,542,057		8.800
$10.000 - $48.150		4,313,821		4.45		27.656		4,174,274		28.084
$48.188 - $56.920		129,647		5.24		51.333		128,677		51.320
$56.990 - $56.990		1,850		5.33		56.990		1,850		56.990

		37,090,268		5.43		7.623		27,185,497		8.778


27.	Stockholders’ Equity (Deficit)


	*Common Stock*

Public trading of our common stock commenced on September 20, 1996, on the NYSE under the symbol “CPN.” Prior to that, there was no public market for our common stock. On December 2, 2005, the NYSE notified us that it was suspending trading in our common stock prior to the opening of the market on December 6, 2005, and, on December 5, 2005, the NYSE issued a press release stating that any application by the NYSE to the SEC to delist our common stock was pending the completion of applicable procedures. The SEC granted the NYSE’s application to delist our common stock effective March 15, 2006. Since December 6, 2005, our common stock has traded under the symbol “CPNLQ.PK” over-the-counter on the Pink Sheets. Certain restrictions in trading are imposed under a U.S. Bankruptcy Court order that requires certain direct and indirect holders (or persons who may become direct or indirect holders) of our common stock to provide the U.S. Debtors, their counsel and the U.S. Bankruptcy Court advance notice of their intent to buy or sell our common stock (including options to acquire common stock and other equity linked instruments) prior to effectuating any such transfer. There were approximately 2,345 common stockholders of record at December 31, 2005. No dividends were paid for the years ended December 31, 2005 and 2004.

Increase in Authorized Shares — On June 2, 2004, after receiving shareholder approval at our 2004 annual meeting, we filed amended certificates with the Delaware Secretary of State to increase the number of authorized shares of common stock to 2,000,000,000 from 1,000,000,000.

On September 30, 2004, in conjunction with the 2014 Convertible Notes offering, we entered into a ten-year Share Lending Agreement with DB London, under which we loaned DB London 89 million shares of newly issued Calpine common stock. DB London sold the 89 million shares on September 30, 2004, at a price of $2.75 per share in a registered public offering. We did not receive any of the proceeds of the public offering. As discussed in Note 22, the requirement to return these shares is considered to be a prepaid forward purchase contract and we analogize to the guidance in SFAS No. 150 so that the 89 million shares of common stock subject to the Share Lending Agreement are excluded from the EPS calculation. See Note 24 for more information regarding the 2014 Convertible Notes offering and the Share Lending Agreement.

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On June 28, 2005, we issued 27.5 million shares of Calpine common stock to extinguish a portion of our 2014 Convertible Notes. See Note 24 for further information regarding this transaction.


	*Preferred Stock and Preferred Share Purchase Rights*

Preferred Shares Authorized — Under our certificate of incorporation we are authorized to issue 10,000,000 shares of preferred stock. On December 31, 2005, there were no shares of our preferred stock outstanding or issuable.

On June 5, 1997, we adopted a stockholders’ rights plan. The rights plan was amended on September 19, 2001, September 28, 2004, and March 18, 2005. To implement the rights plan, we had declared a dividend of one preferred share purchase right for each outstanding share of our common stock held of record as of June 18, 1997, and issued one preferred share purchase right with respect to each share of our common stock that became outstanding thereafter until the rights expired on May 1, 2005, as described below. The rights would have become exercisable and traded independently from our common stock upon the public announcement of the acquisition by a person or group of 15% or more of our common stock, or ten days after commencement of a tender or exchange offer that would result in the acquisition of 15% or more of our common stock. The rights expired on May 1, 2005, pursuant to the March 18, 2005, amendment to the rights plan. Accordingly, on December 31, 2005, there were no rights outstanding.


28.	Customers


	*Significant Customer*

In each of 2005, 2004 and 2003, we had one significant customer that accounted for more than 10% of our annual consolidated revenues: CDWR. See “— California Department of Water Resources” below for a discussion of our contracts with CDWR.

For the years ended December 31, 2005, 2004, and 2003, CDWR revenues were $1,225.5 million, $1,148.0 million and $1,219.7 million, respectively.

Our receivables from CDWR at December 31, 2005, 2004 and 2003, were $102.4 million, $98.5 million and $97.8 million, respectively.

We are seeking to reject one of the CDWR contracts, referred to as Contract 2, related to two of our California facilities, Delta Energy Center and Los Medanos Energy Center. For a discussion of the status of the proceedings regarding our notice of rejection, see Note 3.


	*Counterparty Exposure*

Our customer and supplier base is concentrated within the energy industry. Additionally, we have exposure to trends within the energy industry, including declines in the creditworthiness of our marketing counterparties. Currently, certain of our counterparties within the energy industry have below investment grade credit ratings. However, we do not currently have any significant exposure to counterparties that are not paying on a current basis.


	*California Department of Water Resources*

In 2001, California adopted legislation permitting it to issue long-term revenue bonds to fund wholesale purchases of power by CDWR. The bonds will be repaid with the proceeds of payments by retail power customers over time. CES and CDWR entered into four long-term supply contracts during 2001. We have recorded deferred revenue in connection with one of the long-term power supply contracts (“Contract 3”). All

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of our accounts receivables from CDWR are current, with the exception of approximately $1.0 million, which we are working to resolve with the customer.

In early 2002, the CPUC and the California EOB filed complaints under Section 206 of the FPA with the FERC alleging that the prices and terms of the long-term contracts with CDWR were unjust and unreasonable and contrary to the public interest (the “206 Complaint”). The contracts entered into by CES and CDWR were subject to the 206 Complaint.

On April 22, 2002, we announced that we had renegotiated CES’s long-term power contracts with CDWR and settled the 206 Complaint. The Office of the Governor, the CPUC, the EOB and the Attorney General for the State of California all endorsed the renegotiated contracts and dropped all pending claims against us and our affiliates, including any efforts by the CPUC and the EOB to seek refunds from us and our affiliates through the FERC California Refund Proceedings. In connection with the renegotiation, we agreed to pay $6 million over three years to the Attorney General to resolve any and all possible claims. See Note 33 for additional information with respect to California Power Market matters.

As noted above, we are seeking to reject CDWR Contract 2, which requires us to provide energy from two of our California facilities, Delta Energy Center and Los Medanos Energy Center, to CDWR through 2009. For a discussion of the status of the proceedings regarding our notice of rejection, see Note 3. CDWR Contract 4, which related to our Los Esteros facility, expired by its terms on March 6, 2006, and is no longer in effect.


	*Lease Income*

We record income under PPAs that are accounted for as operating leases under SFAS No. 13, “Accounting for Leases,” and EITF Issue No. 01-08. For income statement presentation purposes, this income is classified within E&S revenue in the Consolidated Statements of Operations.

The total contractual future minimum lease payments for these PPAs are as follows (in thousands):


2006		$	175,349
2007			213,431
2008			285,386
2009			288,516
2010			291,693
Thereafter			2,553,024

	Total	$	3,807,399


	*Credit Evaluations*

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

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29.	Derivative Instruments


	*Commodity Derivative Instruments*

As an IPP primarily focused on generation of electricity using gas-fired turbines, our natural physical commodity position is “short” fuel (i.e., natural gas consumer) and “long” power (i.e., electricity seller). To manage forward exposure to price fluctuation in these and (to a lesser extent) other commodities, we enter into derivative commodity instruments. We enter into commodity instruments to convert floating or indexed electricity and gas (and to a lesser extent oil and refined product) prices to fixed prices in order to lessen our vulnerability to reductions in electricity prices for the electricity we generate, and to increases in gas prices for the fuel we consume in our power plants. The hedging, balancing and optimization activities that we engage in are directly related to our asset-based business model of owning and operating gas-fired electric power plants and are designed to protect our “spark spread” (the difference between our fuel cost and the revenue we receive for our electric generation). We hedge exposures that arise from the ownership and operation of power plants and related sales of electricity and purchases of natural gas. We also utilize derivatives to optimize the returns we are able to achieve from these assets. From time to time we have entered into contracts considered energy trading contracts under EITF Issue No. 02-03. However, our traders have low capital at risk and value at risk limits for energy trading, and, at any given time, our risk management policy limits our net sales of power to our generation capacity and limits our net purchases of gas to our fuel consumption requirements on a total portfolio basis. This model is markedly different from that of companies that engage in significant commodity trading operations that are unrelated to underlying physical assets. Derivative commodity instruments are accounted for under the requirements of SFAS No. 133.

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


	*Interest Rate and Currency Derivative Instruments*

We also enter into various interest rate swap agreements to hedge against changes in floating interest rates on certain of our project financing facilities and to adjust the mix between fixed and floating rate debt in our capital structure to desired levels. Certain of the interest rate swap agreements effectively convert floating rates into fixed rates so that we can predict with greater assurance what our future interest costs will be and protect ourselves against increases in floating rates.

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

Also, in conjunction with our capital market activities, we enter into various interest rate swap agreements to hedge against the change in fair value on certain of our fixed rate Senior Notes. These interest rate swap agreements effectively convert fixed rates into floating rates so that we can predict with greater assurance what the fair value of our fixed rate Senior Notes will be and protect ourselves against unfavorable future fair value movements.

Additionally, from time-to-time we have and may in the future enter into various foreign currency swap agreements to hedge against changes in exchange rates on certain of our Senior Notes denominated in

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currencies other than the U.S. dollar. Such foreign currency swaps effectively convert floating exchange rates into fixed exchange rates so that we can predict with greater assurance what our U.S. dollar cost will be for purchasing foreign currencies to satisfy the interest and principal payments on these Senior Notes.


	*Summary of Derivative Values*

The table below reflects the amounts (in thousands) that are recorded as assets and liabilities at December 31, 2005, for our derivative instruments:


						Commodity
			Interest Rate			Derivative			Total
			Derivative			Instruments			Derivative
			Instruments			Net			Instruments

Current derivative assets			$	1,089		$	488,410		$	489,499
Long-term derivative assets				4,176			710,050			714,226

	Total assets		$	5,265		$	1,198,460		$	1,203,725

Current derivative liabilities			$	2,334		$	726,560		$	728,894
Long-term derivative liabilities				7,370			911,714			919,084

	Total liabilities		$	9,704		$	1,638,274		$	1,647,978

		Net derivative assets (liabilities)	$	(4,439	)	$	(439,814	)	$	(444,253	)

Of our net derivative assets, $179.0 million and $28.2 million are net derivative assets of PCF and CNEM, respectively, each of which is an entity with its existence separate from us and other subsidiaries of ours, as discussed more fully in Note 14. We fully consolidate CNEM and we record the derivative assets of PCF in our balance sheet.

On March 31, 2005, Deer Park, an indirect, wholly owned subsidiary of Calpine, entered into agreements to sell power to and buy gas from MLCI. The agreements cover 650 MW of Deer Park’s capacity, and deliveries under the agreements began on April 1, 2005, and continue through December 31, 2010. To assure performance under the agreements, Deer Park granted MLCI a collateral interest in the Deer Park Energy Center. The power and gas agreements contain terms as follows:

Power Agreements — Under the terms of the power agreements, Deer Park will sell power to MLCI at fixed and index prices with a discount to prevailing market prices at the time the agreements were executed. In exchange for the discounted pricing, Deer Park received an initial cash payment of $195.8 million, net of $17.3 million in transaction costs during the first quarter of 2005, and subsequently received additional cash payments of $76.4 million, net of $2.9 million in transaction costs, as additional power transactions were executed with discounts to prevailing market prices. The cash received by Deer Park is sufficiently small compared to the amount that would be required to fully prepay for the power to be delivered under the agreements that the agreements have been determined to be derivatives in their entirety under SFAS No. 133. The value of the derivative liability at December 31, 2005, was $284.2 million. As Deer Park makes power deliveries under the agreements, the liability will be satisfied and, accordingly, the derivative liability will be reduced, and Deer Park will record corresponding gains in income, supplementing the revenues recognized based on discounted pricing as deliveries take place. The upfront payments received by Deer Park from the transaction are recorded as cash flows from financing activity in accordance with guidance contained in SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” SFAS No. 149 requires that companies present cash flows from derivatives that contain an “other-than-insignificant” financing element as cash flows from financing activities. Under SFAS No. 149, a contract that

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at its inception includes off-market terms, or requires an up-front cash payment, or both is deemed to contain an “other-than-insignificant” financing element.

Gas Agreements — Under the terms of the gas agreements, Deer Park will receive quantities of gas such that, when combined with fuel supply provided by Deer Park’s steam host, Deer Park will have sufficient contractual fuel supply to meet the fuel needs required to generate the power under the power agreements. Deer Park will pay both fixed and variable prices under the gas agreements. To the extent that Deer Park receives fixed prices for power, Deer Park will receive a volumetrically proportionate quantity of gas supply at fixed prices thereby fixing the spread between the revenue Deer Park receives under the fixed price power sales and the cost it pays under the fixed price gas purchases. To the extent that Deer Park receives index-based prices for its power sales, it will pay index-based prices for a volumetrically proportionate amount of its gas supply.


	*Relationship of Net Derivative Assets or Liabilities to AOCI*

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


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

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

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

Below is a reconciliation of our net derivative liabilities to our accumulated other comprehensive loss, net of tax from derivative instruments at December 31, 2005 (in thousands):


Net derivative liabilities		$	(444,253	)
Derivatives not designated as cash flow hedges and recognized hedge ineffectiveness			549,696
Cash flow hedges terminated prior to maturity			(353,293	)
Deferred tax asset attributable to accumulated other comprehensive loss on cash flow hedges			89,123

	Accumulated other comprehensive loss from derivative instruments, net of tax(1)	$	(158,727	)


(1)	Amount represents one portion of our total AOCI balance.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The asset and liability balances for our commodity derivative instruments represent the net totals after offsetting certain assets against certain liabilities under the criteria of FIN 39. For a given contract, FIN 39 will allow the offsetting of assets against liabilities so long as four criteria are met: (1) each of the two parties under contract owes the other determinable amounts; (2) the party reporting under the offset method has the right to set off the amount it owes against the amount owed to it by the other party; (3) the party reporting under the offset method intends to exercise its right to set off; and (4) the right of set-off is enforceable by law. The table below reflects both the amounts (in thousands) recorded as assets and liabilities by us and the amounts that would have been recorded had our commodity derivative instrument contracts not qualified for offsetting as of December 31, 2005:


			December 31, 2005

			Gross			Net

Current derivative assets			$	2,612,436		$	488,410
Long-term derivative assets				1,300,990			710,050

	Total derivative assets		$	3,913,426		$	1,198,460

Current derivative liabilities			$	2,850,587		$	726,560
Long-term derivative liabilities				1,502,653			911,714

	Total derivative liabilities		$	4,353,240		$	1,638,274

		Net commodity derivative (liabilities)	$	(439,814	)	$	(439,814	)

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

The tables below reflect the impact of unrealized mark-to-market gains (losses) on our pre-tax earnings, both from cash flow hedge ineffectiveness and from the changes in market value of derivatives not designated as hedges of cash flows, for the years ended December 31, 2005, 2004 and 2003, respectively (in thousands):


		2005

		Hedge			Undesignated
		Ineffectiveness			Derivatives			Total

Natural gas derivatives(1)		$	(1,951	)	$	(9,042	)	$	(10,993	)
Power derivatives(1)			(4,638	)		(79,467	)		(84,105	)
Interest rate derivatives(2)			161			(2,527	)		(2,366	)
Currency derivatives			—			—			—

	Total	$	(6,428	)	$	(91,036	)	$	(97,464	)


		2004

		Hedge		Undesignated
		Ineffectiveness		Derivatives			Total

Natural gas derivatives(1)		$	5,827	$	(10,700	)	$	(4,873	)
Power derivatives(1)			1,814		(31,666	)		(29,852	)
Interest rate derivatives(2)			1,492		6,035			7,527
Currency derivatives			—		(12,897	)		(12,897	)

	Total	$	9,133	$	(49,228	)	$	(40,095	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


		2003

		Hedge			Undesignated
		Ineffectiveness			Derivatives			Total

Natural gas derivatives(1)		$	3,153		$	7,768		$	10,921
Power derivatives(1)			(5,001	)		(56,693	)		(61,694	)
Interest rate derivatives(2)			(974	)		—			(974	)
Currency derivatives			—			—			—

	Total	$	(2,822	)	$	(48,925	)	$	(51,747	)


(1)	Represents the unrealized portion of mark-to-market activity on gas and power transactions. The unrealized portion of mark-to-market activity is combined with the realized portions of mark-to-market activity and presented in the Consolidated Statements of Operations as mark-to-market activities, net.

(2)	Recorded within Other Income.

The table below reflects the contribution of our cash flow hedge activity to pre-tax earnings based on the reclassification adjustment from OCI to earnings for the years ended December 31, 2005, 2004 and 2003, respectively (in thousands):


		2005			2004			2003

Natural gas and crude oil derivatives		$	136,767		$	58,308		$	40,752
Power derivatives			(521,119	)		(128,556	)		(79,233	)
Interest rate derivatives			(16,984	)		(17,625	)		(27,727	)
Foreign currency derivatives			(4,188	)		(2,015	)		10,588

	Total derivatives	$	(405,524	)	$	(89,888	)	$	(55,620	)

As of December 31, 2005, the maximum length of time over which we were hedging our exposure to the variability in future cash flows for forecasted transactions was 3 and 11 years, for commodity and interest rate derivative instruments, respectively. We estimate that pre-tax losses of $185 million would be reclassified from AOCI into earnings during the twelve months ended December 31, 2006, as the hedged transactions affect earnings assuming constant gas and power prices, interest rates, and exchange rates over time; however, the actual amounts that will be reclassified will likely vary based on the probability that gas and power prices as well as interest rates and exchange rates will, in fact, change. Therefore, management is unable to predict what the actual reclassification from OCI to earnings (positive or negative) will be for the next twelve months.

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


																	2011 &
		2006			2007			2008			2009			2010			After			Total

Gas OCI		$	305,259		$	11,800		$	—		$	—		$	—		$	—		$	317,059
Power OCI			(484,439	)		(33,757	)		(5,956	)		(4,336	)		(3,037	)		—			(531,525	)
Interest rate OCI			(5,798	)		(5,267	)		(4,516	)		(3,989	)		(2,265	)		(11,550	)		(33,385	)
Foreign currency OCI			—			—			—			—			—			—			—

	Total pre-tax OCI	$	(184,978	)	$	(27,224	)	$	(10,472	)	$	(8,325	)	$	(5,302	)	$	(11,550	)	$	(247,851	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


30.	Earnings (Loss) per Share

Basic loss per common share was computed by dividing net loss by the weighted average number of common shares outstanding for the respective periods. The dilutive effect of the potential exercise of outstanding options to purchase shares of common stock is calculated using the treasury stock method. The dilutive effect of the assumed conversion of certain convertible securities into our common stock is based on the dilutive common share equivalents and the after tax distribution expense avoided upon conversion. The reconciliation of basic and diluted loss per common share is shown in the following table (in thousands, except per share data).


			For the Years Ended December 31,

			2005								2004								2003

			Net								Net								Net
			Income			Shares		EPS			Income			Shares		EPS			Income			Shares		EPS

Basic earnings (loss) per common share:
	Income (loss) before discontinued operations and cumulative effect of a change in accounting principle		$	(9,880,954	)		463,567	$	(21.32	)	$	(419,683	)		430,775	$	(0.97	)	$	(13,272	)		390,772	$	(0.03	)
	Discontinued operations, net of tax			(58,254	)		—		(0.12	)		177,222			—		0.41			114,351			—		0.29
	Cumulative effect of a change in accounting principle, net of tax			—			—		—			—			—		—			180,943			—		0.46

		Net income (loss)	$	(9,939,208	)		463,567	$	(21.44	)	$	(242,461	)		430,775	$	(0.56	)	$	282,022			390,772	$	0.72

Diluted earnings (loss) per common share:
	Common shares issuable upon exercise of stock options using treasury stock method						—								—								5,447

	Income (loss) before discontinued operations and cumulative effect of a change in accounting principle		$	(9,880,954	)		463,567	$	(21.32	)	$	(419,683	)		430,775	$	(0.97	)	$	(13,272	)		396,219	$	(0.03	)
	Discontinued operations, net of tax			(58,254	)		—		(0.12	)		177,222			—		0.41			114,351			—		0.29
	Cumulative effect of a change in accounting principle, net of tax			—			—		—			—			—		—			180,943			—		0.45

		Net income (loss)	$	(9,939,208	)		463,567	$	(21.44	)	$	(242,461	)		430,775	$	(0.56	)	$	282,022			396,219	$	0.71

We incurred losses before discontinued operations for the year ended December 31, 2005 and losses before discontinued operations and cumulative effect of a change in accounting principle for the year ended December 31, 2004. As a result, basic shares were used in the calculations of fully diluted loss per share for these periods, under the guidelines of SFAS No. 128 as using the basic shares produced the more dilutive effect on the loss per share. Potentially convertible securities, shares to be purchased under our ESPP and unexercised employee stock options to purchase a weighted average of 0.1 million, 47.2 million and 127.1 million shares of our common stock were not included in the computation of diluted shares outstanding during the years ended December 31, 2005, 2004 and 2003, respectively, because such inclusion would be anti-dilutive.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended December 31, 2005, 2004 and 2003, approximately 0.1 million, 8.9 million and 61.0 million, respectively, weighted common shares of our outstanding 2006 Convertible Notes were excluded from the diluted EPS calculations as the inclusion of such shares would have been anti-dilutive.

In connection with the convertible debentures payable to Trust I, Trust II and Trust III, net of repurchases on a weighted average basis, there were 4.6 million, 34.4 million and 44.1 million common shares potentially issuable, respectively, that were excluded from the diluted EPS calculation for the years ended December 31, 2005, 2004 and 2003 as their inclusion would be anti-dilutive. The convertible debentures payable to Trust III were redeemed in full on July 13, 2005, and the convertible debentures payable to Trusts I and II were redeemed in full on October 20, 2004.

For the years ended December 31, 2005, 2004 and 2003, under the net share settlement method and in accordance with the new guidance of EITF 04-08, there were no shares potentially issuable and thus potentially included in the diluted EPS calculation under our 2023 Convertible Notes, 2014 Convertible Notes and 2015 Convertible Notes because our closing stock price at each period end was below the conversion price. However, subject to potential compromise of these convertible notes pursuant to our bankruptcy cases, in future reporting periods after we have emerged from bankruptcy, if the closing price of our common stock is above the conversion price for a series of these convertible notes and we have income before discontinued operations and cumulative effect of change in accounting principle, as set forth in Note 24, the holders of such series of convertible notes would be entitled, upon conversion, to receive the conversion value of such convertible notes in cash up to the applicable principal amount of the note, and in a number of shares of our common stock for the conversion value in excess of such principal amount. In addition, if any of such convertible notes were converted during the pending of our bankruptcy cases, we would be required to deliver the par value solely in shares of our common stock. The maximum potential shares issuable under the conversion provisions of these convertible notes would be as presented below, assuming that 100% of each series of such convertible note remains outstanding following our emergence from bankruptcy. The actual number of potential shares issuable will depend on the potential compromise of these convertible notes pursuant to our bankruptcy cases and the closing price of our common stock at conversion.


	•	2023 Convertible Notes — If our closing stock price is above the instrument’s conversion price of $6.50, a maximum of approximately 97.5 million shares would be included (if dilutive) in the diluted EPS calculation;

	•	2015 Convertible Notes — If our closing stock price is above the instrument’s conversion price of $4.00, a maximum of approximately 163.0 million shares would be included (if dilutive) in the diluted EPS calculation;

	•	2014 Convertible Notes — If our closing stock price is above the instrument’s conversion price of $3.85, a maximum of approximately 139.8 million shares would be included (if dilutive) in the diluted EPS calculation;

For the year ended December 31, 2005, 1.2 million weighted average common shares of our contingently issuable (unvested) restricted stock was excluded from the calculation of diluted EPS because our closing stock price had not reached the price at which the shares vest, and as discussed above, inclusion would be anti-dilutive.

As discussed in Note 24, in conjunction with the offering of the 2014 Convertible Notes in September 2004, we entered into a ten-year Share Lending Agreement with DB London, under which we loaned DB London 89 million newly issued shares of our common stock. We excluded the 89 million shares of common stock subject to the Share Lending Agreement from the EPS calculation.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

See Note 2 for a discussion of the potential impact of SFAS No. 128-R on the calculation of diluted EPS.

31. Commitments and Contingencies

A. LTSA Cancellations — On July 5, 2005, we executed an agreement with Siemens-Westinghouse to settle various matters related to certain warranty disputes and to terminate certain LTSAs. We received approximately $25.5 million as a net settlement payment related to these matters. Consequently, $10.8 million was recorded as a reduction in plant operating expense relating to warranty recoveries and contract settlements of prior period repair expenses. The remaining settlement proceeds were applied as a reduction to capitalized turbine costs.

On July 7, 2005, we announced that we had entered into a 15-year Master Products and Services Agreement with GE. A related agreement replaces the nine remaining LTSAs covering our GE 7FA turbine fleet. We expect to benefit from improved power plant performance and O&M flexibility to service our plants to further lower costs. Historically, GE provided full-service turbine maintenance for a select number of our power plants. Under the new agreement, we will supplement our operations with a variety of GE services. As of December 31, 2005, we operate multiple power plants that are powered by GE gas turbines, representing approximately 12,824 MW of capacity. We recorded LTSA cancellation expense of $34.1 million during the year 2005.

B. Turbines — The table below sets forth future turbine payments for construction and development projects, as well as for unassigned turbines. It includes previously delivered turbines and payments required for the potential cancellation costs of the remaining 9 gas and 13 steam turbines pursuant to restructurings in 2003 of turbine purchase agreements. The table does not include payments that would result if we were to release for manufacturing any of these remaining 22 turbines.


Year		Total

		(In thousands)
2006		$	17,578
2007			4,432
2008			2,699

	Total	$	24,709

The following table sets forth an analysis of our turbine restructuring reserves from January 1, 2003, to December 31, 2005 (in thousands):


		Turbine
		Restructuring
		Accrual

As of January 1, 2003		$	24,824
	Payments		(15,805	)
	Adjustments to accrual		(473	)

As of December 31, 2003		$	8,546
	Payments		(4,498	)

As of December 31, 2004		$	4,048
	Payments		—

As of December 31, 2005		$	4,048

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

C. Other Restructuring Charges — In fiscal years 2003, 2004 and 2005, in connection with management’s plan to reduce costs and improve operating efficiencies, we recorded restructuring charges primarily comprised of severance and benefits related to the involuntary termination of employees and charges related to the vacancy of a number of facilities.

The following table sets forth our restructuring reserves relating to our vacancy of various facilities from January 1, 2003, to December 31, 2005 (in thousands):


								Total
		Accrued Rent-			Accrued Rent-			Accrued Rent
		Short-Term			Long-Term			Liability

As of January 1, 2003		$	4,009		$	2,370		$	6,379
	Additions		2,062			8,341			10,403
	Reclass from long-term		825			(825	)		—
	Amortization		(3,718	)		(162	)		(3,880	)
	Adjustments to accrual		(166	)		195			29

As of December 31, 2003		$	3,012		$	9,919		$	12,931
	Additions		1,313			354			1,667
	Reclass from long-term		2,512			(2,512	)		—
	Amortization		(2,585	)		—			(2,585	)
	Accretion		—			1,325			1,325
	Adjustments to accrual		12			54			66

As of December 31, 2004		$	4,264		$	9,140		$	13,404
	Additions		281			1,373			1,654
	Reclass from long-term		3,300			(3,300	)		—
	Amortization		(4,156	)		—			(4,156	)
	Accretion		—			982			982
	Adjustments to accrual (primarily Canadian and other foreign subsidiaries deconsolidation)		(837	)		(1,121	)		(1,958	)

As of December 31, 2005		$	2,852		$	7,074		$	9,926

The 2003 charge of $10.4 million was recorded in the “Sales, general and administrative expense” line item on the Consolidated Statements of Operations for the year ended December 31, 2003. In 2004, $1.5 million of the vacancy related charges were recorded in the “Discontinued operations, net” line and $0.1 million in the “Sales, general and administrative expense” line of the Consolidated Statements of Operations for the year ended December 31, 2004. The $1.7 million of vacancy related changes for the year ended December 31, 2005, were recorded in the “Sales, general and administrative expense” line item on the Consolidated Statements of Operations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table sets forth our restructuring reserves relating to our involuntary termination of employees from January 1, 2003, to December 31, 2005 (in thousands):


	Severance
	Liability

January 1, 2003	$	1,556
Additions		3,914
Payments		(5,191	)
Adjustments		414

As of December 31, 2003	$	693
Additions		6,154
Payments		(5,292	)
Adjustments		(1,555	)

As of December 31, 2004	$	—
Additions		6,241
Payments		(598	)
Adjustments		—

As of December 31, 2005	$	5,643

Severance-related charges of $1.1 million were recorded in the “Plant operating expense” line with the remaining $2.8 million in the “Selling, general and administrative expense” line of the Consolidated Statements of Operations for the year ended December 31, 2003. Severance-related charges of $6.2 million were recorded in the “Discontinued operations, net” line of the Consolidated Statements of Operations for the year ended December 31, 2004. Severance-related charges of $6.2 million were recorded in the “Selling, general and administrative expense” line of the Consolidated Statement of Operations for the year ended December 31, 2005.

D. Power Plant Operating Leases — We have entered into long-term operating leases for power generating facilities, expiring through 2049, including renewal options. Many of the lease agreements provide for renewal options at fair value, and some of the agreements contain customary restrictions on dividends, additional debt and further encumbrances similar to those typically found in project finance agreements. In accordance with SFAS No. 13, “Accounting for Leases” and SFAS No. 98, our operating leases are not reflected on our balance sheet. Lease payments on our operating leases which contain escalation clauses or step rent provisions are recognized on a straight-line basis. Certain capital improvements associated with leased facilities may be deemed to be leasehold improvements and are amortized over the shorter of the term

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

of the lease or the economic life of the capital improvement. Future minimum lease payments under these leases are as follows (in thousands):


		Initial
		Year		2006		2007		2008		2009		2010		Thereafter		Total

Watsonville			1995	$	2,905	$	2,905	$	2,905	$	4,065	$	—	$	—	$	12,780
Greenleaf			1998		6,604		6,999		6,290		7,697		6,440		22,931		56,961
Geysers			1999		61,965		47,150		42,886		34,566		22,899		83,118		292,584
KIAC			2000		23,875		23,845		24,473		24,537		24,548		215,535		336,813
Rumford/ Tiverton			2000		45,000		45,000		45,000		45,000		205,924		321,038		706,962
South Point			2001		9,620		9,620		9,620		9,620		9,620		297,570		345,670
RockGen			2001		26,088		27,478		28,732		29,360		29,250		140,003		280,911

	Total			$	176,057	$	162,997	$	159,906	$	154,845	$	298,681	$	1,080,195	$	2,032,681

In 2005, 2004, and 2003, rent expense for power plant operating leases amounted to $104.7 million, $105.9 million and $112.1 million, respectively. We guarantee $1.6 billion of the total future minimum lease payments of our consolidated subsidiaries.

Subsequent to December 31, 2005, we filed a notice of rejection of our leasehold interests in the Rumford and Tiverton power plants as part of our Chapter 11 cases. See Note 3 for more information on our notices of rejection and the bankruptcy cases.

E. Production Royalties and Leases — We are committed under numerous geothermal leases and right-of-way, easement and surface agreements. The geothermal leases generally provide for royalties based on production revenue with reductions for property taxes paid. The right-of-way, easement and surface agreements are based on flat rates or adjusted based on CPI changes and are not material. Under the terms of most geothermal leases, the royalties accrue as a percentage of electrical revenues. Certain properties also have net profits and overriding royalty interests that are in addition to the land base lease royalties. Some lease agreements contain clauses providing for minimum lease payments to lessors if production temporarily ceases or if production falls below a specified level. As part of finalizing the DIP Facility, subsequent to December 31, 2005, we paid off the existing operating lease and related debt for The Geysers geothermal assets. With this transaction, we have 100% ownership interest in The Geysers. See Note 34 for more information on this transaction.

Production royalties for gas-fired and geothermal facilities for the years ended December 31, 2005, 2004, and 2003, were $36.9 million, $28.4 million and $24.6 million, respectively.

F. Office and Equipment Leases — We lease our corporate, regional and satellite offices as well as some of our office equipment under noncancellable operating leases expiring through 2014. Future minimum lease payments under these leases are as follows (in thousands):


2006		$	22,910
2007			21,287
2008			20,109
2009			19,851
2010			20,070
Thereafter			41,945

	Total	$	146,172

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Lease payments are subject to adjustments for our pro rata portion of annual increases or decreases in building operating costs. In 2005, 2004, and 2003, rent expense for noncancellable operating leases amounted to $24.3 million, $29.7 million and $21.6 million, respectively. Subsequent to December 31, 2005, we filed notices of rejection of certain of our office leases. See Note 3 for more information regarding the notices of rejection of certain of our office leases.

G. Natural Gas Purchases — We enter into gas purchase contracts of various terms with third parties to supply gas to our gas-fired cogeneration projects.

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

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

At December 31, 2005, guarantees of subsidiary debt, standby letters of credit and surety bonds to third parties and guarantees of subsidiary operating lease payments and their respective expiration dates were as follows (in thousands):


Commitments Expiring		2006		2007		2008		2009		2010		Thereafter		Total

Guarantee of subsidiary debt(5)		$	24,425	$	198,859	$	1,592,342	$	22,131	$	11,040	$	590,287	$	2,439,084
Standby letters of credit(1)(3)			361,104		8,298		898		—		—		—		370,300
Surety bonds(2)(3)(4)			—		—		—		—		—		11,395		11,395
Guarantee of subsidiary operating lease payments(3)			81,772		82,487		115,604		113,977		263,041		900,742		1,557,623

	Total	$	467,301	$	289,644	$	1,708,844	$	136,108	$	274,081	$	1,502,424	$	4,378,402


(1)	The standby letters of credit disclosed above include those disclosed in Notes 15 and 20.

(2)	The surety bonds do not have expiration or cancellation dates.

(3)	These are off balance sheet obligations.

(4)	As of December 31, 2005, $7,061 of cash collateral is outstanding related to these bonds.

(5)	Includes the guarantee of our ULCI and ULCII subsidiary debt which was deconsolidated along with most of our Canadian and other foreign subsidiaries on December 20, 2005.

The majority of our off balance sheet commitments are stayed due to our bankruptcy filings on December 20, 2005. However, pending resolution of bankruptcy claims, these amounts represent our current

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


	Balance at
	December 31, 2005

Guarantee of subsidiary debt	$	2,439,084
Standby letters of credit		370,300
Surety bonds		11,395

	$	2,820,779

We have guaranteed the repayment of Senior Notes (original principal amount of $2,597.2 million) issued by two wholly owned finance subsidiaries of ours, ULC I and ULC II. However, amounts outstanding under these two entities have been reduced to $1,943.0 million and $2,139.7 million at December 31, 2005 and 2004, respectively, due to repurchases of such Senior Notes which are held by subsidiaries of ours. King City Cogen, a wholly owned subsidiary of ours, has guaranteed to Calpine Commercial Trust, an unaffiliated entity, a loan made by the Calpine Commercial Trust to our wholly owned subsidiary, Calpine Canada Power Limited. Outstanding balances of the loan at December 31, 2005 and 2004, were $28.7 million and $37.7 million, respectively. As of December 31, 2005, we have guaranteed $265.2 million and $76.6 million, respectively, of project financing for the Broad River Energy Center and Pasadena Power Plant and $275.1 million and $72.4 million, respectively, as of December 31, 2004, for these power plants. In 2004, we had obligations related to the HIGH TIDES III in the amount of $517.5 million under the convertible debentures held by Trust III related to the HIGH TIDES III. In 2005 we repaid these convertible debentures. (See Note 5 for more information.) With respect to our Hidalgo facility, we agreed to indemnify Duke Capital Corporation in the amount of $101.4 million as of December 31, 2005 and 2004, in the event Duke Capital Corporation is required to make any payments under its guarantee of the Hidalgo Lease. As of December 31, 2005 and 2004, we have also guaranteed $24.2 million and $31.7 million, respectively, of other miscellaneous debt. In addition, as a result of the deconsolidation of our Canadian and other foreign subsidiaries, we deconsolidated approximately $2.0 billion of debt that is guaranteed by Calpine Corporation (or a consolidated subsidiary thereof) through, in some cases, redundant guarantee structures that are expected to give rise to allowable claims in excess of the amount of debt outstanding to third party securities holders. Accordingly, we recorded approximately $3.8 billion of additional LSTC related to the ULC I, ULC II, and the King City Cogen loan guarantees, some of which, as in the case of ULC I guarantees, were redundant. As of December 31, 2005, all of the guaranteed debt is recorded on our Consolidated Balance Sheet, except for ULC I, ULC II and the Calpine Commercial Trust loan, which were deconsolidated on December 20, 2005. As of December 31, 2004, all of the guaranteed debt was recorded on our Consolidated Balance Sheet.

We routinely arrange for the issuance of letters of credit and various forms of surety bonds to third parties in support of our subsidiaries’ contractual arrangements of the types described above and may guarantee the operating performance of some of our partially owned subsidiaries up to our ownership percentage. The letters of credit outstanding under various credit facilities support CES risk management, and other operational and construction activities. Of the total letters of credit outstanding, $2.5 million were issued to support CES risk management at December 31, 2005 and 2004. In the event a subsidiary were to fail to perform its obligations under a contract supported by such a letter of credit or surety bond, and the issuing bank or surety were to make payment to the third party, we would be responsible for reimbursing the issuing bank or surety within an agreed timeframe, typically a period of 1 to 10 days. To the extent liabilities are incurred as a result of activities covered by letters of credit or the surety bonds, such liabilities are included in the Consolidated Balance Sheets.

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The debt on the books of the unconsolidated investments is not reflected on our balance sheet. At December 31, 2005, investee debt was approximately $2,161.7 million. Of the $2,161.7 million, $1,971.2 million related to our deconsolidated Canadian and other foreign subsidiaries. Based on our ownership share of each of the investments, our share of such debt would be approximately $2,057.7 million. Except for the debt of the deconsolidated Canadian and other foreign subsidiaries, all such debt is non-recourse to us.

In the course of our business, we and our subsidiaries have entered into various purchase and sale agreements relating to stock and asset acquisitions or dispositions. These purchase and sale agreements customarily provide for indemnification by each of the purchaser and the seller, and/or their respective parent, to the counter-party for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party. These indemnification obligations generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or impossible to quantify at the time of the consummation of a particular transaction.

Additionally, we and our subsidiaries from time to time assume other indemnification obligations in conjunction with transactions other than purchase or sale transactions. These indemnification obligations generally have a discrete term and are intended to protect our counterparties against risks that are difficult to predict or impossible to quantify at the time of the consummation of a particular transaction, such as the costs associated with litigation that may result from the transaction.

We have in a few limited circumstances directly or indirectly guaranteed the performance of obligations by unrelated third parties. These circumstances have arisen in situations in which a third party has contractual obligations with respect to the construction, operation or maintenance of a power generating facility or related equipment owned in whole or in part by us. Generally, the third party’s obligations with respect to related equipment are guaranteed for our direct or indirect benefit by the third party’s parent or other party. A financing party or investor in such facility or equipment may negotiate for us also to guarantee the performance of such third party’s obligations as additional support for the third party’s obligations. For example, in conjunction with the financing of the construction of our California peaker facilities, we guaranteed for the benefit of the lenders certain warranty obligations of third party suppliers and contractors.

I. Litigation — We are party to various litigation matters arising out of the normal course of business, the more significant of which are summarized below. The ultimate outcome of each of these matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated presently for every case. The liability we may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued with respect to such matters and, as a result of these matters, may potentially be material to our Consolidated Financial Statements. Further, we and the majority of our subsidiaries filed for bankruptcy protection in the United States and Canada on December 20, 2005, and additional subsidiaries have filed thereafter. Bankruptcy law in the United States (and the CCAA in Canada) provides for an automatic stay of most litigation involving those entities effective the date of the filing. Unless indicated otherwise, each case listed below was stayed on December 20, 2005. See Note 3 for information regarding the bankruptcy matters.

Securities Class Action Lawsuits. Beginning on March 11, 2002, fifteen complaints seeking class action status for securities claims against Calpine and other individual defendants were filed in the U.S. District Court for the Northern District of California against Calpine and certain of its employees, officers, and directors. All of these actions were ultimately assigned to Judge Saundra Brown Armstrong, and Judge Armstrong ordered the actions consolidated for all purposes on August 16, 2002, as In re Calpine Corp. Securities Litigation, Master File No. C 02-1200 SBA. Judge Armstrong denied the motion for class certification on August 10, 2005. In November 2005, the parties executed a settlement agreement. No defendant made any admission of liability. The settlement resolved the only claim remaining in these

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consolidated actions, which was a claim by two plaintiffs for an alleged violation of Section 11 of the Securities Act of 1933. All of the other claims brought in the consolidated actions were dismissed with prejudice by a February 2004 order. Pursuant to the settlement agreement, on December 5, 2005, Judge Armstrong entered a judgment of dismissal with prejudice, dismissing the consolidated actions and all claims asserted therein with prejudice. The settlement amount has been paid by insurance and the matter is resolved.

Hawaii Structural Ironworkers Pension Fund v. Calpine, et al. This case is a Section 11 case brought as a class action on behalf of purchasers in Calpine’s April 2002 stock offering. This case was filed in San Diego County Superior Court on March 11, 2003. Defendants won a motion to transfer the case to Santa Clara County. Defendants in this case are Calpine, Peter Cartwright, Ann B. Curtis, John Wilson, Kenneth Derr, George Stathakis, Credit Suisse First Boston, Banc of America Securities, Deutsche Bank Securities, and Goldman, Sachs & Co. The Hawaii Fund alleges that the prospectus and registration statement for the April 2002 offering had false or misleading statements regarding: Calpine’s actual financial results for 2000 and 2001; Calpine’s projected financial results for 2002; Mr. Cartwright’s agreement not to sell or purchase shares within 90 days of the offering; and Calpine’s alleged involvement in “wash trades.” A central allegation of the complaint is that a March 2003 restatement concerning the accounting for two sales-leaseback transactions revealed that Calpine had misrepresented its financial results in the prospectus/registration statement for the April 2002 offering. This action is stayed as to Calpine pursuant to federal bankruptcy law. There is no trial date in this action. We consider this lawsuit to be without merit and, should the case proceed against Calpine, intend to continue to defend vigorously against the allegations. In addition, Calpine has filed a motion with the bankruptcy court to extend the automatic stay to the individual defendants listed above (or enjoin further prosecution of the action). The Hawaii Fund has opposed that motion. The motion is scheduled to be heard on June 5, 2006.

Phelps v. Calpine Corporation, et al. On April 17, 2003, James Phelps filed a class action complaint in the Northern District of California, alleging claims under the Employee Retirement Income Security Act (“ERISA”). On May 19, 2003, a nearly identical class action complaint was filed in the Northern District by Lenette Poor-Herena. The parties agreed to have both of the ERISA actions assigned to Judge Armstrong, who oversees the above-described federal securities class action and the Gordon derivative action (see below). On August 20, 2003, pursuant to an agreement between the parties, Judge Armstrong ordered that the two ERISA actions be consolidated under the caption, In re Calpine Corp. ERISA Litig., Master File No. C 03-1685 SBA (the “ERISA Class Action”). Plaintiff James Phelps filed a consolidated ERISA complaint on January 20, 2004 (“Consolidated Complaint”). Ms. Poor-Herena is not identified as a plaintiff in the Consolidated Complaint.

The Consolidated Complaint defines the class as all participants in, and beneficiaries of, the Calpine Corporation Retirement Savings Plan for whose accounts investments were made in Calpine stock during the period from January 5, 2001, to the present. The Consolidated Complaint names as defendants Calpine, the members of its Board of Directors, the Calpine Corporation Retirement Savings Plan’s Advisory Committee and its members (Kati Miller, Lisa Bodensteiner, Rick Barraza, Tom Glymph, Patrick Price, Trevor Thor, Bob McCaffrey, and Bryan Bertacchi), signatories of the Calpine Corporation Retirement Savings Plan’s Annual Return/ Report of Employee Benefit Plan Forms 5500 for 2001 and 2002 (Pamela J. Norley and Marybeth Kramer-Johnson, respectively), an employee of a consulting firm hired by the Calpine Corporation Retirement Savings Plan (Scott Farris), and unidentified fiduciary defendants. The Consolidated Complaint alleges that defendants breached their fiduciary duties involving the Calpine Corporation Retirement Savings Plan, in violation of ERISA, by misrepresenting Calpine’s actual financial results and earnings projections, failing to disclose certain transactions between Calpine and Enron that allegedly inflated Calpine’s revenues, failing to disclose that the shortage of power in California during 2000-2001 was due to withholding of capacity by certain power companies, failing to investigate whether Calpine common stock was an appropriate investment for the Calpine Corporation Retirement Savings Plan, and failing to take appropriate actions to

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prevent losses to the Calpine Corporation Retirement Savings Plan. In addition, the Consolidated Complaint alleges that certain of the individual defendants suffered from conflicts of interest due to their sales of Calpine stock during the class period.

Defendants moved to dismiss the Consolidated Complaint. Judge Armstrong granted the motion and dismissed three of the four claims with prejudice. The remaining claim, for misrepresentation, was dismissed with leave to amend. Plaintiff filed an Amended Consolidated Complaint on June 3, 2005. The Amended Consolidated Complaint names as defendants Calpine Corporation and the members of the Advisory Committee for the Calpine Corporation Retirement Savings Plan. Defendants filed motions to dismiss the Amended Consolidated Complaint. The Court granted Defendants’ motions and dismissed the plaintiff’s Amended Consolidated Complaint with prejudice on December 5, 2005. Plaintiff appealed the Court’s dismissal orders to the Ninth Circuit Court of Appeals. The Ninth Circuit has extended the stay to the other defendants, has suspended the briefing schedule on the appeal as to all parties, and has requested a status report on or before June 28, 2006. We consider this lawsuit to be without merit and, should the case proceed against Calpine, intend to continue to defend vigorously against the allegations. In addition, as discussed above, Calpine has filed a motion with the bankruptcy court to extend the automatic stay to the individual defendants listed above (or enjoin further prosecution of the action). Plaintiff has opposed the motion. The motion is scheduled to be heard on June 5, 2006.

Johnson v. Peter Cartwright, et al. On December 17, 2001, a shareholder filed a derivative lawsuit on behalf of Calpine against its directors and one of its senior officers. This lawsuit is styled Johnson vs. Cartwright, et al. (No. CV803872) and is pending in California Superior Court in Santa Clara County, California. Calpine is a nominal defendant in this lawsuit, which alleges claims relating to purportedly misleading statements about Calpine and stock sales by certain of the director defendants and the officer defendant. On July 1, 2003, the Court granted Calpine’s motion to stay this proceeding until In re Calpine Corporation Securities Litigation, an action then-pending in the Northern District of California, was resolved, or until further order of the Court. As indicated above, In re Calpine Corporation Securities Litigation was resolved by a settlement. The Court has not lifted the stay in this case, and in any event this case is stayed as to Calpine pursuant to federal bankruptcy law. We consider this lawsuit to be without merit and, should the case proceed against Calpine, intend to defend vigorously against the allegations if the stay is lifted. In addition, as discussed above, Calpine has filed a motion with the bankruptcy court to extend the automatic stay to the individual defendants in this action (or enjoin further prosecution of the action). Plaintiff has opposed the motion. The motion is scheduled to be heard on June 5, 2006.

Gordon v. Peter Cartwright, et al. On August 8, 2002, a shareholder filed a derivative suit in the United States District Court for the Northern District of California on behalf of Calpine against its directors, captioned Gordon v. Cartwright, et al. similar to Johnson v. Cartwright. Motions were filed to dismiss the action against certain of the director defendants on the grounds of lack of personal jurisdiction, as well as to dismiss the complaint in total on other grounds. In February 2003, plaintiff agreed to stay these proceedings until In re Calpine Corporation Securities Litigation was resolved, and to dismiss without prejudice certain director defendants. The Court did not rule on the motions to dismiss the complaint on non-jurisdictional grounds. On March 4, 2003, plaintiff filed papers with the court voluntarily agreeing to dismiss without prejudice his claims against three of the outside directors. In December 2005, plaintiff voluntarily dismissed this action on his own initiative and the matter is now resolved.

International Paper Company v. Androscoggin Energy LLC. In October 2000, IP filed a complaint against AELLC alleging that AELLC breached certain contractual representations and warranties arising out of an Amended ESA by failing to disclose facts surrounding the termination, effective May 8, 1998, of one of AELLC’s fixed-cost gas supply agreements. The steam price paid by IP under the ESA is derived from AELLC’s price of gas under its gas supply agreements. We had acquired a 32.3% economic interest and a

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49.5% voting interest in AELLC as part of the SkyGen transaction, which closed in October 2000. On November 7, 2002, the court issued an opinion granting summary judgment to IP on the liability aspect of a particular claim against AELLC. At trial, on November 3, 2004, a jury verdict in the amount of $41 million was rendered in favor of IP holding AELLC liable on the misrepresentation claim, but not on the breach of contract claim. The verdict amount was based on calculations proffered by IP’s damages experts. AELLC has made an additional accrual to recognize the jury verdict, and the Company has recognized its 32.3% share. AELLC filed a post-trial motion challenging both the determination of its liability and the damages award and, on November 16, 2004, the court entered an order staying the execution of the judgment.

Given the adverse verdict, on or about November 26, 2004, AELLC filed a petition for relief under Chapter 11 of the Bankruptcy Code. On or about January 9, 2006, AELLC filed its Second Amended Plan of Reorganization (the “AELLC Plan”) and, on or about February 15, 2006, the U.S. Bankruptcy Court entered its order confirming the AELLC Plan (the “Confirmation Order”). In the course of obtaining confirmation of the AELLC Plan, AELLC resolved all objections to claims against the AELLC estate, with the exception of: (1) the secured tax claims of the Town of Jay; and (2) possible claims for damages arising out of the rejection of executory contracts pursuant to the AELLC Plan. Under the AELLC Plan, which provides for liquidation and distribution of substantially all of AELLC’s assets, the secured tax claims will be paid in full with interest, all other secured and priority claims will be paid in full, certain claims of IP will be released for consideration detailed in the AELLC Plan, and all unsecured claims (including any allowed rejection damages claims) will receive a pro rata portion of remaining cash, in full satisfaction of such claims. The projected distribution to unsecured creditors (other than IP) is 30-40% of the allowed amount of such claims. All claims of all creditors of AELLC will be resolved pursuant to the AELLC Plan. Membership interests in AELLC will receive nothing under the AELLC Plan and will be cancelled. Following consummation of the AELLC Plan, AELLC will cease all commercial operations. Reference may be made to the AELLC Plan and the Confirmation Order for additional information regarding the treatment of AELLC’s assets and all claims.

Panda Energy International, Inc., et al. v. Calpine Corporation, et al. On November 5, 2003, Panda Energy International, Inc. and certain related parties, including PLC II, LLC, (collectively “Panda”) filed suit against the Company and certain of its affiliates alleging, among other things, that the Company breached duties of care and loyalty allegedly owed to Panda by failing to correctly construct and operate the Oneta power plant, which the Company acquired from Panda, in accordance with Panda’s original plans. Panda alleges that it is entitled to a portion of the profits of the Oneta plant and that the Company’s actions have reduced the profits from Oneta thereby undermining Panda’s ability to repay monies owed to the Company on December 1, 2003, under a promissory note on which approximately $38.6 million (including interest) is currently outstanding. The Company has filed a counterclaim against Panda based on a guaranty, and has also filed a motion to dismiss as to the causes of action alleging federal and state securities laws violations. The court recently granted the Company’s motion to dismiss the above claims, but allowed Panda an opportunity to replead. We consider Panda’s lawsuit to be without merit and intend to vigorously defend it. The Company 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. The action has been stayed due to the bankruptcy filing.

Snohomish PUD No. 1, et al. v. FERC (regarding Nevada Power Company and Sierra Pacific Power Company v. Calpine Energy Services, L.P. complaint dismissed by FERC). On December 4, 2001, Nevada Power Company (“NPC”) and Sierra Pacific Power Company (“SPPC”) filed a complaint with FERC under Section 206 of the FPA against a number of parties to their PPAs, including Calpine. NPC and SPPC allege in their complaint, that the prices they agreed to pay in certain of the PPAs, including those signed with Calpine, were negotiated during a time when the spot power market was dysfunctional and that they are unjust and unreasonable. The complaint therefore sought modification of the contract prices. The administrative law judge issued an Initial Decision on December 19, 2002, that found for Calpine and the other respondents in

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the case and denied NPC and SPPC the relief that they were seeking. In a June 26, 2003 order, FERC affirmed the judge’s findings and dismissed the complaint, and subsequently denied rehearing of that order. The matter is pending on appeal before the United States Court of Appeals for the Ninth Circuit. The Company has participated in briefing and arguments before the Ninth Circuit defending the FERC orders, but the Company is not able to predict at this time the outcome of the Ninth Circuit appeal. There has been no activity since the December 20, 2005 automatic stay.

Transmission Service Agreement with Nevada Power Company. On September 30, 2004, NPC filed a complaint in state district court of Clark County, Nevada against Calpine Corporation (“Calpine”), Moapa Energy Center, LLC, Fireman’s Fund Insurance Company (“FFIC”) and unnamed parties alleging, among other things, breach by Calpine of its obligations under a Transmission Service Agreement (“TSA”) between Calpine and NPC for 400 MW of transmission capacity and breach by FFIC of its obligations under a surety bond, which surety bond was issued by FFIC to NPC to support Calpine’s obligations under the TSA. This proceeding was removed from state court to United States District Court for the District of Nevada. On December 10, 2004, FFIC filed a Motion to Dismiss, which was granted on May 25, 2005 with respect to claims asserted by NPC that FFIC had breached its obligations under the surety bond by not honoring NPC’s demand that the full amount of the surety bond ($33,333,333.00) be paid to NPC in light of Calpine’s failure to provide replacement collateral upon the expiration of the surety bond on May 1, 2004. NPC’s Motion to Amend the Complaint was granted on November 17, 2005 and the Amended Complaint was filed December 8, 2005. FFIC’s answer is pending. There has been no action as to Calpine and Moapa since the automatic stay took effect.

Calpine Canada Natural Gas Partnership v. Enron Canada Corp. On February 6, 2002, Calpine Canada filed a complaint in the Alberta Court of Queens Branch alleging that Enron Canada Corp. (“Enron Canada”) owed it approximately US$1.5 million from the sale of gas in connection with two Master Firm gas Purchase and Sale Agreements. To date, Enron Canada has not sought bankruptcy relief and has counterclaimed in the amount of US$18 million. We are still at the Discovery stage. The Company believes that Enron Canada’s counterclaim is without merit and intends to vigorously defend against it. Please note that a majority of Calpine Corporation’s Canadian subsidiaries (including the Plaintiff referenced above) filed for Bankruptcy protection under the Companies’ Creditors Arrangement Act R.S.C 1985, c. C-36 on December 20, 2005. Canadian Bankruptcy law provides for an automatic stay of any litigation involving those entities effective the date of the filing. There has been no action in this matter since the automatic stay took effect.

Estate of Jones, et al. v. Calpine Corporation. 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 Mr. Darrell Jones of National Energy Systems Company (“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. 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 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

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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.

Hulsey, et al. v. Calpine Corporation. On September 20, 2004, Virgil D. Hulsey, Jr. (a current employee) and Ray Wesley (a former employee) filed a class action wage and hour lawsuit against Calpine Corporation and certain of its affiliates. The complaint alleges that the purported class members were entitled to overtime pay and Calpine failed to pay the purported class members at legally required overtime rates. The matter was transferred to the Santa Clara County Superior Court and Calpine filed an answer, denying plaintiffs’ claims. In late 2005, the parties tentatively agreed to settle the case and a motion to preliminarily approve the settlement was set for January 10, 2006. The case was stayed on December 20, 2005. Accordingly, the motion was taken off calendar and there has been no further activity in the case.

Auburndale Power Partners and Cutrale. Calpine Corporation owns an interest in the Auburndale PP cogeneration facility, which provides steam to Cutrale, a juice company. The Auburndale PP facility currently operates on a “cycling” basis whereby the plant operates only a portion of the day. During the hours that the Auburndale PP facility is not operating, Auburndale PP does not provide steam to Cutrale. Cutrale filed an arbitration claim alleging that they were entitled to damages due to Auburndale PP’s failure to provide them with steam 24 hours a day. Auburndale PP disagreed with Cutrale’s position based on its interpretation of the contractual language in the Steam Supply Agreement. Binding arbitration was conducted on the contractual interpretation issue only (reserving the remedy/damage issue for a second phase of arbitration) and the arbitrator found in favor of Cutrale’s contractual interpretation. Following the first phase of arbitration, the parties agreed to settle the matter for a payment to Cutrale of approximately $1.0 million. Additionally, Cutrale will receive free steam over the life of the contract, which has a value of approximately $10 million based on current market curves. The settlement was finalized on November 16, 2005.

Harbert Distressed Investment Master Fund, Ltd. v. Calpine Canada Energy Finance II ULC, et al. On May 5, 2005, Harbert Distressed Investment Master Fund, Ltd. (the “Harbert Fund”) filed an Originating Notice (Application) (the “Original Application”) in the Supreme Court of Nova Scotia (the “Nova Scotia Court”) against Calpine Corporation and certain of its subsidiaries, including Calpine Canada Energy Finance II ULC (“Finance II”), the issuer of certain bonds (the “Bonds”) held by the Harbert Fund, and Calpine Canada Resources Company (“CCRC”), the parent company of Finance II and the indirect parent company of the company that owned the Saltend facility. Calpine Corporation has guaranteed the Bonds. In June 2005, the indenture trustee Wilmington Trust Company (the “Trustee”) joined the Original Application as co-applicant on behalf of all holders of the Bonds (“Bondholders”). The Harbert Fund and the Trustee alleged that Calpine Corporation, CCRC and Finance II violated the Harbert Fund’s rights under Nova Scotia laws in connection with certain financing transactions completed by CCRC or subsidiaries of CCRC, including in relation to a Term Debenture (the “Term Debenture”) between CCRC and Finance II. The matter proceeded to a full hearing in July 2005.

On August 2, 2005, the Nova Scotia Court issued Written Reasons for Decision (the “Decision”) which dismissed the Harbert Fund’s Original Application for relief and denied all relief to the Harbert Fund and all other Bondholders that purchased Bonds on or after September 1, 2004. However, the Nova Scotia Court stated that a remedy should be granted to any Bondholder, other than the Calpine respondent companies, that purchased Bonds prior to September 1, 2004 and that continued to hold those Bonds on August 2, 2005 (the “Eligible Bondholders”). On October 7, 2005, the Trustee and the Harbert Fund filed an Originating Notice (Application) in the Nova Scotia Court against CCRC seeking leave to commence a derivative proceeding on behalf of Finance II (the “Harbert/ WTC Leave Application”) against CCRC claiming certain relief including orders requiring CCRC to retain in its control the net proceeds from the sale of Saltend, and

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prohibiting CCRC from incurring further indebtedness ranking senior in priority to its indebtedness under the Term Debenture and from making future transfers of funds for intercompany obligations or assets of diminished or dubious value while the Term Debenture remains in force.

On October 11, 2005, Finance II and CCRC filed an Interlocutory Notice Application (the “Calpine Preliminary Application”) seeking a dismissal or alternatively a stay of the Harbert/ WTC Leave Application on the bases of res judicata and abuse of process, arguing that the claims and relief sought by the applicants in the Harbert/ WTC Leave Application are the same, or arise out of the same facts and circumstances, as the claims and relief that those applicants sought, and were denied, in the Original Application. On November 18, 2005, just prior to the hearing of the Calpine Preliminary Application, the Trustee served an update report advising that the aggregate amount of Eligible Bondholders was approximately (at then — current exchange rates) US$42,125,000. On November 21 and 22, 2005, the Calpine Preliminary Application was argued. The Nova Scotia Court reserved its decision at that time, but on December 15, 2005, issued a brief letter granting the Calpine respondents’ application and dismissing the Harbert/ WTC Leave Application, with written reasons to follow.

On November 30, 2005, the Trustee filed a Final Report confirming the aggregate face value of Bonds held by Eligible Bondholders was (at then — current exchange rates) approximately US$42,125,000. Specifically, the Trustee reported that in total there were 12 Sterling Eligible Bondholders totaling £16,750,000 and 13 Euro Eligible Bondholders totaling € 11,424,000. On December 19 and 20, 2005, the parties re-appeared before the Nova Scotia Court to settle the terms of the final order (the “Final Order”) implementing the Decision in the Original Action. After argument, and to enable the parties to address an application by the Trustee to produce further information and documentation, this application was adjourned to January 12, 2006. In addition to Calpine’s Chapter 11 filing, on December 20, 2005, Finance II and CCRC instituted proceedings (the “CCAA Proceedings”) under the Companies’ Creditors Arrangement Act before the Court of Queen’s Bench of Alberta (the “Alberta Court”). As a result of the Chapter 11 and the CCAA Proceedings, all Canadian proceedings are stayed, and in particular the application to settle the Final Order in the Original Application has been adjourned indefinitely, no final order implementing the Decision in the Original Application or confirming the dismissal of the Harbert/ WTC Leave Application have been entered and the appeal periods connected therewith have not commenced to run. However, please note that the Trustee obtained an order from the Alberta Court in the CCAA Proceedings on January 31, 2006 lifting the stay for the limited purpose of allowing Bankruptcy Petitions to be filed, which application the Canadian Calpine companies did not oppose. This is a common step taken in Canadian CCAA proceedings by creditors to freeze the running of time limits in the event it is later discovered a reviewable transaction occurred on the eve of insolvency.

By letter dated February 21, 2006, the Nova Scotia Court asked the parties to the Original Application and the Harbert/ WTC Leave Application if they were in a position to advise how they intended to proceed in these matters. The Calpine respondents confirmed to the Nova Scotia Court by letter dated February 23, 2006 that the stay in the CCAA Proceedings had been extended by the Alberta Court to April 20, 2006 by Order entered January 16, 2006, and that as such the stay remained in effect. While the Harbert Fund did not dispute that the stay remained in effect, by letter dated February 21, 2006 it advised the Nova Scotia Court it expected to receive a report from the Monitor in the CCAA Proceedings by mid-March 2006, which disclosure was required to enable the Harbert finance to determine its future steps, including as to whether to apply to the Alberta Court to attempt to lift the stay. As such, the Harbert Fund asked the Nova Scotia Court to allow it until the end of March 2006 to respond with its intended position. To date, the Trustee has not specifically responded to the Nova Scotia Court’s February 21, 2006 letter, but it is expected that the Trustee’s position is the same as Harbert’s position. By order dated April 11, 2006, the Alberta Court extended the Stay in the CCAA Proceedings to July 20, 2006.

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In connection with the Chapter 11 Filing and the CCAA Proceedings, Calpine Corporation gave undertakings to the Alberta Court and to the Trustee that: (i) the net Saltend sale proceeds remain at Calpine UK Holdings Limited, a subsidiary of CCRC; (ii) Calpine Corporation intends to continue to hold the monies there and will provide advance notice to the Trustee and the service list in the CCAA Proceedings if that intention changes; (iii) the Saltend sale proceeds held at Calpine UK Holdings Limited are not pledged as collateral for the US DIP; and (iv) Calpine Corporation will provide advance notice to the Trustee and the service list in the CCAA Proceedings of any filing of Calpine UK Holdings Limited in Canada, the US or the UK.

Harbert Convertible Arbitrage Master Fund, Ltd. et al. v. Calpine Corporation. Plaintiff Harbert Convertible Arbitrage Master Fund, Ltd. and two affiliated funds filed this action on July 11, 2005, in Supreme Court, New York County, State of New York, and filed an amended complaint on July 19, 2005. In their amended complaint, plaintiffs allege that in a July 5, 2005 letter to Calpine they provided “reasonable evidence” as required under the indenture governing the 2014 Convertible Notes that, on one or more days beginning on July 1, 2005, the Trading Price of the 2014 Convertible Notes was less than 95% of the product of the Common Stock Price multiplied by the Conversion Rate, as those terms are defined in the indenture, and that Calpine therefore was required to instruct the Bid Solicitation Agent for the 2014 Convertible Notes to determine the Trading Price beginning on the next Trading Day. If the Trading Price as determined by the Bid Solicitation Agent was below 95% of the product of the Common Stock Price multiplied by the Conversion Rate for the next five consecutive Trading Days, then the 2014 Convertible Notes would become convertible into cash and common stock for a limited period of time. Plaintiffs have asserted a claim for breach of contract, seeking unspecified damages, because Calpine did not instruct the Bid Solicitation Agent to begin to calculate the Trading Price. In addition, plaintiffs sought a declaration that Calpine had a duty, based on the statements in the July 5th letter, to commence the bid solicitation process, and also sought injunctive relief to force Calpine to instruct the Bid Solicitation Agent to determine the Trading Price of the Notes.

On November 18, 2005, Harbert filed a second amended complaint for breach and anticipatory breach of indenture, which also added the Trustee as a plaintiff. At a court hearing on November 22, counsel for Harbert and the Trustee again sought an expedited trial, stating that plaintiffs were willing to forego affirmative discovery and could respond to Calpine’s forthcoming discovery requests promptly. The Court ordered Harbert and the Trustee to provide specified discovery immediately, to respond promptly to any additional discovery demands from Calpine, and ordered the parties to commence depositions in January. The Court did not set a firm trial date, but suggested that a trial could occur by early March. Calpine moved to dismiss the second amended complaint on December 13, 2005. In the meantime, Harbert and the Trustee delayed providing any discovery, stating their belief that a bankruptcy filing was imminent that could moot the case or in any event stay it. The matter was stayed on December 20, 2005.

Whitebox Convertible Arbitrage Fund, L.P., et al. v. Calpine Corporation. Plaintiff Whitebox Convertible Arbitrage Fund, L.P. and seven affiliated funds filed an action in the Supreme Court, New York County, State of New York, for breach of contract on October 17, 2004. The factual allegations and legal basis for the claims set forth in that action are nearly identical to those set forth in the Harbert Convertible filings. On October 19, 2005, the Whitebox plaintiffs filed a motion for preliminary injunctive relief, but withdrew the motion on November 7, 2005. Whitebox had informed Calpine and the Court that the Trustee was considering intervening in the case and/or filing a similar action for the benefit of all holders of the 2014 Convertible Notes. The matter was stayed on December 20, 2005.

Calpine Corporation v. The Bank of New York, Collateral Trustee for Senior Secured Note Holders, et al. In September of 2005, Calpine received a letter from The Bank of New York, the Collateral Trustee (the “Collateral Trustee”) for Calpine’s senior secured debt holders, informing Calpine of disagreements

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purportedly raised by certain holders of First Priority Notes regarding the Company’s reinvestment of the proceeds from its recent sale of natural gas assets to Rosetta. As a result of these concerns, the Collateral Trustee informed the Company that it would not allow further withdrawals from the gas sale proceeds account until these disagreements were resolved. On September 26, 2005, Calpine filed a Declaratory Relief Action in the Delaware Court of Chancery against the Collateral Trustee and Wilmington Trust Company, as trustee for the First Priority Notes (the “First Priority Trustee”), seeking a declaration that Calpine’s past and proposed purchases of natural gas assets were permitted by the indenture for the First Priority Notes and related documents, and also seeking an injunction compelling the Collateral Trustee to release funds requested to be withdrawn.

The First Priority Trustee counterclaimed, seeking an order compelling the Company to, among other things, (i) pay damages in an amount not less than $365 million plus prejudgment interest either to the First Priority Trustee or into the gas sale proceeds account; (ii) return to the gas sale proceeds account all amounts previously withdrawn from such account and used by the Company to purchase natural gas in storage; and (iii) indemnify the First Priority Trustee for all expenses incurred in connection with defending the lawsuit and pursuing counterclaims. In addition, Wilmington Trust, in its capacity as Indenture Trustee (the “Second Priority Trustee”) for the holders of certain Second Priority Notes of the Company, intervened on behalf of the holders of the Second Priority Notes. The Company filed a motion to dismiss the First Priority Trustee’s counterclaims on the grounds that the holders of the First Priority Notes (and the First Priority Trustee on behalf of the holders of the First Priority Notes) had no remaining right under the indenture governing the First Priority Notes to obtain the relief requested because the Company had made, and the holders of the First Priority Notes had subsequently declined, an offer to purchase all of the First Priority Notes at par. A bench trial on the above claims was held before the Delaware Court of Chancery on November 11, 2005.

Following a one-day bench trial, post-trial briefing and oral argument, the Delaware Chancery Court ruled against Calpine on November 22, 2005, holding that Calpine’s use of approximately $313 million of gas sale proceeds to purchase certain gas storage inventory violated the indentures governing Calpine’s Second Priority Notes and that use of the proceeds for similar contracts was impermissible. The Chancery Court denied the First Priority Trustee’s counterclaims on the grounds asserted in the Company’s motion to dismiss — namely, that the First Priority Trustee had no right to the requested relief under the indenture governing the First Priority Notes because the holders of the First Priority Notes had declined an offer made by the Company to purchase all of the First Priority Notes at par. On December 5, 2005, the Court entered a Final Order and Judgment affording Calpine until January 22, 2006, to restore to a collateral account $311,782,955.55, plus interest. Calpine appealed, and the First Priority Trustee and Second Priority Trustee cross-appealed. On December 16, 2005, the Delaware Supreme Court affirmed the Chancery Court’s ruling that Calpine’s use of proceeds was impermissible; reversed the decision that the First Priority Trustee lacked standing to object to such use; and directed the Chancery Court to issue a modified final order in accordance with the Supreme Court’s decision. An Amended Final Order was entered by the Chancery Court on December 20, 2005. Later that same day, the case was stayed upon Calpine’s Chapter 11 filing.

Scott, et al. v. Calpine Corporation. On September 13, 2005, Calpine received a letter from an attorney representing one current and six former employees located in the Houston, Texas office. The letter alleges claims of racial discrimination, retaliation, slander, a hostile work environment and constructive discharge. The seven individuals also filed Notices of Charges of Discrimination with the U.S. Equal Employment Opportunity Commission. Outside counsel was retained and investigated the claims. In December 2005, Calpine filed a detailed response with the EEOC to each of the seven charges. On February 2, 2006, the EEOC dismissed each of the seven charges and issued Notice of Suit Rights to each of the claimants. We consider the allegations of the seven claimants to be without merit and intend to defend vigorously against any claims filed in the bankruptcy (or legal action filed elsewhere).

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See Note 3 for a description of the bankruptcy cases, including the description of a pending proceeding regarding our motion to reject eight PPAs and related FERC and other court proceedings. See also Note 33 for information concerning several matters with respect to the California power market.

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

32. Operating Segments

We are first and foremost an electric generating company. In pursuing this business strategy, it was our objective to produce a portion of our fuel consumption requirements from our own natural gas reserves (“equity gas”). In July 2005, we sold substantially all of our remaining domestic oil and gas assets to Rosetta. See Note 13 for a discussion of the divestiture of our oil and gas assets. As a result of the sale of substantially all of our oil and gas assets, we now have two reportable segments, “Electric Generation and Marketing” and “Other.” The revenue and expense from the “Oil and Gas Production and Marketing” reportable segment has been reclassified to discontinued operations and the assets have been reclassified into current and long-term assets held for sale. The remaining gas pipeline and transportation assets previously included in this reportable segment have been reflected in the table below within “Other.”

The Electric Generation and Marketing segment includes the development, acquisition, ownership and operation of power production facilities, including hedging, balancing, optimization, and trading activity transacted on behalf of our power generation facilities. The Other segment includes the activities of our parts and services businesses and our gas pipeline assets.

We evaluate performance based upon several criteria including profits before tax. The accounting policies of the operating segments are the same as those described in Note 2. The financial results for our operating segments have been prepared on a basis consistent with the manner in which our management internally disaggregates financial information for the purposes of assisting in making internal operating decisions.

Certain costs related to company-wide functions are allocated to each segment, such as interest expense and interest income, based on a ratio of segment assets to total assets. The “Depreciation and amortization” line reported below discloses only such amounts as included in “Total cost of revenue” of the Consolidated Statements of Operations. Due to the integrated nature of the business segments, estimates and judgments have been made in allocating certain revenue and expense items, and reclassifications have been made to prior periods to present the allocation consistently.

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	Electric
	Generation						Corporate and
	and Marketing			Other			Eliminations			Total

2005
Revenue from external customers	$	10,011,789		$	239,700		$	(138,831	)	$	10,112,658
Depreciation and amortization expense included in cost of revenue		503,992			3,661			(1,212	)		506,441
Operating plant impairments		2,412,586			—			—			2,412,586
(Income) loss from unconsolidated investments		(12,119	)		—			—			(12,119	)
Equipment, development project and other impairments		2,091,967			—			25,698			2,117,665
Interest expense		1,318,121			21,213			57,954			1,397,288
Interest (income)		(79,454	)		(1,279	)		(3,493	)		(84,226	)
(Income) from repurchase of various issuances of debt		—			—			(203,341	)		(203,341	)
Other (income) expense, net		53,713			2,617			16,058			72,388
Income (loss) before reorganization items, provision (benefit) for income taxes, and discontinued operations		(5,535,921	)		(72,142	)		12,221			(5,595,842	)
Reorganization items		296,187			(145,757	)		4,876,080			5,026,510
Provision (benefit) for income taxes		(769,399	)		28,001			—			(741,398	)
Total assets		19,380,779			311,902			852,116			20,544,797
Investment in power projects and oil and gas properties		83,620			—			—			83,620
Property additions		784,562			6,156			31,589			822,307
2004
Revenue from external customers	$	8,580,461		$	117,797		$	(49,876	)	$	8,648,382
Depreciation and amortization expense included in cost of revenue		441,215			3,637			1,166			446,018
(Income) loss from unconsolidated investments		14,088			—			—			14,088
Equipment, development project and other impairments		46,371			523			—			46,894
Interest expense		1,010,937			49,243			35,239			1,095,419
Interest (income)		(50,542	)		(2,462	)		(1,762	)		(54,766	)
(Income) from repurchase of various issuances of debt		—			—			(246,949	)		(246,949	)
Other (income) expense, net		(197,760	)		7,243			69,455			(121,062	)
Income (loss) before reorganization items, provision (benefit) for income taxes, and discontinued operations		(563,659	)		(129,667	)		38,329			(654,997	)
Provision (benefit) for income taxes		(200,606	)		(49,273	)		14,565			(235,314	)
Total assets		25,117,106			1,223,454			875,528			27,216,088
Investments in power projects and oil and gas properties		373,108			—			—			373,108
Property additions		1,457,819			5,343			18,417			1,481,579
2003
Revenue from external customers	$	8,380,469		$	51,439		$	(10,738	)	$	8,421,170
Depreciation and amortization expense included in cost of revenue		359,005			20,967			2,008			381,980
(Income) loss from unconsolidated investments		(75,724	)		—			—			(75,724	)
Equipment, development project and other impairments		67,979			—			—			67,979
Interest expense		611,048			48,554			35,902			695,504
Interest (income)		(34,431	)		(2,736	)		(2,023	)		(39,190	)
(Income) from repurchase of various issuances of debt		—			—			(278,612	)		(278,612	)
Other (income) expense, net		(46,461	)		(46,581	)		46,478			(46,564	)
Income (loss) before reorganization items, provision (benefit) for income taxes, and discontinued operations		(57,970	)		(20,164	)		38,429			(39,705	)
Provision (benefit) for income taxes		(33,374	)		(7,662	)		14,603			(26,433	)
Cumulative effect of a change in accounting principle, net of tax		183,270			(1,443	)		(884	)		180,943

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	*Geographic Area Information*

During the year ended December 31, 2005, we owned continuing interests in 89 operating power plants in the United States, and three operating power plants in Canada. We also owned TTS in The Netherlands. See Note 10 for a discussion of the deconsolidation of our Canadian and other foreign subsidiaries. Geographic revenue and property, plant and equipment information is based on physical location of the assets at the end of each period.


	United States		Canada		Europe		Total

	(In thousands)
2005
Total Revenue	$	9,955,907	$	105,497	$	51,254	$	10,112,658
Property, plant and equipment, net		14,118,795		—		420		14,119,215
2004
Total Revenue	$	8,512,769	$	93,071	$	42,542	$	8,648,382
Property, plant and equipment, net		17,893,678		498,136		5,929		18,397,743
2003
Total Revenue	$	8,276,392	$	121,218	$	23,560	$	8,421,170

33. California Power Market

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

On December 12, 2002, an Administrative Law Judge issued a Certification of Proposed Finding on California Refund Liability making an initial determination of refund liability. On March 26, 2003, FERC issued an order adopting many of the findings set forth in the December 12 Certification. In addition, as a result of certain findings by the FERC staff concerning the unreliability or misreporting of certain reported indices for gas prices in California during the Refund Period, FERC ordered that the basis for calculating a party’s potential refund liability be modified by substituting a gas proxy price based upon gas prices in the producing areas plus the tariff transportation rate for the California gas price indices previously adopted in the California Refund Proceeding. We believe, based on the available information, that any refund liability that may be attributable to us could total approximately $10.1 million (plus interest, if applicable), after taking the appropriate set-offs for outstanding receivables owed to us by the CalPX and the CAISO. We believe we have appropriately reserved for the refund liability that by our current analysis would potentially be owed under the refund calculation clarification in the March 26 Order. The final determination of the refund liability and the allocation of payment obligations among the numerous buyers and sellers in the California markets is subject to further Commission proceedings to ascertain the allocation of payment obligations among the numerous buyers and sellers in the California markets. Furthermore, it is possible that there will be further proceedings to require refunds from certain sellers for periods prior to the originally designated Refund Period. In addition, the FERC orders concerning the Refund Period, the method for calculating refund liability and numerous other issues are pending on appeal before the U.S. Court of Appeals for the Ninth Circuit. At this time, we are unable to predict the timing of the completion of these proceedings or the final refund liability. Thus, the impact on our business is uncertain.

On April 22, 2002, we entered into a settlement with the Governor of the State of California, acting on behalf of the executive branch of the State of California, the California EOB, the California Public Utilities Commission, and the People of the State of California by and through the Attorney General (the “AG”)

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(collectively, the “California State Releasing Parties”). Our settlement resulted in a FERC order issued on March 26, 2004, which partially dismissed us from the California Refund Proceeding to the extent that any refunds are owed for power sold by us to CDWR or any of the other California State Releasing Parties.

On September 9, 2004, the Ninth Circuit Court of Appeals issued a decision on appeal (State of California, Ex. Rel. Bill Lockyer, Attorney General v. Federal Energy Regulatory Commission) of a Petition for Review of an order issued by FERC in FERC Docket No. EL02-71 wherein the AG had filed a complaint (the “AG Complaint”) under Sections 205 and 206 of the FPA alleging that parties who misreported or did not properly report market based transactions were in violation of their market based rate tariff and, as a result, were not accorded protection under section 206 of the FPA from retroactive refund liability. The Ninth Circuit remanded the order to FERC for rehearing. FERC is required to determine whether refunds should be required for violation of reporting requirements prior to October 2, 2000. The proceeding on remand has not yet been established. In connection with its settlement agreement with the California State Releasing Parties (including the AG), we and our affiliates settled all claims related to the AG Complaint.

FERC Investigation into Western Markets. On February 13, 2002, FERC initiated an investigation of potential manipulation of electric and natural gas prices in the western United States. This investigation was initiated as a result of allegations that Enron and others, through their affiliates, had used their market position to distort electric and natural gas markets in the West. The scope of the investigation was to consider whether, as a result of any manipulation in the short-term markets for electric energy or natural gas or other undue influence on the wholesale markets by any party since January 1, 2000, the rates of the long-term contracts subsequently entered into in the West were potentially unjust and unreasonable. On August 13, 2002, the FERC staff issued the Initial Report on Company-Specific Separate Proceedings and Generic Reevaluations; Published Natural Gas Price Data; and Enron Trading Strategies (the “Initial Report”), summarizing its initial findings in this investigation. There were no findings or allegations of wrongdoing by us set forth or described in the Initial Report. On March 26, 2003, the FERC staff issued a final report in this investigation (the “Final Report”). In the Final Report, the FERC staff recommended that FERC issue a show cause order to a number of companies, including us, regarding certain power scheduling practices that may have been in violation of the CAISO’s or the CalPX’s tariff. The Final Report also recommended that FERC modify the basis for determining potential liability in the California Refund Proceeding discussed above.

On June 25, 2003, FERC issued a number of orders associated with these investigations, including the issuance of two show cause orders to certain industry participants. FERC did not subject us to either of the show cause orders. Also on June 25, 2003, FERC issued an order directing the FERC Office of Markets and Investigations to investigate further whether market participants who bid a price in excess of $250/ MWh into markets operated by either the CAISO or the CalPX during the period of May 1, 2000, to October 2, 2000, may have violated CAISO and CalPX tariff prohibitions. By letter dated May 12, 2004, the Director of FERC’s Office of Market Oversight and Investigation notified us that the investigation of us in this proceeding has been terminated.

Also during the summer of 2003, FERC’s Office of Market Oversight and Investigations began an investigation of generators in California to determine whether California generators improperly physically withheld power from the California markets between May 1, 2000 and June 30, 2001. On June 30, 2004, we were notified by FERC that its investigation of us in this matter had been terminated.

CPUC Proceeding Regarding QF Contract Pricing for Past Periods. Our QF contracts with PG&E provide that the CPUC has the authority to determine the appropriate utility “avoided cost” to be used to set energy payments by determining the short run avoided cost (“SRAC”) energy price formula. In mid-2000, our QF facilities elected the option set forth in Section 390 of the California Public Utilities Code, which provided QFs the right to elect to receive energy payments based on the CalPX market clearing price instead of the SRAC price administratively determined by the CPUC. Having elected such option, our QF facilities

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were paid based upon the CalPX Price for various periods commencing in the summer of 2000 until January 19, 2001, when the CalPX ceased operating a day-ahead market. The CPUC has conducted proceedings (R.99-11-022) to determine whether the CalPX Price was the appropriate price for the energy component upon which to base payments to QFs which had elected the CalPX-based pricing option. In late 2000, the CPUC Commissioner assigned to the matter issued a proposed decision to the effect that the CalPX Price was the appropriate energy price to pay QFs who selected the pricing option then offered by Section 390, but the CPUC has yet to issue a final decision. Therefore, it is possible that the CPUC could order a payment adjustment based on a different energy price determination. On April 29, 2004, PG&E, the Utility Reform Network, a consumer advocacy group, and the Office of Ratepayer Advocates, an independent consumer advocacy department of the CPUC (collectively, the “PG&E Parties”), filed a Motion for Briefing Schedule Regarding True-Up of Payments to QF Switchers (the “April 29 Motion”). The April 29 Motion requested that the CPUC set a briefing schedule in the R.99-11-022 docket to determine what is the appropriate price that should be paid to the QFs that had switched to the CalPX Price. The PG&E Parties allege that the appropriate price should be determined using the methodology that has been developed thus far in the California Refund Proceeding discussed above. Supplemental pleadings have been filed on the April 29 Motion, but neither the CPUC nor the assigned administrative law judge has issued any rulings with respect to either the April 29 Motion or the initial Emergency Motion. On August 16, 2005, the Administrative Law Judge assigned to hear the April 29 Motion issued a ruling setting October 11, 2005, as the date for filing prehearing conference statements and October 17, 2005, as the date of the prehearing conference. In our response, filed on October 11, 2005, we urged that the April 29 Motion should be dismissed, but if dismissal were not granted, then discovery, testimony and hearings would be required. The assigned Administrative Law Judge has not yet issued a formal ruling following the October 17, 2005 prehearing conference. We believe that the PX Price was the appropriate price for energy payments and that the basis for any refund liability based on the interim determination by the FERC in the California Refund Proceeding is unfounded, but there can be no assurance that this will be the outcome of the CPUC proceedings.

On April 14, 2006, our QFs with existing QF contracts with PG&E executed amendments to, among other matters, adjust the energy price paid and to be paid to QFs and extinguish any potential refund obligation to PG&E for energy payments these QFs received based on the PX Price. The effectiveness of our individual amendments to these existing QF contracts is subject, where applicable, to creditors’ committee, project lender(s), U.S. Bankruptcy Court and CPUC approval. If effective, each amendment would authorize PG&E to pay an adjusted energy price under our existing QF contracts prospectively for a number of years as part of the consideration for the extinguishment of the potential for any retroactive refund liability relating to the energy payments based on the PX Price. On April 18, 2006, PG&E and the Independent Energy Producers Association filed a joint motion requesting that the CPUC approve the settlement and the individual QF contract amendments, including our existing QF contracts. Any comments on the settlement and amendments are to be filed by May 18, 2006.

Geysers RMR Section 206 Proceeding. CAISO, EOB, CPUC, PG&E, SDG&E, and Southern California Edison Company (collectively referred to as the “Buyers Coalition”) filed a complaint on November 2, 2001, at FERC requesting the commencement of a FPA Section 206 proceeding to challenge one component of a number of separate settlements previously reached on the terms and conditions of RMR Contracts with certain generation owners, including GPC, which settlements were also previously approved by FERC. RMR Contracts require the owner of the specific generation unit to provide energy and ancillary services when called upon to do so by the ISO to meet local transmission reliability needs or to manage transmission constraints. The Buyers Coalition asked FERC to find that the availability payments under these RMR Contracts are not just and reasonable. On June 3, 2005, FERC issued an order dismissing the Buyers Coalition’s complaint against all named generation owners, including GPC. On August 2, 2005, FERC issued an order denying requests for rehearing of its order. On September 23, 2005, the Buyers Coalition (with the exclusion of the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CAISO) filed a Petition for Review with the U.S. Court of Appeals for the D.C. Circuit, seeking review of FERC’s order dismissing the complaint.

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. 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 (the “Delta RMR Settlement”). Under the terms of the Delta RMR Settlement, the parties agreed to interim RMR rates which Delta would collect, subject to refund, from February 10, 2003, forward. The parties agreed to defer further proceedings on the Delta RMR contract until a similar RMR proceeding (the “Mirant RMR Proceeding”) was resolved by FERC. Under the terms of the Delta RMR Settlement, Delta continued to provide services to the CAISO pursuant to the interim RMR rates, terms and conditions. Since the Delta RMR Settlement, Delta and CAISO have entered into RMR contracts for the years 2003, 2004 and 2005 pursuant to the terms of the Delta RMR Settlement.

On June 3, 2005, FERC issued a final order in the Mirant RMR Proceeding, resolving that proceeding and triggering the reopening of the Delta RMR 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 Delta RMR Settlement with the 2006 RMR case. FERC set the proceeding for hearing, but has suspended hearing procedures pending settlement discussions among the parties with respect to the rates for both the February 10, 2003 through December 31, 2005, period and the calendar year 2006 period. In addition, to resolve credit concerns raised by certain intervening parties, Delta has begun to direct into an escrow account the difference between the previously-filed rate and the 2006 rate pending the determination by FERC as to whether Delta is obligated to refund some portion of the rate collected in 2006. We are unable at this time to predict the result of any settlement process or the ultimate ruling by the FERC on the rates for Delta’s RMR services for the period between February 10, 2003 and December 31, 2005 or for calendar year 2006.

34. Subsequent Events

On January 26, 2006, the U.S. Bankruptcy Court granted final approval of our $2 billion DIP Facility. The DIP Facility will be used to fund our operations during our Chapter 11 restructuring. In addition, as described below, a portion of the DIP Facility was used to retire certain facility operating lease obligations at The Geysers. In addition, pursuant to the May 3, 2006 amendment, borrowings under the DIP Facility may be used to repay a portion of the First Priority Notes. The DIP Facility closed on December 22, 2005, with limited access to the commitments, pursuant to the interim order of the U.S. Bankruptcy Court and was amended and restated on February 23, 2006, funding the term loans. It consisted of a $1 billion revolving credit facility (including a $300 million letter of credit subfacility and a $10 million swingline subfacility), priced at LIBOR plus 225 basis points; $400 million first-priority term loan, priced at LIBOR plus 225 basis points or base rate plus 125 basis points; and $600 million second-priority term loan, priced at LIBOR plus 400 basis points or the base rate plus 300 basis points. The DIP Facility will remain in place until the earlier of an effective plan of reorganization or December 20, 2007.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

commercial activities in the United States while reducing activities and curtailing expenditures in certain non-core areas and business units. On April 4, 2006, we identified approximately 20 power plants in operation or under construction that are no longer considered to be core operations due to a combination of factors, including financial performance, market prospects, and strategic fit. Accordingly, we will be seeking to sell the majority of these assets by the end of 2006. In addition, we will close our office in Boston, Massachusetts, and have closed our offices in Dublin, California, Denver and Fort Collins, Colorado, Deer Park, Texas, Portland, Oregon, Tampa, Florida and Atlanta, Georgia. As we complete asset sales and construction activities, we expect to reduce our workforce by approximately 1,100 positions, or over one third of our pre-petition date workforce by the end of 2006. At the completion of this effort, we expect to retain a generating portfolio of clean and reliable geothermal and natural gas-fired power plants located in our key North American markets.

On February 3, 2006, as part of finalizing the collateral structure of the $2 billion DIP Facility, we closed a transaction pursuant to which we acquired The Geysers operating lease assets and paid off the related lessor’s third party debt for approximately $275.1 million. As a result of this transaction, we became the 100% owner of The Geysers assets. Our DIP Facility is secured by first priority liens on The Geysers assets, together with first priority liens on all of the other unencumbered assets, and junior liens on all of the encumbered assets, of the U.S. Debtors. Previously, we had leased the 19 Geysers power plants pursuant to a leveraged lease.

On February 15, 2006, we entered into a non-binding letter of intent contemplating the negotiation of a definitive agreement for the sale of Otay Mesa Energy Center to San Diego Gas & Electric. The letter included a period of exclusivity which expired May 1, 2006. The parties are discussing a possible extension of exclusivity. Any final, definitive agreement would require the approval of the California Public Utilities Commission and the Bankruptcy Court over our Chapter 11 cases. Construction of the Otay Mesa Energy Center, a 593-MW power plant, located in San Diego County, began in 2001 and has proceeded only gradually while we have sought certain regulatory approvals and, more recently, as a result of the negotiations with SDG&E.

On March 1, 2006, upon receipt of Bankruptcy Court approval, we implemented a severance program that provides eligible employees, whose employment is involuntarily terminated in connection with workforce reductions, with certain severance benefits, including base salary continuation for specified periods based on the employee’s position and length of service.

On March 3, 2006, pursuant to the Cash Collateral Order, the U.S. Debtors and the Official Committee of Unsecured Creditors of Calpine Corporation and the Ad Hoc Committee of Second Lien Holders of

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Calpine Corporation agreed, in consultation with the indenture trustee for the First Priority Notes on the designation of nine projects that, absent the consent of the Committees or unless ordered by the Bankruptcy Court, may not receive funding, other than in certain limited amounts that were agreed to by the U.S. Debtors and the Committees in consultation with the First Priority Notes trustees. The nine designated projects are the Clear Lake power plant, Dighton power plant, Fox Energy Center, Newark power plant, Parlin power plant, Pine Bluff Energy Center, Rumford power plant, Texas City power plant, and Tiverton power plant. The U.S. Debtors may determine, in consultation with the Committees and the First Priority Notes trustee, that additional projects should be added to, or that certain of the foregoing projects should be deleted from, the list of designated projects.

On March 15, 2006, CCFC entered into agreements amending, respectively, the indenture governing its $415.0 million aggregate principal amount of Second Priority Senior Secured Floating Rate Notes due 2011 and the credit agreement governing its $385.0 million in aggregate principal amount of First Priority Senior Secured Institutional Term Loans due 2009. CCFC also entered into waiver agreements providing for the waiver of certain defaults that occurred following our bankruptcy filings as a result of the failure of CES to make certain payments to CCFC under a PPA with CCFC. Each of the amendment agreements (i) provides that it would be an event of default under the indenture or the credit agreement, as applicable, if CES were to seek to reject the PPA in connection with the bankruptcy cases and (ii) allows CCFC to make a distribution to its indirect parent, CCFCP, to permit CCFCP to make a scheduled dividend payment on its redeemable preferred shares. The amendment agreements and waiver agreements were executed upon the receipt by CCFC of the consent of a majority of the holders of the notes and the agreement of a majority of the term loan lenders pursuant to a consent solicitation and request for amendment initiated on February 22, 2006 as amended on March 10, 2006. CCFC made a consent payment of $1.89783 per each $1,000 principal amount of notes or term loans held by consenting noteholders or term loan lenders, as applicable. None of CCFCP, CCFC, or any of their direct and indirect subsidiaries, is a Calpine Debtor or has otherwise sought protection under the Bankruptcy Code.

On March 30, 2006, the Master Transaction Agreement, dated September 7, 2005, among Bear Stearns, CalBear, Calpine and Calpine’s indirect, wholly owned subsidiaries CES and CMSC, was terminated. Under the Master Transaction Agreement, CalBear and Bear Stearns were entitled to terminate the Master Transaction Agreement upon certain events of default by Calpine, CES or CMSC, including a bankruptcy filing by one or more of them. In connection with the termination of the Master Transaction Agreement, the related agreements entered into thereunder were also terminated, including (i) the Agency and Services Agreement by and among CMSC and CalBear, pursuant to which CMSC acted as CalBear’s exclusive agent for gas and power trading, (ii) the Trading Master Agreement among CES, CMSC and CalBear, pursuant to which CalBear had executed credit enhancement trades on behalf of CES and (iii) the ISDA Master Agreement, Schedule, and applicable annexes between CES and CalBear to effectuate the credit enhance-

282

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(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

ment trades. As a result of the termination of the Master Transaction Agreement and related agreements, CMSC has the obligation to liquidate all trading positions of CalBear and terminate all transactions done in the name of CalBear, except as otherwise approved by CalBear. Bear Stearns may, at its option, take over such liquidation from CMSC. In addition, Bear Stearns continues to maintain ownership of all of the third party master agreements executed in connection with the CalBear relationship.

On April 11, 2006, the U.S. Bankruptcy Court granted our application for an extension of the period during which we have the exclusive right to file a reorganization plan or plans from April 20, 2006 to December 31, 2006, and granted us the exclusive right until March 31, 2007, to solicit acceptances of such plan or plans. In addition, the U.S. Bankruptcy Court granted each of the U.S. Debtors an additional 90 days (or until July 18, 2006, for most of the U.S. Debtors) to assume or reject non-residential real property leases. Also on April 11, 2006, the U.S. Bankruptcy Court granted our application for the repayment of a portion of a loan we had extended to CPN Insurance Corporation, our wholly owned captive insurance subsidiary. The repayment of this loan facilitates our ability to continue to provide a portion of our insurance needs through our subsidiary and thus provides us additional flexibility to be able to continue to implement a favorable property insurance program.

For a discussion of certain events relating to our bankruptcy proceedings see Note 3. See Notes 14-24 for a complete discussion of our various debt instruments including certain covenant violations resulting from our bankruptcy filings.

283

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

35. Quarterly Consolidated Financial Data (unaudited)

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

On December 20, 2005, Calpine and the majority of its wholly owned subsidiaries in the United States filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court and, in Canada, under the CCAA.

Our quarter ended December 31, 2005 statement of operations data below reflects the application of Statement of Position 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code.” See Notes 3 and 4 for more information on the bankruptcy filing.

During the fourth quarter of 2005, we determined it was necessary to deconsolidate most of our Canadian and other foreign entities due to our loss of control over these entities upon filing for bankruptcy protection under the CCAA in Canada. As a result of the deconsolidation, we adopted the cost method of accounting for our investment in these entities. Upon adoption of the cost method, we evaluated our investment balances and intercompany notes receivable from these entities for impairment. We determined that our entire investment in these entities had experienced other-than-temporary decline in value and was impaired. We also concluded that all intercompany notes receivable balances from these entities were uncollectible, as the notes were unsecured and protected by the automatic stay under the CCAA. Consequently, we fully impaired these investment and receivable assets at December 31, 2005, resulting in a $879.1 million charge to reorganization items.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Also during the fourth quarter of 2005, we determined that certain operating plants, development and construction projects, investments and other assets were impaired. We recorded impairment charges totaling $4,530.3 million. See Note 6 for more information regarding these impairments.


		Quarter Ended

		December 31,			September 30,			June 30,			March 31,

		(In thousands, except per share amounts)
2005 Common stock price per share:
	High	$	3.05		$	3.88		$	3.60		$	3.80
	Low		0.20			2.26			1.45			2.64
2005
Total revenue		$	2,586,430		$	3,281,590		$	2,198,907		$	2,045,731
(Income) from repurchase of various issuances of debt			(36,885	)		(15,530	)		(129,154	)		(21,772	)
Operating plant impairments			2,412,586			—			—			—
Gross profit (loss)			(2,346,247	)		239,127			78,458			83,739
Equipment, development project and other impairments			2,117,665			—			—			—
Income (loss) from operations			(4,488,655	)		175,164			(78,632	)		20,844
Reorganization items			5,026,510			—			—			—
Income (loss) before discontinued operations			(9,259,478	)		(242,435	)		(208,182	)		(170,859	)
Discontinued operations, net of tax			4,150			25,744			(90,276	)		2,128
Net income (loss)		$	(9,255,329	)	$	(216,690	)	$	(298,458	)	$	(168,731	)
Basic earnings per common share:
	Income (loss) before discontinued operations	$	(19.33	)	$	(0.51	)	$	(0.46	)	$	(0.38	)
	Discontinued operations, net of tax		0.01			0.06			(0.20	)		—
	Net income (loss)		(19.32	)		(0.45	)		(0.66	)		(0.38	)
Diluted earnings per common share:
	Income (loss) before discontinued operations	$	(19.33	)	$	(0.51	)	$	(0.46	)	$	(0.38	)
	Discontinued operations, net of tax		0.01			0.06			(0.20	)		—
	Net income (loss)		(19.32	)		(0.45	)		(0.66	)		(0.38	)
2004 Common stock price per share:
	High	$	4.08		$	4.46		$	4.98		$	6.42
	Low		2.24			2.87			3.04			4.35
2004
Total revenue		$	2,182,050		$	2,411,732		$	2,189,128		$	1,865,472
(Income) from repurchase of various issuances of debt			(76,401	)		(167,154	)		(2,559	)		(835	)
Gross profit			71,458			226,445			33,144			48,902
Income (loss) from operations			(45,725	)		142,323			(32,062	)		(12,156	)
Income (loss) before discontinued operations			(225,208	)		28,878			(69,887	)		(153,466	)
Discontinued operations, net of tax			(58,488	)		112,247			41,189			82,274
Net income (loss)			(283,696	)		141,125			(28,698	)		(71,192	)
Basic earnings per common share:
	Income (loss) before discontinued operations	$	(0.51	)	$	0.07		$	(0.17	)	$	(0.37	)
	Discontinued operations, net of tax		(0.13	)		0.25			0.10			0.20
	Net income (loss)	$	(0.64	)	$	0.32		$	(0.07	)	$	(0.17	)
Diluted earnings per common share:
	Income (loss) before discontinued operations		(0.51	)		0.07			(0.17	)		(0.37	)
	Discontinued operations, net of tax		(0.13	)		0.25			0.10			0.20
	Net income (loss)	$	(0.64	)	$	0.32		$	(0.07	)	$	(0.17	)

285

SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS


						Charged to
						Accumulated
		Balance at				Other
		Beginning		Charged to		Comprehensive								Balance at
Description		of Year		Expense		Loss		Reductions(1)			Other(2)			End of Year

		(In thousands)
Year ended December 31, 2005
	Allowance for doubtful accounts	$	7,317	$	11,645	$	—	$	(3,267	)	$	(3,009	)	$	12,686
	Allowance for doubtful accounts with related party Canadian and other foreign subsidiaries		—		54,830		—		—			—			54,830
	Reserve for notes receivable		2,910		28,936		—		—			—			31,846
	Reserve for interest and notes receivable with related party Canadian and other foreign subsidiaries		—		228,014		—		—			—			228,014
	Gross reserve for California Refund Liability		12,905		90		—		—			—			12,995
	Reserve for investment in Androscoggin Energy Center		5,000		—		—		—			—			5,000
	Reserve for derivative assets		3,268		4,077		3		(3,862	)		—			3,486
	Deferred tax asset valuation allowance		62,822		1,576,400		—		—			—			1,639,222
Year ended December 31, 2004
	Allowance for doubtful accounts	$	7,282	$	6,119	$	—	$	(6,486	)	$	402		$	7,317
	Reserve for notes receivable		273		2,637		—		—			—			2,910
	Gross reserve for California Refund Liability		12,905		—		—		—			—			12,905
	Reserve for investment in Androscoggin Energy Center		—		5,000		—		—			—			5,000
	Reserve for derivative assets		7,454		2,825		173		(7,184	)		—			3,268
	Repayment reserve for third-party default on emission reduction credits’ settlement		3,000		2,850		—		(5,850	)		—			—
	Deferred tax asset valuation allowance		19,335		43,487		—		—			—			62,822
Year ended December 31, 2003
	Allowance for doubtful accounts	$	5,057	$	2,190	$	—	$	(383	)	$	418		$	7,282
	Reserve for notes receivable		—		273		—		—						273
	Gross reserve for California Refund Liability		10,700		2,205		—		—						12,905
	Reserve for derivative assets		16,452		19,459		3,640		(32,097	)					7,454
	Gain reserved on certain Enron transactions		17,862		—		—		(17,862	)					—
	Repayment reserve for third-party default on emission reduction credits’ settlement		—		3,000		—		—						3,000
	Deferred tax asset valuation allowance		26,665		—		—		(7,330	)		—			19,335


(1)	Represents write-offs of accounts considered to be uncollectible and recoveries of amounts previously written off or reserved.

(2)	Primarily relates to amounts recorded on our deconsolidated Canadian and other foreign subsidiaries for the year ended December 31, 2005, and to foreign currency translation adjustments for the years ended December 31, 2004 and 2003.

286

EXHIBIT INDEX


Exhibit
Number			Description

	2	.1	Purchase and Sale Agreement, dated July 1, 2004, among Calpine Corporation (the “Company”), Calpine Natural Gas L.P. and Pogo Producing Company.(a)

	2	.2	Purchase and Sale Agreement, dated July 1, 2004, among the Company, Calpine Natural Gas L.P. and Bill Barrett Corporation.(a)

	2	.3	Asset and Trust Unit Purchase and Sale Agreement, dated July 1, 2004, among the Company, Calpine Canada Natural Gas Partnership, Calpine Energy Holdings Limited, PrimeWest Gas Corp. and PrimeWest Energy Trust.(a)

	2	.4	Share Sale and Purchase Agreement, made as of May 28, 2005, among the Company, Calpine UK Holdings Limited, Quintana Canada Holdings, LLC, International Power PLC, Mitsui & Co., Ltd. and Normantrail (UK CO 3) Limited. Approximately four pages of this Exhibit 2.4 have been omitted pursuant to a request for confidential treatment. The omitted language has been filed separately with the SEC.(b)

	2	.5	Purchase and Sale Agreement dated July 7, 2005, by and among Calpine Gas Holdings LLC, Calpine Fuels Corporation, the Company, Rosetta Resources Inc., and the other Subject Companies identified therein.(c)

	2	.6	Agreement dated as of December 20, 2005, by and among Steam Heat LLC, Thermal Power Company and, for certain limited purposes, Geysers Power Company, LLC.(*)

	3	.1.1	Amended and Restated Certificate of Incorporation of the Company, as amended through June 2, 2004.(d)

	3	.1.2	Amendment to Amended and Restated Certificate of Incorporation of the Company, dated June 20, 2005.(e)

	3	.2	Amended and Restated By-laws of the Company.(f)

	4	.1.1	Indenture dated as of May 16, 1996, between the Company and U.S. Bank (as successor trustee to Fleet National Bank), as Trustee, including form of Notes.(g)

	4	.1.2	First Supplemental Indenture dated as of August 1, 2000, between the Company and U.S. Bank (as successor trustee to Fleet National Bank), as Trustee.(h)

	4	.1.3	Second Supplemental Indenture dated as of April 26, 2004, between the Company and U.S. Bank (as successor trustee to Fleet National Bank), as Trustee.(i)

	4	.2.1	Indenture dated as of July 8, 1997, between the Company and The Bank of New York, as Trustee, including form of Notes.(j)

	4	.2.2	Supplemental Indenture dated as of September 10, 1997, between the Company and The Bank of New York, as Trustee.(k)

	4	.2.3	Second Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(h)

	4	.2.4	Third Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(i)

	4	.3.1	Indenture dated as of March 31, 1998, between the Company and The Bank of New York, as Trustee, including form of Notes.(l)

	4	.3.2	Supplemental Indenture dated as of July 24, 1998, between the Company and The Bank of New York, as Trustee.(l)

	4	.3.3	Second Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(h)

	4	.3.4	Third Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(i)

	4	.4.1	Indenture dated as of March 29, 1999, between the Company and The Bank of New York, as Trustee, including form of Notes.(m)

	4	.4.2	First Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(h)

287


Exhibit
Number			Description


	4	.4.3	Second Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(i)

	4	.5.1	Indenture dated as of March 29, 1999, between the Company and The Bank of New York, as Trustee, including form of Notes.(m)

	4	.5.2	First Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(h)

	4	.5.3	Second Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(i)

	4	.6.1	Indenture dated as of August 10, 2000, between the Company and Wilmington Trust Company, as Trustee.(n)

	4	.6.2	First Supplemental Indenture dated as of September 28, 2000, between the Company and Wilmington Trust Company, as Trustee.(h)

	4	.6.3	Second Supplemental Indenture dated as of September 30, 2004, between the Company and Wilmington Trust Company, as Trustee.(o)

	4	.6.3	Third Supplemental Indenture dated as of June 23, 2005, between the Company and Wilmington Trust Company, as Trustee.(b)

	4	.7.1	Amended and Restated Indenture dated as of October 16, 2001, between Calpine Canada Energy Finance ULC and Wilmington Trust Company, as Trustee.(p)

	4	.7.2	Guarantee Agreement dated as of April 25, 2001, between the Company and Wilmington Trust Company, as Trustee.(q)

	4	.7.3	First Amendment, dated as of October 16, 2001, to Guarantee Agreement dated as of April 25, 2001, between the Company and Wilmington Trust Company, as Trustee.(p)

	4	.8.1	Indenture dated as of October 18, 2001, between Calpine Canada Energy Finance II ULC and Wilmington Trust Company, as Trustee.(p)

	4	.8.2	First Supplemental Indenture, dated as of October 18, 2001, between Calpine Canada Energy Finance II ULC and Wilmington Trust Company, as Trustee.(p)

	4	.8.3	Guarantee Agreement dated as of October 18, 2001, between the Company and Wilmington Trust Company, as Trustee.(p)

	4	.8.4	First Amendment, dated as of October 18, 2001, to Guarantee Agreement dated as of October 18, 2001, between the Company and Wilmington Trust Company, as Trustee.(p)

	4	.9	Indenture, dated as of June 13, 2003, between Power Contract Financing, L.L.C. and Wilmington Trust Company, as Trustee, Accounts Agent, Paying Agent and Registrar, including form of Notes.(r)

	4	.10	Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(r)

	4	.11	Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(r)

	4	.12	Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(r)

	4	.13.1	Indenture, dated as of August 14, 2003, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee, including form of Notes.(s)

	4	.13.2	Supplemental Indenture, dated as of September 18, 2003, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee.(s)

	4	.13.3	Second Supplemental Indenture, dated as of January 14, 2004, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee.(t)

288


Exhibit
Number			Description


	4	.13.4	Third Supplemental Indenture, dated as of March 5, 2004, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee.(t)

	4	.13.5	Fourth Supplemental Indenture, dated as of March 15, 2006, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee.(*)

	4	.13.6	Waiver Agreement, dated as of March 15, 2006, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee.(*)

	4	.14	Indenture, dated as of September 30, 2003, among Gilroy Energy Center, LLC, each of Creed Energy Center, LLC and Goose Haven Energy Center, as Guarantors, and Wilmington Trust Company, as Trustee and Collateral Agent, including form of Notes.(s)

	4	.15	Indenture, dated as of November 18, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(t)

	4	.16	Amended and Restated Indenture, dated as of March 12, 2004, between the Company and Wilmington Trust Company, including form of Notes.(t)

	4	.17.1	First Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust Company, as Trustee, including form of Notes.(t)

	4	.17.2	Second Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust Company, as Trustee, including form of Notes.(t)

	4	.17.3	Third Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust Company, as Trustee, including form of Notes.(t)

	4	.18	Indenture, dated as of June 2, 2004, between Power Contract Financing III, LLC and Wilmington Trust Company, as Trustee, Accounts Agent, Paying Agent and Registrar, including form of Notes.(d)

	4	.19	Indenture, dated as of September 30, 2004, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(u)

	4	.20.1	Amended and Restated Rights Agreement, dated as of September 19, 2001, between Calpine Corporation and Equiserve Trust Company, N.A., as Rights Agent.(v)

	4	.20.2	Amendment No. 1 to Rights Agreement, dated as of September 28, 2004, between Calpine Corporation and Equiserve Trust Company, N.A., as Rights Agent.(o)

	4	.20.3	Amendment No. 2 to Rights Agreement, dated as of March 18, 2005, between Calpine Corporation and Equiserve Trust Company, N.A., as Rights Agent.(w)

	4	.21.1	Second Amended and Restated Limited Liability Company Operating Agreement of CCFC Preferred Holdings, LLC, dated as of October 14, 2005, containing terms of its 6-Year Redeemable Preferred Shares Due 2011.(*)

	4	.21.2	Consent, Acknowledgment and Amendment, dated as of March 15, 2006, among Calpine CCFC Holdings, Inc. and the Redeemable Preferred Members party thereto.(*)

	4	.22	Third Amended and Restated Limited Liability Company Operating Agreement of Metcalf Energy Center, LLC, dated as of June 20, 2005, containing terms of its 5.5-year redeemable preferred shares.(*)

	4	.23	Pass Through Certificates (Tiverton and Rumford)

	4	.23.1	Pass Through Trust Agreement dated as of December 19, 2000, among Tiverton Power Associates Limited Partnership, Rumford Power Associates Limited Partnership and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including the form of Certificate.(h)

289


Exhibit
Number			Description


	4	.23.2	Participation Agreement dated as of December 19, 2000, among the Company, Tiverton Power Associates Limited Partnership, Rumford Power Associates Limited Partnership, PMCC Calpine New England Investment LLC, PMCC Calpine NEIM LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee.(h)

	4	.23.3	Appendix A — Definitions and Rules of Interpretation.(h)

	4	.23.4	Indenture of Trust, Mortgage and Security Agreement, dated as of December 19, 2000, between PMCC Calpine New England Investment LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, including the forms of Lessor Notes.(h)

	4	.23.5	Calpine Guaranty and Payment Agreement (Tiverton) dated as of December 19, 2000, by the Company, as Guarantor, to PMCC Calpine New England Investment LLC, PMCC Calpine NEIM LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(h)

	4	.23.6	Calpine Guaranty and Payment Agreement (Rumford) dated as of December 19, 2000, by the Company, as Guarantor, to PMCC Calpine New England Investment LLC, PMCC Calpine NEIM LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(h)

	4	.24	Pass Through Certificates (South Point, Broad River and RockGen)

	4	.24.1	Pass Through Trust Agreement A dated as of October 18, 2001, among South Point Energy Center, LLC, Broad River Energy LLC, RockGen Energy LLC and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including the form of 8.400% Pass Through Certificate, Series A.(f)

	4	.24.2	Pass Through Trust Agreement B dated as of October 18, 2001, among South Point Energy Center, LLC, Broad River Energy LLC, RockGen Energy LLC and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including the form of 9.825% Pass Through Certificate, Series B.(f)

	4	.24.3	Participation Agreement (SP-1) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-1, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)

	4	.24.4	Participation Agreement (SP-2) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-2, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)

	4	.24.5	Participation Agreement (SP-3) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-3, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)

	4	.24.6	Participation Agreement (SP-4) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-4, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)

290


Exhibit
Number			Description


	4	.24.7	Participation Agreement (BR-1) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-1, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)

	4	.24.8	Participation Agreement (BR-2) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-2, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)

	4	.24.9	Participation Agreement (BR-3) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-3, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)

	4	.24.10	Participation Agreement (BR-4) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-4, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)

	4	.24.11	Participation Agreement (RG-1) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-1, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)

	4	.24.12	Participation Agreement (RG-2) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-2, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)

	4	.24.13	Participation Agreement (RG-3) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-3, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)

	4	.24.14	Participation Agreement (RG-4) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-4, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)

	4	.24.15	Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-1, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(f)

291


Exhibit
Number			Description


	4	.24.16	Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-2, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(f)

	4	.24.17	Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-3, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(f)

	4	.24.18	Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-4, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(f)

	4	.24.19	Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-1, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(f)

	4	.24.20	Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-2, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(f)

	4	.24.21	Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-3, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(f)

	4	.24.22	Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-4, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(f)

	4	.24.23	Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-1, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(f)

	4	.24.24	Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-2, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(f)

	4	.24.25	Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-3, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(f)

	4	.24.26	Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-4, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(f)

	4	.24.27	Calpine Guaranty and Payment Agreement (South Point SP-1) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-1, LLC, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)

	4	.24.28	Calpine Guaranty and Payment Agreement (South Point SP-2) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-2, LLC, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)

292


Exhibit
Number			Description


	4	.24.29	Calpine Guaranty and Payment Agreement (South Point SP-3) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-3, LLC, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)

	4	.24.30	Calpine Guaranty and Payment Agreement (South Point SP-4) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-4, LLC, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)

	4	.24.31	Calpine Guaranty and Payment Agreement (Broad River BR-1) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-1, LLC, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)

	4	.24.32	Calpine Guaranty and Payment Agreement (Broad River BR-2) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-2, LLC, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)

	4	.24.33	Calpine Guaranty and Payment Agreement (Broad River BR-3) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-3, LLC, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)

	4	.24.34	Calpine Guaranty and Payment Agreement (Broad River BR-4) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-4, LLC, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)

	4	.24.35	Calpine Guaranty and Payment Agreement (RockGen RG-1) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-1, LLC, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)

	4	.24.36	Calpine Guaranty and Payment Agreement (RockGen RG-2) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-2, LLC, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)

	4	.24.37	Calpine Guaranty and Payment Agreement (RockGen RG-3) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-3, LLC, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)

	4	.24.38	Calpine Guaranty and Payment Agreement (RockGen RG-4) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-4, LLC, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)

	10	.1	DIP Financing Agreements

	10	.1.1.1	$2,000,000,000 Amended & Restated Revolving Credit, Term Loan and Guarantee Agreement, dated as of February 23, 2006, among the Company, as borrower, the Subsidiaries of the Company named therein, as guarantors, the Lenders from time to time party thereto, Credit Suisse Securities (USA) LLC and Deutsche Bank Trust Company Americas, as Joint Syndication Agents, Deutsche Bank Securities Inc. and Credit Suisse Securities (USA) LLC, as Joint Lead Arrangers and Joint Bookrunners, and Credit Suisse and Deutsche Bank Trust Company Americas, as Joint Administrative Agents.(*)

293


Exhibit
Number			Description


	10	.1.1.2	First Consent, Waiver and Amendment, dated as of May 3, 2006, to and under the Amended and Restated Revolving Credit, Term Loan and Guarantee Agreement, dated as of February 23, 2006, among Calpine Corporation, as borrower, its subsidiaries named therein, as guarantors, the Lenders party thereto, Deutsche Bank Trust Company Americas, as administrative agent for the First Priority Lenders, Credit Suisse, Cayman Islands Branch, as administrative agent for the Second Priority Term Lenders.(*)

	10	.1.2	Amended and Restated Security and Pledge Agreement, dated as of February 23, 2006, among the Company, the Subsidiaries of the Company signatory thereto and Deutsche Bank Trust Company Americas, as collateral agent.(*)

	10	.2	Financing and Term Loan Agreements

	10	.2.1	Share Lending Agreement, dated as of September 28, 2004, among the Company, as Lender, Deutsche Bank AG London, as Borrower, through Deutsche Bank Securities Inc., as agent for the Borrower, and Deutsche Bank Securities Inc., in its capacity as Collateral Agent and Securities Intermediary.(o)

	10	.2.2	Amended and Restated Credit Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, The Bank of Nova Scotia, as Administrative Agent, LC Bank, Lead Arranger and Sole Bookrunner, Bayerische Landesbank Cayman Islands Branch, as Arranger and Co-Syndication Agent, Credit Lyonnais New York Branch, as Arranger and Co-Syndication Agent, ING Capital LLC, as Arranger and Co-Syndication Agent, Toronto-Dominion (Texas) Inc., as Arranger and Co-Syndication Agent, and Union Bank of California, N.A., as Arranger and Co-Syndication Agent.(t)

	10	.2.3.1	Letter of Credit Agreement, dated as of July 16, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent.(r)

	10	.2.3.2	Amendment to Letter of Credit Agreement, dated as of September 30, 2004, between the Company and The Bank of Nova Scotia, as Administrative Agent.(y)

	10	.2.4	Letter of Credit Agreement, dated as of September 30, 2004, between the Company and Bayerische Landesbank, acting through its Cayman Islands Branch, as the Issuer.(y)

	10	.2.5	Credit Agreement, dated as of July 16, 2003, among the Company, the Lenders named therein, Goldman Sachs Credit Partners L.P., as Sole Lead Arranger, Sole Bookrunner and Administrative Agent, The Bank of Nova Scotia, as Arranger and Syndication Agent, TD Securities (USA) Inc., ING (U.S.) Capital LLC and Landesbank Hessen-Thuringen, as Co-Arrangers, and Credit Lyonnais New York Branch and Union Bank of California, N.A., as Managing Agents.(r)

	10	.2.6.1	Credit and Guarantee Agreement, dated as of August 14, 2003, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(s)

	10	.1.6.2	Amendment No. 1 to the Credit and Guarantee Agreement, dated as of September 12, 2003, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(s)

	10	.2.6.3	Amendment No. 2 to the Credit and Guarantee Agreement, dated as of January 13, 2004, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(t)

	10	.2.6.4	Amendment No. 3 to the Credit and Guarantee Agreement, dated as of March 5, 2004, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(t)

294


Exhibit
Number			Description


	10	.2.6.5	Amendment No. 4 to the Credit and Guarantee Agreement, dated as of March 15, 2006, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(*)

	10	.2.6.6	Waiver Agreement, dated as of March 15, 2006 among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(*)

	10	.2.7	Credit and Guarantee Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, Morgan Stanley Senior Funding, Inc., as Administrative Agent, and Morgan Stanley Senior Funding, Inc., as Sole Lead Arranger and Sole Bookrunner.(t)

	10	.2.8	Credit and Guarantee Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, Morgan Stanley Senior Funding, Inc., as Administrative Agent, and Morgan Stanley Senior Funding, Inc., as Sole Lead Arranger and Sole Bookrunner.(t)

	10	.2.9	Credit Agreement, dated as of June 24, 2004, among Riverside Energy Center, LLC, the Lenders named therein, Union Bank of California, N.A., as the Issuing Bank, Credit Suisse First Boston, acting through its Cayman Islands Branch, as Lead Arranger, Book Runner, Administrative Agent and Collateral Agent, and CoBank, ACB, as Syndication Agent.(z)

	10	.2.10	Credit Agreement, dated as of June 24, 2004, among Rocky Mountain Energy Center, LLC, the Lenders named therein, Union Bank of California, N.A., as the Issuing Bank, Credit Suisse First Boston, acting through its Cayman Islands Branch, as Lead Arranger, Book Runner, Administrative Agent and Collateral Agent, and CoBank, ACB, as Syndication Agent.(z)

	10	.2.11	Credit Agreement, dated as of February 25, 2005, among Calpine Steamboat Holdings, LLC, the Lenders named therein, Calyon New York Branch, as a Lead Arranger, Underwriter, Co-Book Runner, Administrative Agent, Collateral Agent and LC Issuer, CoBank, ACB, as a Lead Arranger, Underwriter, Co-Syndication Agent and Co-Book Runner, HSH Nordbank AG, as a Lead Arranger, Underwriter and Co-documentation Agent, UFJ Bank Limited, as a Lead Arranger, Underwriter and Co-Documentation Agent, and Bayerische Hypo-Und Vereinsbank AG, New York Branch, as a Lead Arranger, Underwriter and Co-Syndication Agent.(z)

	10	.3	Security Agreements

	10	.3.1	Guarantee and Collateral Agreement, dated as of July 16, 2003, made by the Company, JOQ Canada, Inc., Quintana Minerals (USA) Inc., and Quintana Canada Holdings LLC, in favor of The Bank of New York, as Collateral Trustee.(r)

	10	.3.2	First Amendment Pledge Agreement, dated as of July 16, 2003, made by JOQ Canada, Inc., Quintana Minerals (USA) Inc., and Quintana Canada Holdings LLC in favor of The Bank of New York, as Collateral Trustee.(r)

	10	.3.3	First Amendment Assignment and Security Agreement, dated as of July 16, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(r)

	10	.3.4.1	Second Amendment Pledge Agreement (Stock Interests), dated as of July 16, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(r)

	10	.3.4.2	Amendment No. 1 to the Second Amendment Pledge Agreement (Stock Interests), dated as of November 18, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(t)

	10	.3.5.1	Second Amendment Pledge Agreement (Membership Interests), dated as of July 16, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(r)

	10	.3.5.2	Amendment No. 1 to the Second Amendment Pledge Agreement (Membership Interests), dated as of November 18, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(t)

295


Exhibit
Number			Description


	10	.3.6	First Amendment Note Pledge Agreement, dated as of July 16, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(r)

	10	.3.7.1	Collateral Trust Agreement, dated as of July 16, 2003, among the Company, JOQ Canada, Inc., Quintana Minerals (USA) Inc., Quintana Canada Holdings LLC, Wilmington Trust Company, as Trustee, The Bank of Nova Scotia, as Agent, Goldman Sachs Credit Partners L.P., as Administrative Agent, and The Bank of New York, as Collateral Trustee.(r)

	10	.3.7.2	First Amendment to the Collateral Trust Agreement, dated as of November 18, 2003, among the Company, JOQ Canada, Inc., Quintana Minerals (USA) Inc., Quintana Canada Holdings LLC, Wilmington Trust Company, as Trustee, The Bank of Nova Scotia, as Agent, Goldman Sachs Credit Partners L.P., as Administrative Agent, and The Bank of New York, as Collateral Trustee.(t)

	10	.3.8	Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Multistate), dated as of July 16, 2003, from the Company to Messrs. Denis O’Meara and James Trimble, as Trustees, and The Bank of New York, as Collateral Trustee.(r)

	10	.3.9	Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Multistate), dated as of July 16, 2003, from the Company to Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of New York, as Collateral Trustee.(r)

	10	.3.10	Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Colorado), dated as of July 16, 2003, from the Company to Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of New York, as Collateral Trustee.(r)

	10	.3.11	Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (New Mexico), dated as of July 16, 2003, from the Company to Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of New York, as Collateral Trustee.(r)

	10	.3.12	Form of Amended and Restated Mortgage, Assignment, Security Agreement and Financing Statement (Louisiana), dated as of July 16, 2003, from the Company to The Bank of New York, as Collateral Trustee.(r)

	10	.3.13	Form of Amended and Restated Deed of Trust with Power of Sale, Assignment of Production, Security Agreement, Financing Statement and Fixture Filings (California), dated as of July 16, 2003, from the Company to Chicago Title Insurance Company, as Trustee, and The Bank of New York, as Collateral Trustee.(r)

	10	.3.14	Form of Deed to Secure Debt, Assignment of Rents and Security Agreement (Georgia), dated as of July 16, 2003, from the Company to The Bank of New York, as Collateral Trustee.(r)

	10	.3.15	Form of Mortgage, Assignment of Rents and Security Agreement (Florida), dated as of July 16, 2003, from the Company to The Bank of New York, as Collateral Trustee.(r)

	10	.3.16	Form of Deed of Trust, Assignment of Rents and Security Agreement and Fixture Filing (Texas), dated as of July 16, 2003, from the Company to Malcolm S. Morris, as Trustee, in favor of The Bank of New York, as Collateral Trustee.(r)

	10	.3.17	Form of Deed of Trust, Assignment of Rents and Security Agreement (Washington), dated as of July 16, 2003, from the Company to Chicago Title Insurance Company, in favor of The Bank of New York, as Collateral Trustee.(r)

	10	.3.18	Form of Deed of Trust, Assignment of Rents, and Security Agreement (California), dated as of July 16, 2003, from the Company to Chicago Title Insurance Company, in favor of The Bank of New York, as Collateral Trustee.(r)

	10	.3.19	Form of Mortgage, Collateral Assignment of Leases and Rents, Security Agreement and Financing Statement (Louisiana), dated as of July 16, 2003, from the Company to The Bank of New York, as Collateral Trustee.(r)

296


Exhibit
Number			Description


	10	.3.20	Amended and Restated Hazardous Materials Undertaking and Indemnity (Multistate), dated as of July 16, 2003, by the Company in favor of The Bank of New York, as Collateral Trustee.(r)

	10	.3.21	Amended and Restated Hazardous Materials Undertaking and Indemnity (California), dated as of July 16, 2003, by the Company in favor of The Bank of New York, as Collateral Trustee.(r)

	10	.3.22	Designated Asset Sale Proceeds Account Control Agreement, dated as of July 16, 2003, among the Company, Union Bank of California, N.A., and The Bank of New York, as Collateral Agent.(t)

	10	.4	Power Purchase and Other Agreements.

	10	.4.1	Master Transaction Agreement, dated September 7, 2005, among the Company, Calpine Energy Services, L.P., The Bear Stearns Companies Inc., and such other parties as may become party thereto from time to time. Approximately two pages of this Exhibit 10.3.1 have been omitted pursuant to a request for confidential treatment. The omitted language has been filed separately with the SEC.(aa)

	10	.4.2	Power Purchase and Sale Agreements with the State of California Department of Water Resources comprising Amended and Restated Cover Sheet and Master Power Purchase and Sale Agreement, dated as of April 22, 2002 and effective as of May 1, 2004, between Calpine Energy Services, L.P. and the State of California Department of Water Resources together with Amended and Restated Confirmation (“Calpine 1”), Amended and Restated Confirmation (“Calpine 2”), Amended and Restated Confirmation (“Calpine 3”) and Amended and Restated Confirmation (“Calpine 4”), each dated as of April 22, 2002, and effective as of May 1, 2002, between Calpine Energy Services, L.P., and the State of California Department of Water Resources.(bb)

	10	.5	Management Contracts or Compensatory Plans or Arrangements.

	10	.5.1	Employment Agreement, effective as of January 1, 2005, between the Company and Mr. Peter Cartwright.(cc)(dd)

	10	.5.2	Employment Agreement, effective as of December 12, 2005, between the Company and Mr. Robert P. May.(*)(dd)

	10	.5.3	Employment Agreement, effective as of January 30, 2006, between the Company and Mr. Scott J. Davido.(*)(dd)

	10	.5.5	Consulting Contract, effective as of January 1, 2005, between the Company and Mr. George J. Stathakis.(hh)(dd)

	10	.5.6	Form of Indemnification Agreement for directors and officers.(gg)(dd)

	10	.5.7	Form of Indemnification Agreement for directors and officers.(f)(dd)

	10	.5.8.1	Calpine Corporation 1996 Stock Incentive Plan and forms of agreements there under.(t)(dd)

	10	.5.8.2	Amendment to Calpine Corporation 1996 Stock Incentive Plan.(z)(dd)

	10	.5.9	Calpine Corporation U.S. Severance Program.(*)(dd)

	10	.5.10	Base Salary, Bonus, Stock Option Grant and Restricted Stock Summary Sheet.(cc)(dd)

	10	.5.11	Form of Stock Option Agreement.(cc)(dd)

	10	.5.12	Form of Restricted Stock Agreement.(cc)(dd)

	10	.5.13	Calpine Corporation 2003 Management Incentive Plan.(hh)(dd)

	10	.5.14	2000 Employee Stock Purchase Plan.(ii)(dd)

	12	.1	Statement on Computation of Ratio of Earnings to Fixed Charges.(*)

	21	.1	Subsidiaries of the Company.(*)

	24	.1	Power of Attorney of Officers and Directors of Calpine Corporation (set forth on the signature pages of this report).(*)

	31	.1	Certification of the Chairman, President and Chief Executive Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(*)

297


Exhibit
Number			Description


	31	.2	Certification of the Executive Vice President and Chief Financial Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(*)

	32	.1	Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.(*)

	99	.1	Acadia Power Partners, LLC and Subsidiary, Consolidated Financial Statements, July 31, 2005 and December 31, 2004 and 2003.(*)


(*)	Filed herewith.

(a)	Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K/ A filed with the SEC on September 14, 2004.

(b)	Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on June 23, 2005.

(c)	Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on July 13, 2005.

(d)	Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 2004, filed with the SEC on August 9, 2004.

(e)	Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 2005, filed with the SEC on August 9, 2005.

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

(g)	Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration Statement No. 333-06259) filed with the SEC on June 19, 1996.

(h)	Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2000, filed with the SEC on March 15, 2001.

(i)	Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated March 31, 2004, filed with the SEC on May 10, 2004.

(j)	Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 1997, filed with the SEC on August 14, 1997.

(k)	Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration Statement No. 333-41261) filed with the SEC on November 28, 1997.

(l)	Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration Statement No. 333-61047) filed with the SEC on August 10, 1998.

(m)	Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3/ A (Registration Statement No. 333-72583) filed with the SEC on March 8, 1999.

(n)	Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3 (Registration No. 333-76880) filed with the SEC on January 17, 2002.

(o)	Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on September 30, 2004.

(p)	Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K dated October 16, 2001, filed with the SEC on November 13, 2001.

(q)	Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3/ A (Registration No. 333-57338) filed with the SEC on April 19, 2001.

(r)	Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 2003, filed with the SEC on August 14, 2003.

298


(s)	Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated September 30, 2003, filed with the SEC on November 13, 2003.

(t)	Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2003, filed with the SEC on March 25, 2004.

(u)	Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on October 6, 2004.

(v)	Incorporated by reference to Calpine Corporation’s Registration Statement on Form 8-A/ A (Registration No. 001-12079) filed with the SEC on September 28, 2001.

(w)	Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on March 23, 2005.

(x)	This document has been omitted in reliance on Item 601(b)(4)(iii) of Regulation S-K. Calpine Corporation agrees to furnish a copy of such document to the SEC upon request.

(y)	Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated September 30, 2004, filed with the SEC on November 9, 2004.

(z)	Description of such Amendment is incorporated by reference to Item 1.01 of Calpine Corporation’s Current Report on Form 8-K filed with the SEC on September 20, 2005.

(aa)	Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated September 30, 2005, filed with the SEC on November 9, 2005.

(bb)	Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K/ A dated December 31, 2003, filed with the SEC on September 13, 2004

(cc)	Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on March 17, 2005.

(dd)	Management contract or compensatory plan or arrangement.

(ee)	Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on December 27, 2005.

(ff)	Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on February 3, 2006.

(gg)	Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-1/ A (Registration Statement No. 333-07497) filed with the SEC on August 22, 1996.

(hh)	Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2004, filed with the SEC on March 31, 2005.

(ii)	Incorporated by reference to Calpine Corporation’s Definitive Proxy Statement on Schedule 14A dated April 13, 2000, filed with the SEC on April 13, 2000.

299