10-K 1 d10k.htm FORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31, 2007 Form 10-K for the fiscal year ended December 31, 2007
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Index to Financial Statements

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form 10-K

 

                (Mark One)     
                [X]   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934   
For the fiscal year ended December 31, 2007
or
                [    ]   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934   
For the transition period from                      to                     

 

 

Calpine Corporation

(A Delaware Corporation)

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

50 West San Fernando Street, San Jose, California 95113

717 Texas Avenue, Houston, Texas 77002

Telephone: (713) 830-8775

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 [    ]    No [X]

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 [    ]    No [X]

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

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.    [X]

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

 

  Large accelerated filer  [X]

   Accelerated filer  [    ]                

 Non-accelerated filer  [    ]

   Smaller reporting company  [    ]

                                 (Do not check if a smaller reporting company)

  

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

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: Calpine Corporation: 417,872,977 shares of common stock, par value $.001, were outstanding as of February 26, 2008.

State the aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2007, the last business day of the registrant’s most recently completed second fiscal quarter: approximately $1,798 million.

Please indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.    Yes [X]    No [    ]

 

 

 


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Index to Financial Statements

CALPINE CORPORATION AND SUBSIDIARIES

(DEBTOR-IN-POSSESSION)

FORM 10-K

ANNUAL REPORT

For the Year Ended December 31, 2007

TABLE OF CONTENTS

 

     Page

PART I

Item 1.

   Business    1

Item 1A.

   Risk Factors    25

Item 1B.

   Unresolved Staff Comments    37

Item 2.

   Properties    37

Item 3.

   Legal Proceedings    37

Item 4.

   Submission of Matters to a Vote of Security Holders    38

PART II

Item 5.

   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities    38

Item 6.

   Selected Financial Data    39

Item 7.

   Management’s Discussion and Analysis of Financial Condition and Results of Operations    40

Item 7A.

   Quantitative and Qualitative Disclosures about Market Risk    80

Item 8.

   Financial Statements and Supplementary Data    80

Item 9.

   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure    80

Item 9A.

   Controls and Procedures    80

Item 9B.

   Other Information    82

PART III

Item 10.

   Directors and Executive Officers of the Registrant    84

Item 11.

   Executive Compensation    88

Item 12.

   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters    111

Item 13.

   Certain Relationships and Related Transactions, and Director Independence    114

Item 14.

   Principal Accounting Fees and Services    115

PART IV

Item 15.

   Exhibits, Financial Statement Schedule    117

Signatures and Power of Attorney

   142

Index to Consolidated Financial Statements

   144

 

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DEFINITIONS

As used in this report, the abbreviations herein have the meanings set forth below. Additionally, the terms “Calpine,” “we,” “us” and “our” refer to Calpine Corporation and its consolidated subsidiaries, unless the context clearly indicates otherwise. For clarification, during the period covered by this Report and through February 8, 2008, such terms do not include the Canadian and other foreign subsidiaries that were deconsolidated as of the Petition Date. The term “Calpine Corporation” shall refer only to Calpine Corporation and not to any of its subsidiaries. Unless and as otherwise stated, any references in this Report to any agreement means such agreement and all schedules, exhibits and attachments thereto in each case as amended, restated, supplemented or otherwise modified to the date of this Report.

 

ABBREVIATION

  

DEFINITION

2006 Form 10-K

   Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2006, filed with the SEC on March 14, 2007

2008 CIP

   2008 Calpine Incentive Program

2014 Convertible Notes

   Calpine Corporation’s Contingent Convertible Notes Due 2014

2015 Convertible Notes

   Calpine Corporation’s 7 3/4% Contingent Convertible Notes Due 2015

2023 Convertible Notes

   Calpine Corporation’s 4 3/4% Contingent Convertible Senior Notes Due 2023

345(b) Waiver Order

   Order, dated May 4, 2006, pursuant to Section 345(b) of the Bankruptcy Code authorizing continued use of existing investment guidelines and continued operation of certain bank accounts

401(k) Plan

   Calpine Corporation Retirement Savings Plan

Acadia PP

   Acadia Power Partners, LLC

AELLC

   Androscoggin Energy LLC

AlixPartners

   AlixPartners LLP

AOCI

   Accumulated other comprehensive income

APH

   Acadia Power Holdings, LLC, a wholly owned subsidiary of Cleco

AP Services

   AP Services, LLC

Aries

   MEP Pleasant Hill, LLC

ASC

   Aircraft Services Corporation, an affiliate of General Electric Capital Corporation
Auburndale PP    Auburndale Power Partners, L.P.
Bankruptcy Code    U.S. Bankruptcy Code
Bankruptcy Courts    The U.S. Bankruptcy Court and the Canadian Court
Bcf    Billion cubic feet
BLM    Bureau of Land Management of the U.S. Department of the Interior
Bridge Facility    Bridge Loan Agreement, dated as of January 31, 2008, among Calpine Corporation as borrower, the lenders party thereto, Goldman Sachs Credit Partners L.P., Credit Suisse, Deutsche Bank Securities Inc. and Morgan Stanley Senior Funding Inc., as co-documentation agents, and Goldman Sachs Credit Partners L.P., as administrative agent and collateral agent
Btu    British thermal unit(s)
CAA    Federal Clean Air Act of 1970
CAIR    Clean Air Interstate Rule

 

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ABBREVIATION

  

DEFINITION

CAISO    California Independent System Operator
Calgary Energy Centre    Calgary Energy Centre Limited Partnership
CalGen    Calpine Generating Company, LLC
CalGen First Lien Debt    Collectively, $235,000,000 First Priority Secured Floating Rate Notes Due 2009 issued by CalGen and CalGen Finance Corp.; $600,000,000 First Priority Secured Institutional Term Loans Due 2009 issued by CalGen; and the CalGen First Priority Revolving Loans
CalGen First Priority Revolving Loans    $200,000,000 First Priority Revolving Loans issued on or about March 23, 2004, pursuant to that Amended and Restated Agreement, among CalGen, the guarantors party thereto, the lenders party thereto, The Bank of Nova Scotia, as administrative agent, L/C 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
CalGen Second Lien Debt    Collectively, $640,000,000 Second Priority Secured Floating Rate Notes Due 2010 issued by CalGen and CalGen Finance; and $100,000,000 Second Priority Secured Institutional Term Loans Due 2010 issued by CalGen
CalGen Secured Debt    Collectively, the CalGen First Lien Debt, the CalGen Second Lien Debt and the CalGen Third Lien Debt
CalGen Third Lien Debt    Collectively, $680,000,000 Third Priority Secured Floating Rate Notes Due 2011 issued by CalGen and CalGen Finance; and $150,000,000 11 1/2% Third Priority Secured Notes Due 2011 issued by CalGen and CalGen Finance
Calpine Debtor(s)    The U.S. Debtors and the Canadian Debtors
Calpine Equity Incentive Plans    Calpine Corporation 2008 Equity Incentive Plan and Calpine Corporation 2008 Director Incentive Plan, which provide for grants of equity awards to Calpine employees and non-employee members of Calpine’s Board of Directors
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
Canadian Effective Date    February 8, 2008, the date on which the Canadian Court ordered and declared that the Canadian Debtors’ proceedings under the CCAA were terminated
Canadian Settlement Agreement    Settlement Agreement dated as of July 24, 2007, by and between Calpine Corporation, on behalf of itself and its U.S. subsidiaries, Calpine Canada Energy Ltd., Calpine Canada Power Ltd., Calpine Canada Energy Finance ULC, Calpine Energy Services Canada Ltd., Calpine Canada Resources Company, Calpine Canada Power Services Ltd., Calpine Canada Energy Finance II ULC, Calpine Natural Gas Services Limited, 3094479 Nova Scotia Company, Calpine Energy Services Canada Partnership, Calpine Canada Natural Gas Partnership, Calpine Canadian Saltend Limited Partnership and HSBC Bank USA, National Association, as successor indenture trustee

 

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ABBREVIATION

  

DEFINITION

Cash Collateral Order    Second Amended Final Order of the U.S. Bankruptcy Court Authorizing Use of Cash Collateral and Granting Adequate Protection, dated February 24, 2006 as modified by orders of the U.S. Bankruptcy Court on June 21, 2006, July 12, 2006, October 25, 2006, November 15, 2006, December 20, 2006, December 28, 2006, January 17, 2007, and March 1, 2007
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
CERCLA    Comprehensive Environmental Response, Compensation and Liability Act, as amended, also called “Superfund”
CES    Calpine Energy Services, L.P.
CES-Canada    Calpine Energy Services Canada Partnership
Chapter 11    Chapter 11 of the Bankruptcy Code
CIP    2007 Calpine Incentive Plan
Cleco    Cleco Corp.
CO2    Carbon dioxide
Collateral Trustee    The Bank of New York as collateral trustee for holders of First Priority Notes and Second Priority Debt
Committees    Creditors’ Committee, Equity Committee, and Ad Hoc Committee of Second Lien Holders of Calpine Corporation
Commodity margin    Non-GAAP financial measure that includes electricity and steam revenues, hedging and optimization activities, renewable energy credit revenue, transmission revenue and expenses, and fuel and purchased energy expenses, but excludes mark-to-market activity and other service revenues
Company    Calpine Corporation, a Delaware corporation, and subsidiaries
Confirmation Order    The order of the U.S. Bankruptcy Court entitled “Findings of Fact, Conclusions of Law, and Order Confirming Sixth Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the Bankruptcy Code,” entered December 19, 2007, confirming the Plan of Reorganization pursuant to section 1129 of the Bankruptcy Code
Convertible Notes    Collectively, the 2014 Convertible Notes, the 2015 Convertible Notes, the 2023 Convertible Notes and Calpine Corporation’s 4% Convertible Senior Notes due 2006
CPIF    Calpine Power Income Fund
CPUC    California Public Utilities Commission
Creditors’ Committee    The Official Committee of Unsecured Creditors of Calpine Corporation appointed by the Office of the U.S. Trustee
Creed    Creed Energy Center, LLC
DB London    Deutsche Bank AG London

 

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ABBREVIATION

  

DEFINITION

Deer Park    Deer Park Energy Center Limited Partnership
DIP    Debtor-in-possession
DIP Facility    The Revolving Credit, Term Loan and Guarantee Agreement, dated as of March 29, 2007, among the Company, as borrower, certain of the Company’s subsidiaries, as guarantors, the lenders party thereto, Credit Suisse, Goldman Sachs Credit Partners L.P. and JPMorgan Chase Bank, N.A., as co-syndication agents and co-documentation agents, General Electric Capital Corporation, as sub-agent, and Credit Suisse, as administrative agent and collateral agent, with Credit Suisse Securities (USA) LLC, Goldman Sachs Credit Partners L.P., JPMorgan Securities Inc., and Deutsche Bank Securities Inc. acting as Joint Lead Arrangers and Bookrunners
DIP Order    Order of the U.S. Bankruptcy Court dated March 12, 2007, approving the DIP Facility
Disclosure Statement    Disclosure Statement for Debtors’ Joint Plan of Reorganization Pursuant to Chapter 11 of the U.S. Bankruptcy Code filed by the U.S. Debtors with the U.S. Bankruptcy Court on June 20, 2007, as amended, modified or supplemented through the filing of this Report pursuant to the Plan of Reorganization
EBITDA    Earnings before interest, taxes, depreciation, and amortization
Effective Date    January 31, 2008, the date on which the conditions precedent enumerated in the Plan of Reorganization were satisfied or waived and the Plan of Reorganization became effective
EIA    Energy Information Administration of the U.S. Department of Energy
EIP    Emergence Incentive Plan
EPA    U.S. Environmental Protection Agency
EPAct 1992    Energy Policy Act of 1992
EPAct 2005    Energy Policy Act of 2005
EPS    Earnings per share
Equity Committee    The Official Committee of the Equity Security Holders of Calpine Corporation appointed by the Office of the U.S. Trustee
ERC(s)    Emission reduction credit(s)
ERCOT    Electric Reliability Council of Texas
ERISA    Employee Retirement Income Security Act
ERO    Electric Reliability Organization
ESA    Energy Services Agreement
ESPP    2000 Employee Stock Purchase Plan
EWG(s)    Exempt wholesale generator(s)
Exchange Act    U.S. Securities Exchange Act of 1934, as amended
Exit Credit Facility    Credit Agreement, dated as of January 31, 2008, among Calpine Corporation, as borrower, the lenders party thereto, General Electric Capital Corporation, as sub-agent, Goldman Sachs Credit Partners L.P., Credit Suisse, Deutsche Bank Securities Inc., and Morgan Stanley Senior Funding, Inc., as co-syndication agents and co-documentation agents, and Goldman Sachs Credit Partners L.P., as administrative agent and collateral agent

 

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ABBREVIATION

  

DEFINITION

Exit Facilities    Together, the Exit Credit Facility and the Bridge Facility
FASB    Financial Accounting Standards Board
FERC    Federal Energy Regulatory Commission
FIN    FASB Interpretation Number
First Priority Notes    9 5/8% First Priority Senior Secured Notes Due 2014
First Priority Trustee    Until February 2, 2006, Wilmington Trust Company, as trustee, and from February 3, 2006, and thereafter, Law Debenture Trust Company of New York, as successor trustee, under the Indenture, dated as of September 30, 2004, with respect to the First Priority Notes
FPA    Federal Power Act
FRCC    Florida Reliability Coordinating Council
Freeport    Freeport Energy Center, LP
Fremont    Fremont Energy Center, LLC
FSP    FASB Staff Position
FUCO(s)    Foreign Utility Company(ies)
GAAP    Generally accepted accounting principles in the U.S.
GE    General Electric International, Inc.
GEC    Gilroy Energy Center, LLC
General Electric    General Electric Company
Geysers Assets    19 (17 active) geothermal power plant assets located in northern California
GHG    Greenhouse gas
Gilroy    Calpine Gilroy Cogen, L.P.
Goose Haven    Goose Haven Energy Center, LLC
Greenfield LP    Greenfield Energy Centre LP
Harbert Convertible Fund    Harbert Convertible Arbitrage Master Fund, L.P.
Harbert Distressed Fund    Harbert Distressed Investment Master Fund, Ltd.
Heat Rate    A measure that represents the energy conversion rate for transforming a Btu of fuel into a unit of electricity such as a KWh
Hg    Mercury
HIGH TIDES III    5% Convertible Preferred Securities, Remarketable Term Income Deferrable Equity Securities issued by Calpine Capital Trust III
Hillabee    Hillabee Energy Center, LLC
ICT    Independent Coordinator of Transmission
IPP(s)    Independent power producer(s)
IRS    U.S. Internal Revenue Service
ISO    Independent System Operator
ISO NE    ISO New England
King City Cogen    Calpine King City Cogen, LLC
KWh    Kilowatt hour(s)

 

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ABBREVIATION

  

DEFINITION

LIBOR    London Inter-Bank Offered Rate
LNG    Liquefied natural gas
LSTC    Liabilities subject to compromise
LTSA    Long Term Service Agreement
Mankato    Mankato Energy Center, LLC
MEIP    Calpine Corporation 2008 Equity Incentive Plan
Metcalf    Metcalf Energy Center, LLC
MISO    Midwest ISO
Mitsui    Mitsui & Co., Ltd.
MLCI    Merrill Lynch Commodities, Inc.
MMBtu    Million Btu(s)
MRO    Midwest Reliability Organization
MRTU    CAISO’s Market Redesign and Technology Upgrade
MW    Megawatt(s)
MWh    Megawatt hour(s)
NAAQS    National Ambient Air Quality Standards
NERC    North American Electric Reliability Council
NGA    Natural Gas Act
NGPA    Natural Gas Policy Act
Ninth Circuit Court of Appeals    U.S. Court of Appeals for the Ninth Circuit
NOL(s)    Net operating loss(es)
Non-Debtor(s)    The subsidiaries and affiliates of Calpine Corporation that are not Calpine Debtors
Non-U.S. Debtor(s)    The consolidated subsidiaries and affiliates of Calpine Corporation that are not U.S. Debtor(s)
Northern District Court    U.S. District Court for the Northern District of California
NOx    Nitrogen oxide
NPCC    Northeast Power Coordinating Council
NYISO    New York ISO
NYSE    New York Stock Exchange
O&M    Operations and maintenance
OCI    Other comprehensive income
OMEC    Otay Mesa Energy Center, LLC
Ontelaunee    Ontelaunee Energy Center
OPA    Ontario Power Authority

 

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ABBREVIATION

  

DEFINITION

Original DIP Facility    The Revolving Credit, Term Loan and Guarantee Agreement, dated as of December 22, 2005, as amended on January 26, 2006, and as amended and restated by that certain Amended and Restated Revolving Credit, Term Loan and Guarantee Agreement, dated as of February 23, 2006, among Calpine Corporation, as borrower, the Guarantors party thereto, the Lenders from time to time party thereto, Credit Suisse Securities (USA) LLC and Deutsche Bank Securities Inc., as joint syndication agents, Deutsche Bank Trust Company Americas, as administrative agent for the First Priority Lenders, General Electric Capital Corporation, as Sub-Agent for the Revolving Lenders, Credit Suisse, as administrative agent for the Second Priority Term Lenders, Landesbank Hessen Thuringen Girozentrale, New York Branch, General Electric Capital Corporation and HSH Nordbank AG, New York Branch, as joint documentation agents for the First Priority Lenders and Bayerische Landesbank, General Electric Capital Corporation and Union Bank of California, N.A., as joint documentation agents for the Second Priority Lenders
Panda    Panda Energy International, Inc., and related party PLC II, LLC
PCF    Power Contract Financing, LLC
PCF III    Power Contract Financing III, LLC
Petition Date    December 20, 2005
PG&E    Pacific Gas and Electric Company
Pink Sheets    Pink Sheets Electronic Quotation Service maintained by Pink Sheets LLC for the National Quotation Bureau, Inc.
PJM    Pennsylvania-New Jersey-Maryland Interconnection
Plan of Reorganization    Debtors’ Sixth Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the U.S. Bankruptcy Code filed by the U.S. Debtors with the U.S. Bankruptcy Court on December 19, 2007, as amended, modified or supplemented through the filing of this Report
POX    Plant operating expense
PPA(s)    Any contract for a physically settled sale (as distinguished from a financially settled future, option or other derivative or hedge transaction) of any electric power product, including electric energy, capacity and/or ancillary services, in the form of a bilateral agreement or a written or oral confirmation of a transaction between two parties to a master agreement, including sales related to a tolling transaction in which part of the consideration provided by the purchaser of an electric power product is the fuel required by the seller to generate such electric power
PSM    Power Systems Manufacturing, LLC
PUC(s)    Public Utility Commission(s)
PUCT    Public Utility Commission of Texas
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), which are cogeneration facilities and certain small power production facilities eligible to be “qualifying facilities” under PURPA, provided that they meet certain electricity and thermal energy production requirements and efficiency standards. QF status provides an exemption from PUHCA 2005 and grants certain other benefits to the QF

 

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ABBREVIATION

  

DEFINITION

RCRA    Resource Conservation and Recovery Act
RFC    Reliability First Corporation
RGGI    Regional Greenhouse Gas Initiative
RMR Contract(s)    Reliability Must Run contract(s)
RockGen Owner Lessors    Collectively, RockGen OL-1, LLC; RockGen OL-2, LLC; RockGen OL-3, LLC and RockGen OL-4, LLC
Rosetta    Rosetta Resources Inc.
RTO    Regional Transmission Organization
Saltend    Saltend Energy Centre
SDG&E    San Diego Gas & Electric Company
SDNY Court    U.S. District Court for the Southern District of New York
SEC    U.S. Securities and Exchange Commission
Second Priority Debt    Collectively, the Second Priority Notes and the Second Priority Term Loans
Second Priority Notes    Calpine Corporation’s Second Priority Senior Secured Floating Rate Notes due 2007, 8 1/2% Second Priority Senior Secured Notes due 2010, 8 3/4% Second Priority Senior Secured Notes due 2013 and 9 7/8% Second Priority Senior Secured Notes due 2011
Second Priority Term Loans    Calpine Corporation’s Second Priority Senior Secured Term Loans due 2007
Securities Act    U.S. Securities Act of 1933, as amended
SERC    Southeastern Electric Reliability Council
SFAS    Statement of Financial Accounting Standards
SIP    1996 Stock Incentive Plan
SO2    Sulfur dioxide
SOP 90-7    Statement of Position 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code”

Spark spread

   The spread between the sales price for electricity generated and the cost of fuel

SPP

   Southwest Power Pool

TCEQ

   Texas Commission on Environmental Quality

TTS

   Thomassen Turbine Systems, B.V.

ULC I

   Calpine Canada Energy Finance ULC

ULC II

   Calpine Canada Energy Finance II ULC

Unsecured Noteholders

   Collectively, the holders of the Unsecured Notes

Unsecured Notes

   Collectively, Calpine Corporation’s 7 7/8% Senior Notes due 2008, 7 3/4% Senior Notes due 2009, 8 5/8% Senior Notes due 2010 and 8 1/2% Senior Notes due 2011, which constitutes a portion of Calpine Corporation’s unsecured senior notes

U.S.

   United States of America

U.S. Bankruptcy Court

   U.S. Bankruptcy Court for the Southern District of New York

U.S. Debtor(s)

   Calpine Corporation and each of its subsidiaries and affiliates that have filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court, which matters are being jointly administered in the U.S. Bankruptcy Court under the caption In re Calpine Corporation, et al., Case No. 05-60200 (BRL)

 

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ABBREVIATION

  

DEFINITION

VIE(s)

   Variable interest entity(ies)

WECC

   Western Electricity Coordinating Council

 

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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 and Section 21E of the Exchange Act. We use words such as “believe,” “intend,” “expect,” “anticipate,” “plan,” “may,” “will” and similar expressions to identify forward-looking statements. Such statements include, among others, those concerning our expected financial performance and strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. You are cautioned that any such forward-looking statements are not guarantees of future performance and that a number of risks and uncertainties could cause actual results to differ materially from those anticipated in the forward-looking statements. Such risks and uncertainties include, but are not limited to: (i) our ability to implement our business plan; (ii) financial results that may be volatile and may not reflect historical trends; (iii) seasonal fluctuations of our results and exposure to variations in weather patterns; (iv) potential volatility in earnings associated with fluctuations in prices for commodities such as natural gas and power; (v) our ability to manage liquidity needs and comply with covenants related to our Exit Facilities and other existing financing obligations; (vi) our ability to complete the implementation of our Plan of Reorganization and the discharge of our Chapter 11 cases including successfully resolving any remaining claims; (vii) disruptions in or limitations on the transportation of natural gas and transmission of electricity; (viii) the expiration or termination of our PPAs and the related results on revenues; (ix) risks associated with the operation of power plants including unscheduled outages; (x) 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; (xi) risks associated with power project development and construction activities; (xii) our ability to attract, retain and motivate key employees including filling certain significant positions within our management team; (xiii) our ability to attract and retain customers and counterparties; (xiv) competition; (xv) risks associated with marketing and selling power from plants in the evolving energy markets; (xvi) present and possible future claims, litigation and enforcement actions; (xvii) effects of the application of laws or regulations, including changes in laws or regulations or the interpretation thereof; and (xviii) other risks identified in this Report. You should also carefully review other reports that we file with the SEC. 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, 717 Texas Avenue, Houston, TX 77002, attention: Corporate Communications, telephone: (713) 830-8775. We will not send exhibits to the documents, unless the exhibits are specifically requested and you pay our fee for duplication and delivery.

 

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OVERVIEW

Our Business

We are an independent power producer that operates and develops clean and reliable power generation facilities in North America. Our primary business is the generation and sale of electricity and electricity-related products and services to wholesale and industrial customers through the operation of our portfolio of owned and leased power generation assets with approximately 24,000 MW of generating capacity. We market electricity produced by our generating facilities to utilities and other third party purchasers. Our commercial marketing and energy trading organizations work closely with our plant operations team to protect and enhance the value of our assets by coordinating dispatch and utilization of our power plants with maintenance schedules to achieve effective deployment of our portfolio.

Our power generation facilities comprise two fuel-efficient and clean power generation technologies: natural gas-fired combustion (primarily combined-cycle) and renewable geothermal facilities. At December 31, 2007, we owned or leased a portfolio of 60 active, clean burning, natural gas-fired power plants throughout the U.S. and 17 active geothermal power plants in the Geysers region of northern California. Our natural gas-fired portfolio is equipped with modern and efficient power generation technologies and is an example of our commitment to clean energy production. Our geothermal plants are low variable-cost facilities that harness the power of the Earth’s naturally occurring steam geysers to generate electricity. Our geothermal energy portfolio is one of the largest producing geothermal resources in the world. In addition to our operating plants, we have interests in two plants in active construction and one plant in active development.

We seek to optimize the profitability of our individual facilities by coordinating O&M and major maintenance schedules, as well as dispatch and fuel supply, throughout our portfolio. We manage the energy commodity price risk of our power generation facilities as an integrated portfolio in the major U.S. markets in which we operate. By centrally managing the portfolio, our sales and marketing resources are able to more efficiently serve our power generation facilities by providing trading and scheduling services to meet delivery requirements, respond to market signals and to ensure fuel is delivered to our facilities. Central management also enables us to reduce our exposure to market volatility and improve our results. In the event that one of our facilities is unavailable or less economic to run in a particular market, we might call upon another one of our facilities in the same market to generate the electricity promised to a customer. Such coordination has allowed us to achieve a high level of reliability. We also have developed risk management guidelines, approved by our Board of Directors, which apply to the sales, marketing, trading and scheduling processes. Market risks are monitored to ensure compliance with our risk management guidelines and to seek to minimize our exposure to those risks. We believe that our capabilities, guidelines and arrangements collectively create efficiencies and value for the enterprise beyond what we could achieve by operating each power plant on a stand-alone basis.

Although we centrally manage our portfolio, we assess our business primarily on a regional basis due to the impact on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors impacting supply and demand. Accordingly, our reportable segments are West (including geothermal), Texas, Southeast, North and Other. Over 77% of our generation in 2007 was attributable to our West and Texas segments. Our “Other” segment includes fuel management, our turbine maintenance group, our TTS and PSM businesses for periods prior to their sale and certain hedging and other corporate activities. See Note 16 of the Notes to Consolidated Financial Statements for financial information about our business segments and “—Description of Power Generation Facilities” for a list of our power plants and generation statistics by segment.

We were organized as a corporation in 1984 for the purpose of providing clean energy and services to the newly emerging independent power industry. Our principal offices are located in San Jose, California and Houston, Texas, and we operate our business through a variety of divisions, subsidiaries and affiliates.

 

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Chapter 11 Cases and CCAA Proceedings

Background — From the Petition Date and through the Effective Date, we operated as a debtor-in-possession under the protection of the U.S. Bankruptcy Court following filings by Calpine Corporation and 274 of its wholly owned U.S. subsidiaries for voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. In addition, during that period, 12 of our Canadian subsidiaries that had filed for creditor protection under the CCAA also operated as debtors-in-possession under the jurisdiction of the Canadian Court.

As a result of the filings under the CCAA, we deconsolidated most of our Canadian and other foreign entities as of the Petition Date as we determined that the administration of the CCAA proceedings in a jurisdiction other than that of the U.S. Debtors’ Chapter 11 cases resulted in a loss of the elements of control necessary for consolidation. We fully impaired our investment in the Canadian and other foreign subsidiaries as of the Petition Date and, through the period covered by this Report, accounted for such investments under the cost method. On February 8, 2008, the Canadian Effective Date, the proceedings under the CCAA were terminated and, accordingly, these entities were reconsolidated. Because the reconsolidation occurred after December 31, 2007, our Consolidated Financial Statements exclude the financial statements of the Canadian Debtors, and the information in this Report principally describes the Chapter 11 cases and only describes the CCAA proceedings where they have a material effect on our operations or where such description provides necessary background information.

During the pendency of our Chapter 11 cases through the Effective Date, pursuant to automatic stay provisions under the Bankruptcy Code and orders granted by the Canadian Court, all actions to enforce or otherwise effect repayment of liabilities preceding the Petition Date as well as all pending litigation against the Calpine Debtors generally were stayed. Following the Effective Date, actions to enforce or otherwise effect repayment of liabilities preceding the Petition Date, as well as pending litigation against the Calpine Debtors related to such liabilities generally have been permanently enjoined. Any unresolved claims will continue to be subject to the claims reconciliation process under the supervision of the U.S. Bankruptcy Court. However, certain pending litigation related to pre-petition liabilities may proceed in courts other than the U.S. Bankruptcy Court to the extent the parties to such litigation have obtained relief from the permanent injunction.

Plan of Reorganization — On June 20, 2007, the U.S. Debtors filed the Debtors’ Joint Plan of Reorganization and related Disclosure Statement, which were subsequently amended on each of August 27, September 18, September 24, September 27 and December 13, 2007. On December 19, 2007, we filed the Sixth Amended Joint Plan of Reorganization. As a result of the modifications to the Plan of Reorganization as well as settlements reached by stipulation with certain creditors, all classes of creditors entitled to vote ultimately voted to approve the Plan of Reorganization. The Plan of Reorganization, which provides that the total enterprise value of the reorganized U.S. Debtors for purposes of the Plan of Reorganization is $18.95 billion, also provided for the amendment and restatement of our certificate of incorporation and the adoption of the Calpine Equity Incentive Plans. The Plan of Reorganization was confirmed by the U.S. Bankruptcy Court on December 19, 2007, and became effective on January 31, 2008.

The Plan of Reorganization provides for the treatment of claims against and interests in the U.S. Debtors. Pursuant to the Plan of Reorganization, allowed administrative claims and priority tax claims will be paid in full in cash or cash equivalents, as will allowed first and second lien debt claims. Other allowed secured claims will be reinstated, paid in full in cash or cash equivalents, or have the collateral securing such claims returned to the secured creditor. Allowed make whole claims arising in connection with the repayment of the CalGen Second Lien Debt and the CalGen Third Lien Debt will be paid in full in cash or cash equivalents, which may include cash proceeds generated from the sale of common stock of the reorganized Calpine Corporation pursuant to the Plan of Reorganization. To the extent that the common stock reserved on account of such make whole claims is insufficient to generate sufficient cash proceeds to satisfy such claims in full, the Company must use other available cash to satisfy such claims. Allowed unsecured claims will receive a pro rata distribution of all common

 

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stock of the reorganized Calpine Corporation to be distributed under the Plan of Reorganization (except shares reserved for issuance under the Calpine Equity Incentive Plans). Allowed unsecured convenience claims (subject to certain exceptions, all unsecured claims $50,000 or less) will be paid in full in cash or cash equivalents. Holders of allowed interests in Calpine Corporation (primarily holders of Calpine Corporation common stock existing as of the Petition Date) will receive a pro rata share of warrants to purchase approximately 48.5 million shares of reorganized Calpine Corporation common stock, subject to certain terms. Holders of subordinated equity securities claims will not receive a distribution under the Plan of Reorganization and may only recover from applicable insurance proceeds. Because certain disputed claims were not resolved as of the Effective Date and are not yet finally adjudicated, no assurances can be given that actual claim amounts may not be materially higher or lower than confirmed in the Plan of Reorganization.

In connection with the consummation of the Plan of Reorganization, we closed on our approximately $7.3 billion of Exit Facilities, comprising the outstanding loan amounts and commitments under the $5.0 billion DIP Facility (including the $1.0 billion revolver), which were converted into exit financing under the Exit Credit Facility, approximately $2.0 billion of additional term loan facilities under the Exit Credit Facility and $300 million of term loans under the Bridge Facility. Amounts drawn under the Exit Facilities at closing were used to fund cash payment obligations under the Plan of Reorganization including the repayment of a portion of the Second Priority Debt and the payment of administrative claims and other pre-petition claims, as well as to pay fees and expenses in connection with the Exit Facilities and for working capital and general corporate purposes.

Pursuant to the Plan of Reorganization, all shares of our common stock outstanding prior to the Effective Date were canceled, and we authorized the issuance of 485 million new shares of reorganized Calpine Corporation common stock, of which approximately 421 million shares have been distributed to holders of allowed unsecured claims against the U.S. Debtors (of which approximately 10 million are being held in escrow pending resolution of certain intercreditor matters), and approximately 64 million shares have been reserved for distribution to holders of disputed unsecured claims whose claims ultimately become allowed. We estimate that the number of shares reserved was more than sufficient to satisfy the U.S. Debtors’ obligations under the Plan of Reorganization even if all disputed unsecured claims ultimately become allowed. As disputed claims are resolved, the claimants receive distributions of shares from the reserve on the same basis as if such distributions had been made on or about the Effective Date. To the extent that any of the reserved shares remain undistributed upon resolution of the remaining disputed claims, such shares will not be returned to us but rather will be distributed pro rata to claimants with allowed claims to increase their recovery. We are not required to issue additional shares above the 485 million shares authorized to settle unsecured claims, even if the shares remaining for distribution are not sufficient to fully pay all allowed unsecured claims. Accordingly, resolution of these claims could have a material effect on creditor recoveries under the Plan of Reorganization as the total number of shares of common stock that remain available for distribution upon resolution of disputed claims is limited pursuant to the Plan of Reorganization.

In addition to the 485 million shares authorized to be issued to settle unsecured claims, pursuant to the Plan of Reorganization, we authorized the issuance to certain of our subsidiaries of additional shares of new common stock to be applied to the termination of certain intercompany balances. Upon termination of the intercompany balances on February 1, 2008, these additional shares were returned to us and have been restored to our authorized shares available for future issuance.

In addition, pursuant to the Plan of Reorganization, we authorized the issuance of up to 15 million shares under the Calpine Equity Incentive Plans and we issued warrants to purchase approximately 48.5 million shares of common stock at $23.88 per share to holders of our previously outstanding common stock. Each warrant represents the right to purchase a single share of our new common stock and will expire on August 25, 2008.

The reorganized Calpine Corporation common stock is listed on the NYSE. Our common stock began “when issued” trading on the NYSE under the symbol “CPN-WI” on January 16, 2008, and began “regular way” trading on the NYSE under the symbol “CPN” on February 7, 2008. Our authorized equity consists of 1.5 billion

 

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shares of common stock, par value $.001 per share, and 100 million shares of preferred stock which may be issued in one or more series, with such voting rights and other terms as our Board of Directors determines.

Several parties have filed appeals seeking reconsideration of the Confirmation Order. See Note 15 of the Notes to Consolidated Financial Statements for more information.

CCAA Proceedings. Upon the application of the Canadian Debtors, on February 8, 2008, the Canadian Court ordered and declared that (i) the unsecured notes issued by ULC I were canceled and discharged on February 4, 2008, (ii) the Canadian Debtors had completed all distributions previously ordered in full satisfaction of the pre-filing claims against them, (iii) the Canadian Debtors had otherwise fully complied with all orders of the Canadian Court and (iv) the proceedings under the CCAA were terminated, including the stay of proceedings.

As a result of the termination of the CCAA proceedings, the Canadian Debtors and other deconsolidated foreign entities, consisting of a 50% ownership interest in the 50-MW Whitby Cogeneration power plant, approximately $34 million of debt and various working capital items, were reconsolidated on the Canadian Effective Date.

Business Initiatives

Prior to and during 2007, in connection with our restructuring, we undertook an asset rationalization process that resulted in the divestiture of nine power plants and two subsidiary businesses, TTS and PSM, that provide services and parts for combustion turbine equipment, that were determined to be under-performing or non-core businesses. In addition, we entered into an agreement to sell a development project, and closed the sale of a second, for each of which construction had been suspended, and we entered into an asset purchase agreement for the RockGen Energy Center, which we previously leased. We restructured existing agreements or reconfigured equipment to enhance the economic or operational performance of five power plants for which we had previously agreed to limit the amount of funds available to support operations; as a result of such actions, the limitations were terminated. We are also actively marketing two natural gas-fired power plants and their eventual sale remains a possibility. We continue to evaluate our power generation portfolio and other business activities on an ongoing basis to determine if actions should be taken with respect to other assets, including whether any should be marketed for potential divestiture and if other actions including restructurings, expansions, improvements or personnel and other overhead adjustments should be implemented in order to optimize productivity and the economics of the asset.

All new development projects, including expansions of existing projects, are evaluated based on a variety of factors to determine the optimal opportunities for us and our fleet. We will continue to seek opportunities to develop our business through selective acquisitions, joint ventures, and divestitures to further enhance our asset mix and competitive position.

We maintain a fleet-wide operating data acquisition, retrieval and storage system, and employ a condition-based maintenance program to evaluate the current status of our turbine fleet based on inspections and operating conditions to determine the most efficient timing to replace worn parts. We intend to further develop and enhance our plant monitoring systems on an ongoing basis to provide an advanced fleet-wide management tool that will integrate all plant natural gas, steam, and power volumes into a common system to handle reporting, billing, monitoring, and billing disputes in a cost-efficient and regulatory-compliant manner.

We strive to continually improve our risk management policy and procedures and the infrastructure required to support risk management, which may be modified from time to time as determined by our senior management and our Board of Directors. All of our energy commodity risk is managed within the limits defined in our risk management policy. Our senior management team will review and approve long-term strategic actions. Long-term strategies will generally seek to balance our market view of commodity prices and the economic value we are seeking to capture with the perceived impact on our risk profile by our investors and rating agencies and the cost of implementing that strategy for our collateral and capital structure.

 

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THE MARKET FOR ELECTRICITY

Overview

The power industry represents one of the largest industries in the U.S. and impacts nearly every aspect of our economy, with an estimated end-user market comprising approximately $339 billion of electricity sales in 2007 based on information published by EIA. Historically, vertically integrated electric utilities with monopolistic control over franchised territories dominated the power generation industry in the U.S. However, industry trends and regulatory initiatives designed to encourage competition in wholesale electricity markets 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, major financial institutions and others. For over a 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, halted or even reversed in some geographic regions, in terms of the level of competition, pricing mechanisms and pace of regulatory reform, two of our largest markets, West and Texas, have emerged as more competitive markets.

Four key market “drivers” significantly affect our financial performance. These are the regional supply and demand environment for electricity, regional generation technology and fuel mix, natural gas prices and environmental regulations.

While our market drivers are subject to risk, some of the uncertainty is reduced by the existence of steam sales contracts and PPAs which dictate the payments we receive for energy and capacity and by the hedging activities that are undertaken by our energy trading group. The balance of our generation not subject to steam sales contracts and PPAs is sold into the market. Although these sales are subject to the risk of unfavorable movements in prices, much of our projected earnings from sales into the market are hedged through forward sales or other derivative transactions. We continue to pursue opportunities to secure steam sales contracts and PPAs where they are considered to be more preferable to sales directly into the market.

Regional Supply and Demand

The current U.S. market consists of distinct regional electric markets, not all of which are effectively interconnected. As a result, reserve margins (the measure of how much the total generating capacity installed in a region exceeds the peak demand for power in that region) vary from region to region. For example, a reserve margin of 15% indicates that supply exceeds expected peak electricity demand by 15%. Holding other factors constant, lower reserve margins typically lead to higher power prices, because the less efficient capacity in the region is needed to satisfy electricity demand.

Regional supply and demand affect the pricing for electricity that results from wholesale market competition, and, consequently, are key drivers of our financial performance. For much of the 1990s, utilities invested relatively sparingly in new generating capacity. As a result, by the late 1990s, many regional markets were in need of new capacity to meet growing electricity demand. Prices rose due to capacity shortages, and the emerging merchant power industry responded by constructing significant amounts of new capacity. Between 2000 and 2003, more than 175,000 MW of new generating capacity came “on line” in the United States. In most regions, these new capacity additions far outpaced the growth of demand, resulting in “overbuilt” markets, i.e., markets with excess capacity. In the West, for example, approximately 24,000 MW of new generating capacity was added between 2000 and 2003, while demand only increased by approximately 8,000 MW. Most of this new generating capacity consisted of gas-fired combined-cycle plants which use a gas turbine to create electricity, then capture, or recycle, the waste heat to create steam, which is then used to create additional electricity through a steam turbine. Natural gas-fired combined-cycle units tend to have higher variable costs in the current natural gas price climate and generally cannot compete effectively with nuclear and coal-fired units, which can produce

 

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power at lower variable costs. This surge of generation investment has subsided since 2003. During 2005, for example, approximately 17,000 MW of new supply was added nationwide. This coupled with growing demand for electricity, has begun to reduce the level of excess supply, leading to current predictions of decreasing reserve margins for many regional markets through the end of the decade.

As a result, reserve margins may decrease after current capacity is absorbed by the market. Some market regulators have forecasted such a decrease in two of our major markets. For example, ERCOT, which includes all of our Texas power plants, has forecasted that its reserve margins will decrease from 13.1% in 2008 to 8.2% in 2013. Similarly, in California, which includes a significant portion of our West power plants, PG&E estimates that reserve margins in its service territory, will decrease from 18.2% in 2008 to 10.9% in 2016.

Moreover, in various regional markets, electricity market administrators have acknowledged that the markets for generating capacity do not provide sufficient revenues to enable existing merchant generators to recover all of their costs or to encourage new generating capacity to be constructed. Capacity auctions are being implemented in the Northeast and Mid-Atlantic regional markets to address this issue. In addition, California has several preceedings, both at the CPUC and the CAISO, to enhance existing capacity markets. If these market design efforts are successful, and if other markets adopt this approach, it could provide additional capacity revenues for IPPs, but any such new capacity market could take years to develop.

Regional Generation Technology and Fuel Mix

In a competitive market, the price of electricity typically is related to the operating costs of the marginal, or price-setting, generator. Assuming economic behavior by market participants, generating units generally are dispatched in order of their variable costs. In other words, units with lower costs are dispatched first and higher-cost units are dispatched as demand (sometimes referred to as “load”) grows. Accordingly, the variable costs of the last (or marginal) unit needed to satisfy demand typically drives the regional power price.

There are three general classifications of generation capacity: baseload; intermediate; and peaking. Baseload units, fueled by cheaper fuels such as hydro, geothermal, coal, or nuclear fuels, are the least expensive from a variable cost perspective and generally serve electricity demand during most hours. Intermediate units, such as combined-cycle plants fueled by natural gas, are more expensive and generally are required to serve electricity demand during on-peak or weekday daylight hours. Lastly, peaking units are the most expensive units from a variable cost perspective to dispatch and generally serve electricity demand only during on-peak hours after less expensive baseload and intermediate units are at full capacity. Much of our generating capacity is in our West and Texas markets, which are regional markets in which gas-fired units set prices during most hours. Because natural gas prices generally are higher than most other input fuels, these regions generally have higher power prices than regions in which coal-fired units set prices. Outside of the West and Texas regions, however, other generating technologies, typically coal-fired plants, tend to set prices more often, reducing average prices and “commodity margin,” which is our term used to describe the margin between realized power prices and fuel costs. These conditions, particularly in overbuilt markets, often make it difficult for gas-fired generation to compete.

In addition to earning margins from the sale of electricity, our geothermal assets benefit from regulations that promote renewable or “green” energy sources. For example, regardless of the dominant technology types for the generation of electricity in the West, the current shortage of renewable generation sources creates a premium for electricity from the geothermal facilities.

Natural Gas Prices

Natural gas prices have been particularly volatile in the current decade. As examples, during the California energy crisis in 2000, daily (or “spot”) natural gas prices rose at times above $20/MMBtu in California, and during 2005, natural gas prices rose to the $11-$13/MMBtu level in the aftermath of disruptions

 

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in Gulf of Mexico gas production caused by Hurricane Katrina, before trending downward in 2006 to the $5-$7/MMBtu range. Natural gas contracts for delivery beyond 2007 continue to trade in the $8-$10/MMBtu range.

At times, higher natural gas prices tend to increase our commodity margin; this occurs where natural gas is the price-setting fuel, such as generally during peak periods in Texas and the West, because our combined-cycle plants are more fuel-efficient than many older gas-fired technologies and peaking units. At other times higher natural gas prices have a neutral impact on us, such as where we enter into tolling agreements under which the customer provides the natural gas in return for electric power or where we enter into indexed-based agreements with a contractual Heat Rate at or near our actual Heat Rate. And at other times, high natural gas prices can decrease our margins, such as where we have entered into fixed-price PPAs and have not hedged the cost of natural gas or where another fuel, such as coal, is the price-setting fuel, which occurs frequently in the Southeast.

Because the price of natural gas is so volatile, we attempt to hedge our exposure to changes in gas prices, as discussed under “— Marketing, Hedging, Optimization and Trading Activities” below.

Environmental Regulations

Environmental regulations force generators to incur costs to comply with limits on emissions of certain pollutants. Higher operating costs for coal and oil fuel-fired generators implicitly favor low-emissions generating technologies such as our geothermal and gas-fired capacity. Further, to the extent that price-setting units experience higher variable costs due to environmental regulations, market prices tend to increase. See “— Government Regulation” for a discussion of the regulations that have or may have a significant impact on our business.

COMPETITION

We believe our ability to compete effectively will be substantially driven by the extent to which we (i) achieve and maintain a lower cost of production and transmission, primarily by managing fuel costs; (ii) effectively manage and accurately assess our risk portfolio; and (iii) provide reliable service to our customers. Wholesale power generation is a capital-intensive, commodity-driven business with numerous industry participants. We compete against other IPPs, trading companies, financial institutions, retail load aggregators, municipalities, retail electric providers, cooperatives and regulated utilities to supply electricity and electricity-related products to our customers in major markets nationwide and throughout North America. In addition, in some markets, we compete against some of our own customers. During recent years, financial institutions have aggressively entered the market along with hedge funds and other private equity funds. We believe the addition of these financial institutions and other investors to the market has generally been beneficial by increasing the number of customers for our physical power products, offering risk management products to manage commodity price risk, improving the general financial strength of market participants and ultimately increasing liquidity in the markets.

Generally, pricing can be influenced by a variety of factors, including the following:

 

   

number of market participants buying and selling;

 

   

amount of electricity normally available in the market;

 

   

fluctuations in electricity supply due to planned and unplanned outages of generators;

 

   

fluctuations in electricity demand due to weather and other factors;

 

   

cost of fuel used by generators, which could be impacted by efficiency of generation technology and fluctuations in fuel supply;

 

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relative ease or difficulty of developing and constructing new facilities;

 

   

availability and cost of transmission;

 

   

creditworthiness and risk associated with counterparties;

 

   

ability to hedge using various commercial products; and

 

   

ability to optimize the mix of alternative sources of electricity.

In less regulated markets, our natural gas and geothermal facilities compete directly with all other sources of electricity. Even though most new power generating facilities are fueled by natural gas, EIA estimates that in 2007 only 22% of the electricity generated in the U.S. was fueled by natural gas and that approximately 67% of power generated in the U.S. was still produced by coal and nuclear facilities, which generated approximately 48% and 19%, respectively. EIA estimates that the remaining 11% of electricity generated in the U.S. was fueled by hydro, fuel oil and other energy sources. However, as environmental regulations continue to evolve, the proportion of electricity generated by natural gas and other low emissions resources is expected to increase in some markets. Some states are imposing strict environmental standards on generators to limit their emissions of NOx, SO2, Hg and GHG. As a result, many of the current coal plants will likely have to install costly emission control devices or limit their operations. Meanwhile, many states are mandating that certain percentages of electricity delivered to end users in their jurisdictions be produced from renewable resources, such as geothermal, wind and solar energy. This activity could cause some coal plants to be retired, thereby allowing a greater proportion of power to be produced by facilities fueled by natural gas, geothermal or other resources that have a less adverse environmental impact.

However, some regulated utilities have proposed to construct coal and nuclear facilities, in some cases with governmental subsidies or under legislative action. Unlike IPPs, these utilities often can recover fixed costs through regulated retail rates, allowing them to invest capital without the need to rely on market prices to recover their investments. In addition, many regulated utilities are also seeking to acquire distressed assets or make substantial improvements to existing coal plants, in each case with regulatory assurance that the utility will be permitted to recover its costs, plus earn a return on its investment. IPPs, such as us, may be put at a competitive disadvantage because we rely heavily on market prices rather than governmental subsidies or regulatory assurances.

MARKETING, HEDGING, OPTIMIZATION AND TRADING ACTIVITIES

The majority of our hedging, balancing and optimization activities are related to risk exposures that arise from our ownership and operation of power plants and from third-party contracts. Most of the electricity generated by our facilities is scheduled and settled by our marketing and energy trading unit, which sells to entities such as utilities, municipalities and cooperatives, as well as to retail electric providers, commercial and industrial end users, financial institutions, power trading and marketing companies and other third parties. We enter into physical and financial purchase and sale transactions as part of our hedging, balancing and optimization activities. The hedging, balancing and optimization activities are designed to protect or enhance our commodity margin.

We are one of the largest consumers of natural gas in North America having consumed approximately 611.3 Bcf during 2007. We employ a variety of market transactions to satisfy most of our natural gas fuel requirements. We enter into natural gas storage and transport agreements to achieve delivery flexibility and to enhance our optimization capabilities. We constantly evaluate our natural gas needs, adjusting our natural gas position to minimize the delivered cost of natural gas, while adjusted for risk within the limitations prescribed in our commodity risk policy.

Our portfolio of power plants creates commodity price exposures primarily to natural gas and electricity. We utilize physical commodity contracts and commodity related financial instruments such as exchange-traded

 

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futures, over-the-counter financial swaps and forward contracts, to manage our exposures to energy commodity price risk.

We have value at risk limits that govern the overall risk of our portfolio of plants, energy trading contracts, financial hedging transactions and other contracts. Our value at risk limits, transaction approval limits and other limits are dictated by our commodity risk policy which is approved by our Board of Directors and administered by our Chief Risk Officer and his organization. The Chief Risk Officer’s organization is segregated from the commercial operations unit, and reports directly to our Audit Committee and Chief Executive Officer. Our risk management policies limit our hedging activities to protect and optimize the value of our physical assets, and also limit any exposure generated from speculative transactions. While this policy limits our potential upside due to hedging and general trading activities, it is primarily intended to provide us with a degree of protection from significant downside energy commodity price exposure to our cash flows.

We actively monitor and hedge our portfolio exposure to future market risks. As of December 31, 2007, we have hedged a portion of our expected commodity margin for 2008 and 2009. Our future hedged status is subject to change as determined by our commercial operations group, senior management, Chief Risk Officer and Board of Directors.

Seasonality and weather can have a significant impact on our results of operations and are also considered in our hedging and optimization activities. Most of our generating facilities are located in regional electric markets where the greatest demand for electricity occurs during the summer months, in our fiscal third quarter. Depending on existing contract obligations and forecasted weather and electricity demands, we may maintain either a larger or smaller open position on fuel supply and committed generation during the summer months so that we can enhance or protect our commodity margin accordingly.

SIGNIFICANT CUSTOMER

See Note 16 of the Notes to Consolidated Financial Statements for a discussion of sales in excess of 10% of our total revenues to one of our customers.

ENVIRONMENTAL PROFILE

Our fleet of mostly modern, combined-cycle natural gas-fired power generation facilities is highly efficient. These facilities consume significantly less fuel to generate electricity than older boiler/steam turbine power generation facilities and emit less air pollution into the environment per unit of electricity produced as compared to coal-fired or oil-fired power generation facilities. All of our natural gas-fired power generation facilities have air emissions controls, and most have selective catalytic reduction to further reduce emissions of nitrogen oxides, a known precursor of atmospheric ozone.

 

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The table below summarizes approximate air pollutant emission rates from our natural gas-fired power generation facilities compared to the average emission rates from U.S. coal-, oil-, and gas-fired power plants as a group.

 

     Air Pollutant Emission Rates—
Pounds of Pollutant Emitted
Per MWh of Electricity Generated

Air Pollutants

   Average U.S. Coal-,
Oil-, and Gas-Fired
Power Plant(1)
   Calpine
Natural Gas-Fired
Power Plant(2)
   Compared to
Average U.S.
Fossil-Fired Facility

Nitrogen Oxide, NOx

   2.89    0.138    95.2% Less

Acid rain, smog and fine particulate formation

        

Sulfur Dioxide, SO2

   7.28    0.0042    99.9% Less

Acid rain and fine particulate formation

        

Mercury, Hg

   0.000035       100% Less

Neurotoxin

        

Carbon Dioxide, CO2

   1,891    811    57.1% Less

Principal greenhouse gas — contributor to climate change

        

 

 

(1) The average U.S. coal-, oil-, and gas-fired power generation facility’s emission rates were obtained from the U.S. Department of Energy’s Electric Power Annual Report for 2006. Emission rates are based on 2006 emissions and net generation.

 

(2) Our natural gas-fired power plant estimated emission rates are based on our 2006 emissions and electric generation data as measured under EPA reporting requirements.

Our 725-MW fleet of geothermal power generation facilities utilizes a natural, clean and renewable energy source—steam from the Earth’s interior—to generate electricity. Since these facilities do not burn fossil fuel, they are able to produce electricity with negligible air emissions. Compared to the average U.S. coal-, oil-, and gas-fired power generation facility, our geothermal facilities emit 99.9% less NOx and SO2 and 96% less CO2.

There are 20 active geothermal power generation facilities located in the Geysers region of northern California. We own and operate 17 of them. We recognize the importance of our geothermal facilities, and we are committed to extending, and possibly expanding, this renewable geothermal resource through the addition of new steam wells and wastewater recharge projects where clean, reclaimed wastewater from local municipalities is recycled into the geothermal resource where it is converted into steam for electricity production.

We are committed to maintaining our fleet of clean, cost-effective and efficient power generation facilities and to the reduction of CO2 emissions. We also are committed to supporting policymakers on legislation to reduce emissions. In 2006, we were involved in the development and enactment of California’s landmark global warming legislation, Assembly Bill 32. Also in 2006, we were one of only two electric generating companies to file a brief of amicus curiae in support of the petitioners in the landmark case of Massachusetts, et al. v. U.S. Environmental Protection Agency, where the Supreme Court held that CO2 was a pollutant potentially subject to the CAA. We have also publicly supported the Regional Greenhouse Gas Initiative, a CO2 cap and trade program undertaken by ten Northeast states set to begin in 2009.

We have implemented a program of proprietary operating procedures to reduce gas consumption and lower air pollutant emissions per MWh of electricity generated. Thermal efficiency improvements in our fleet operations reduced CO2 emissions by approximately 40 lbs/MWh ton in 2006 compared to 2004.

Our environmental record has been widely recognized.

 

   

We are an EPA Climate Leaders Partner with a stated goal to reduce GHG intensity.

 

 

 

We became the first power producer to earn the distinction of Climate Action Leader, and we have certified our CO2 emissions inventory with the California Climate Action Registry every year since 2003.

 

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The Santa Rosa Geysers Recharge Project, developed by us and the City of Santa Rosa, transports 11 million gallons of reclaimed water per day—wastewater that was previously being discharged into the Russian River—through a 41-mile pipeline from the City of Santa Rosa to our geothermal facilities, where it is recycled into the geothermal reservoir. The water is naturally heated by the Earth, creating additional steam to fuel our geothermal facilities.

 

   

Through separate agreements with several municipalities, we use treated wastewater for cooling at several of our facilities. This eliminates the need to consume valuable surface and/or groundwater supplies—in the amount of 3 million to 4 million gallons per day for an average power generation facility.

DESCRIPTION OF POWER GENERATION FACILITIES

Plants in Operation at December 31, 2007

 

SEGMENT

           Projects            Calpine
Net Interest
with Peaking (MW)

West

   43    7,246

Texas

   12    7,487

Southeast

   12    6,254

North

   10    2,822
         

Total

   77    23,809
         

Each of our 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 our gas-fired cogeneration facilities is sold to industrial and governmental users. Our gas-fired and geothermal power generation projects produce electricity and thermal energy that is sold pursuant to short-term and long-term agreements, PPAs or into the market. Electric revenue from a PPA often consists of either energy payments or capacity payments or both. Energy payments are based on all or a portion of 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 the amount of MW that a power plant is capable of delivering at any given time. Energy payments are earned for each MWh of energy delivered. Capacity payments are typically earned whether or not any electricity is scheduled by the customer and delivered; however, capacity payments typically have an availability requirement.

Geothermal energy is considered a renewable energy because the steam harnessed to power our turbines is produced inside the Earth and does not require burning fuel to generate electricity. The extracted steam is also partially replenished by the injection of condensate associated with the steam extracted to generate electricity. We also inject clean, reclaimed waste-water from the City of Santa Rosa Recharge Project and from Lake County through injection wells, which serves to slow the natural depletion of our geothermal reservoirs. We expect the injection projects to extend the useful life of this resource and help to maintain the output of our geothermal resources and power plants.

We currently lease the geothermal steam fields from which we extract steam for our geothermal power generation facilities. We have leasehold mineral interests in 107 leases comprising approximately 27,700 acres of federal, state and private geothermal resource lands in the Geysers region in northern California. In general, under these mineral 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

 

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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 mineral leases, on which commercial production has not yet been established, contain drilling or other exploratory work requirements. In certain cases, if these requirements are 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. In addition, in the Glass Mountain and Medicine Lake areas in northern California, we hold leasehold mineral interests in 41 leases comprising approximately 46,400 acres of federal geothermal resource lands. See Note 15 of the Notes to Consolidated Financial Statements for a description of litigation relating to our Glass Mountain area 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, or have the ability, to renew any expiring leases.

Upon completion of our projects under construction, subject to any dispositions that may occur, we will provide O&M services for all but two of the 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 O&M 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.

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 and capacity payments) 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.

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.

 

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Set forth below is certain information regarding our operating power plants and plants under construction/development as of December 31, 2007.

Power Plants in Operation and Under Construction/Development

 

SEGMENT /Project(1)

 

NERC

    Region    

 

US State or
Canadian

    Province    

 

Technology

  Baseload /
Intermediate
Capacity
(MW)
  With
Peaking
Capacity

    (MW)    
  Calpine
Interest
Percentage
  Calpine Net
Interest
Baseload
(MW)
  Calpine Net
Interest
With
Peaking
(MW)
  2007
Total
MWh(2)
Generation

WEST

                 

Geothermal

                 

McCabe #5 & #6

  WECC   CA   Geothermal   78   78   100%   78   78   667,069

Ridge Line #7 & #8

  WECC   CA   Geothermal   69   69   100%   69   69   615,360

Calistoga

  WECC   CA   Geothermal   66   66   100%   66   66   579,213

Eagle Rock

  WECC   CA   Geothermal   66   66   100%   66   66   552,153

Quicksilver

  WECC   CA   Geothermal   53   53   100%   53   53   457,937

Cobb Creek

  WECC   CA   Geothermal   52   52   100%   52   52   427,675

Lake View

  WECC   CA   Geothermal   52   52   100%   52   52   451,592

Sulphur Springs

  WECC   CA   Geothermal   51   51   100%   51   51   421,366

Socrates

  WECC   CA   Geothermal   50   50   100%   50   50   419,748

Big Geysers

  WECC   CA   Geothermal   48   48   100%   48   48   472,757

Grant

  WECC   CA   Geothermal   43   43   100%   43   43   326,368

Sonoma

  WECC   CA   Geothermal   42   42   100%   42   42   330,878

West Ford Flat

  WECC   CA   Geothermal   24   24   100%   24   24   205,107

Aidlin

  WECC   CA   Geothermal   17   17   100%   17   17   146,531

Bear Canyon

  WECC   CA   Geothermal   14   14   100%   14   14   114,050

Gas-Fired

                 

Delta Energy Center

  WECC   CA   Natural Gas   818   840   100%   818   840   5,270,603

Pastoria Energy Center

  WECC   CA   Natural Gas   750   750   100%   750   750   4,831,817

Rocky Mountain Energy Center

  WECC   CO   Natural Gas   479   621   100%   479   621   3,560,749

Hermiston Power Project

  WECC   OR   Natural Gas   547   616   100%   547   616   3,080,066

Metcalf Energy Center

  WECC   CA   Natural Gas   564   605   100%   564   605   2,955,406

Sutter Energy Center

  WECC   CA   Natural Gas   542   578   100%   542   578   2,668,953

Los Medanos Energy Center

  WECC   CA   Natural Gas   512   540   100%   512   540   3,491,354

South Point Energy Center

  WECC   AZ   Natural Gas   520   520   100%   520   520   2,133,894

Blue Spruce Energy Center

  WECC   CO   Natural Gas     285   100%     285   487,394

Los Esteros Critical Energy Facility

  WECC   CA   Natural Gas     188   100%     188   65,115

Gilroy Energy Center

  WECC   CA   Natural Gas     135   100%     135   89,879

Gilroy Cogeneration Plant

  WECC   CA   Natural Gas   117   128   100%   117   128   281,111

King City Cogeneration Plant

  WECC   CA   Natural Gas   120   120   100%   120   120   394,048

Pittsburg Power Plant

  WECC   CA   Natural Gas   64   64   100%   64   64   147,011

Greenleaf 1 Power Plant

  WECC   CA   Natural Gas   50   50   100%   50   50   286,712

Greenleaf 2 Power Plant

  WECC   CA   Natural Gas   49   49   100%   49   49   249,103

Wolfskill Energy Center

  WECC   CA   Natural Gas     48   100%     48   20,505

Yuba City Energy Center

  WECC   CA   Natural Gas     47   100%     47   25,033

Feather River Energy Center

  WECC   CA   Natural Gas     47   100%     47   25,562

Creed Energy Center

  WECC   CA   Natural Gas     47   100%     47   12,874

Lambie Energy Center

  WECC   CA   Natural Gas     47   100%     47   14,602

Goose Haven Energy Center

  WECC   CA   Natural Gas     47   100%     47   14,645

Riverview Energy Center

  WECC   CA   Natural Gas     47   100%     47   26,403

King City Peaking Energy Center

  WECC   CA   Natural Gas     45   100%     45   22,408

Watsonville (Monterey) Cogeneration Plant

  WECC   CA   Natural Gas   29   29   100%   29   29   160,045

Agnews Power Plant

  WECC   CA   Natural Gas   28   28   100%   28   28   224,515
                           

Subtotal

        5,914   7,246     5,914   7,246   36,727,611

TEXAS

                 

Freestone Energy Center

  ERCOT   TX   Natural Gas   1,036   1,036   100%   1,036   1,036   4,052,496

Deer Park Energy Center

  ERCOT   TX   Natural Gas   792   1,019   100%   792   1,019   5,867,983

Baytown Energy Center

  ERCOT   TX   Natural Gas   742   830   100%   742   830   4,746,915

Pasadena Power Plant

  ERCOT   TX   Natural Gas   731   776   100%   731   776   3,756,089

Magic Valley Generating Station

  ERCOT   TX   Natural Gas   662   692   100%   662   692   2,948,458

Brazos Valley Power Plant

  ERCOT   TX   Natural Gas   508   594   100%   508   594   2,736,351

Channel Energy Center

  ERCOT   TX   Natural Gas   443   593   100%   443   593   2,832,679

Corpus Christi Energy Center

  ERCOT   TX   Natural Gas   400   505   100%   400   505   2,512,009

Texas City Power Plant

  ERCOT   TX   Natural Gas   400   453   100%   400   453   1,555,191

Clear Lake Power Plant

  ERCOT   TX   Natural Gas   344   400   100%   344   377   613,038

Hidalgo Energy Center

  ERCOT   TX   Natural Gas   475   479   79%   373   376   1,533,029

Freeport Energy Center(3)

  ERCOT   TX   Natural Gas   210   236   100%   210   236   n/a
                           

Subtotal

        6,743   7,613     6,641   7,487   33,154,238

 

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SEGMENT /Project(1)

 

NERC

    Region    

 

US State or
Canadian

    Province    

 

Technology

  Baseload /
Intermediate
Capacity
(MW)
  With
Peaking
Capacity

    (MW)    
  Calpine
Interest
Percentage
  Calpine Net
Interest
Baseload
(MW)
  Calpine Net
Interest
With
Peaking
(MW)
  2007
Total
MWh(2)
Generation

SOUTHEAST

                 

Broad River Energy Center

  SERC   SC   Natural Gas     847   100%     847   740,136

Morgan Energy Center

  SERC   AL   Natural Gas   720   807   100%   720   807   2,894,046

Decatur Energy Center

  SERC   AL   Natural Gas   734   792   100%   734   792   2,393,282

Columbia Energy Center

  SERC   SC   Natural Gas   455   606   100%   455   606   387,476

Carville Energy Center

  SERC   LA   Natural Gas   449   501   100%   449   501   2,160,450

Santa Rosa Energy Center

  SERC   FL   Natural Gas   250   250   100%   250   250  

Hog Bayou Energy Center

  SERC   AL   Natural Gas   235   237   100%   235   237   96,737

Pine Bluff Energy Center

  SERC   AR   Natural Gas   184   215   100%   184   215   840,953

Oneta Energy Center

  SPP   OK   Natural Gas   980   1,134   100%   980   1,134   1,890,438

Osprey Energy Center

  FRCC   FL   Natural Gas   537   599   100%   537   599   2,224,348

Auburndale Power Plant

  FRCC   FL   Natural Gas   150   150   100%   150   150   664,915

Auburndale Peaking Energy Center

  FRCC   FL   Natural Gas     116   100%     116   49,540
                           

Subtotal

        4,694   6,254     4,694   6,254   14,342,321

NORTH

                 

Riverside Energy Center

  MRO   WI   Natural Gas   518   603   100%   518   603   1,344,309

RockGen Energy Center

  MRO   WI   Natural Gas     460   100%     460   92,701

Mankato Power Plant

  MRO   MN   Natural Gas   280   324   100%   280   324   710,364

Westbrook Energy Center

  NPCC / ISO NE   ME   Natural Gas   537   537   100%   537   537   2,388,927

Kennedy International Airport Power Plant

  NPCC / NYISO   NY   Natural Gas   110   121   100%   110   121   545,859

Bethpage Energy Center 3

  NPCC / NYISO   NY   Natural Gas   80   80   100%   80   80   344,483

Bethpage Power Plant

  NPCC / NYISO   NY   Natural Gas   55   56   100%   55   56   49,545

Bethpage Peaker

  NPCC / NYISO   NY   Natural Gas     48   100%     48   38,767

Stony Brook Power Plant

  NPCC / NYISO   NY   Natural Gas   45   47   100%   45   47   253,373

Zion Energy Center

  RFC   IL   Natural Gas     546   100%     546   256,943
                           

Subtotal

        1,625   2,822     1,625   2,822   6,025,271
                           

Total operating power plants (77)

        18,976   23,935     18,874   23,809   90,249,441
                           

Projects under construction

                 

Otay Mesa Energy Center(4)

  WECC   CA   Natural Gas   510   596   100%   510   596   n/a

Greenfield Energy Centre

  Ontario   ON   Natural Gas   775   1,005   50%   388   503   n/a
Projects under active development                  

Russell City Energy Center

  WECC   CA   Natural Gas   557   600   65%   362   390   n/a
                           

Total operating and under construction /development power plants

        20,818   26,136     20,134   25,298   90,249,441
                           

 

 

(1) The Canadian plant listed below was deconsolidated as of December 31, 2005 (see Notes 2 and 3 of the Notes to Consolidated Financial Statements), and is not included in the table above:

 

Whitby Cogeneration

  Ontario   ON   Natural Gas   50   50   50%   25   25   375,833

 

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

 

(3) Freeport Energy Center is owned by us but contracted and operated by The Dow Chemical Company (DOW).

 

(4) Otay Mesa Energy Center was deconsolidated in the second quarter of 2007 (see Note 2 of the Notes to Consolidated Financial Statements).

 

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Set forth below is certain information regarding our power plants that are not in operation at December 31, 2007. These power plants remain idle until their return to operation is economically preferable.

Power Plants Not in Operation

 

Project

  NERC
    Region    
      US State         Technology     Baseload /
Intermediate
Capacity
(MW)
  With
Peaking
Capacity
(MW)
  Calpine
Interest
Percentage
  Calpine Net
Interest
Baseload
(MW)
  Calpine Net
Interest

With
Peaking
(MW)

Newark Power Plant

  RFC   NJ   Natural Gas   50   56   100%   50   56

Philadelphia Water Project

  RFC   PA   Natural Gas     23   83%     19

Pryor Power Plant

  SPP   OK   Natural Gas   38   90   100%   38   90

Fumarole #9 & #10(1)

  WECC   CA   Geothermal       100%    
                       

Total

        88   169     88   165
                       

 

 

(1) Steam is currently diverted to our other geothermal plants.

Projects Under Construction at December 31, 2007

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 the projects discussed below that are already in construction, while construction on certain other projects may remain in suspension or the projects may be sold. We generally expect to start development or construction on new projects only in cases where power contracts and financing are available and attractive returns are expected.

Otay Mesa Energy Center. In July 2001, we acquired OMEC and the associated development rights including a CEC license permitting construction of the plant. Site preparation activities for this 596-MW facility, located in southern San Diego County, California began in 2001. In February 2004, we signed a 10-year PPA with SDG&E for delivery of up to 615 MW of capacity and energy beginning January 1, 2008, and entered into a PPA Reinstatement Agreement and an Amended and Restated PPA in October 2006. Power deliveries under the contract are currently scheduled to begin on May 1, 2009. At the end of the 10-year PPA term, OMEC has an option to require SDG&E to purchase the plant and SDG&E has an option to require OMEC to sell the plant to SDG&E.

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 power plant located in Ontario, Canada. The facility will deliver electricity to the OPA under a 20-year PPA. We contributed three combustion turbines, three combustion generators, one steam turbine generator, and cash to the project, giving us a 50% interest in the facility. Mitsui owns the remaining 50% interest. Construction began in November 2005, and commercial operation is expected to occur in 2008.

Project Under Active Development at December 31, 2007

Russell City Energy Center. A proposed 600-MW, natural gas-fired power plant to be located in Hayward, California, the Russell City Energy Center is currently contracted to deliver its full output to PG&E under a PPA which was executed in December 2006 and approved by the CPUC in January 2007. In September 2006, we sold a 35% equity interest in the project to ASC for approximately $44 million and ASC’s obligation to post a $37 million letter of credit. We own the remaining 65% interest. Under the LLC agreement with ASC, ASC’s equity is to be applied toward completion of development and construction of the power plant, and ASC is also to provide related credit support for the project. We currently are in discussions with PG&E to amend the terms and conditions under which this project will be constructed and operated. Construction is anticipated to begin once all permits and other required approvals are final and non-appealable, and project financing has closed.

 

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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 power generating 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 transmission grid and natural gas pipelines.

There have been a number of federal and state legislative and regulatory actions that have recently changed, and will continue to change, how our business is regulated. Such changes could adversely affect our existing business.

Federal Regulation of Electricity

Electric utilities have been highly regulated by the federal government since the 1930s, principally under the FPA and PUHCA 1935. These statutes have been amended and supplemented by subsequent legislation, including PURPA, EPAct 1992 and EPAct 2005. These particular statutes and regulations are discussed in more detail below.

The FPA grants the federal government broad authority over electric utilities and IPPs, and vests its authority in FERC. Unless otherwise exempt, any person that owns or operates facilities used for the wholesale sale or transmission of electricity in interstate commerce is a public utility subject to FERC’s jurisdiction. FERC governs, among other things, the disposition of certain utility property, the issuance of securities by public utilities, the rates, terms and conditions for the transmission or wholesale sale of electric energy in interstate commerce, interlocking directorates and the uniform system of accounts and reporting requirements for public utilities.

The majority of our power generating facilities are subject to FERC’s jurisdiction, but some qualify for available exemptions. FERC’s jurisdiction over EWGs under the FPA applies to the majority of our generating projects because they are EWGs or are owned by EWGs, except our EWGs located in ERCOT. Facilities located in ERCOT are exempt from many FERC regulations under the FPA. Many of our power generating facilities that are not EWGs are operated as QFs under PURPA. 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 reporting and accounting 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.

FERC has the right to review books and records of “holding companies,” as defined in PUHCA 2005, that are determined by FERC to be relevant to the companies’ respective FERC-jurisdictional rates. We are considered a holding company, as defined in PUHCA 2005, by virtue of our control of the outstanding voting securities of our subsidiaries that own or operate facilities used for the generation of electric energy for sale or that are themselves holding companies. However, we are exempt from FERC’s inspection rights pursuant to one of the limited exemptions under PUHCA 2005 because we are a holding company due solely to our owning one or more QFs, EWGs and FUCOs. If any single Calpine entity were not a QF, EWG or FUCO, then we and our holding company subsidiaries would be subject to the books and records access requirement.

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. The impact of such policies and proposals on our business is uncertain and cannot be predicted at this time.

 

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FERC Regulation of Market-Based Rates

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 some of those power plants that are QFs under PURPA, or those that are located in ERCOT), as well as our 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 to continue to satisfy FERC’s current or future criteria, or if FERC eliminates or restricts the ability of wholesale sellers of power to make sales at market-based rates.

FERC’s regulations specifically prohibit the manipulation of the electric energy markets by 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 engage in fraudulent or deceptive practices.

To ward against market manipulation, FERC requires us and other sellers making sales pursuant to their market-based rate authority to file certain reports, including quarterly reports of contract and transaction data, notices of any change in status and triennial updated market power analyses. If a seller does not timely file these reports or notices, FERC can revoke the seller’s market-based rate authority. FERC’s regulations also contain four market behavior rules that apply to sellers with market-based rate authority. These rules address such matters as compliance with organized RTO or ISO market rules, communication of accurate information, price reporting to publishers of electricity or natural gas price indices and record retention. Failure to comply with these regulations can lead to sanctions by FERC, including penalties and suspension or revocation of market-based rate authority.

FERC Regulation of Transfers of Jurisdictional Facilities

Dispositions of our jurisdictional facilities or certain types of financing arrangements may require prior FERC approval, which could result in revised terms or impose additional costs, or cause a transaction to be delayed or terminated. 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 or securities with a value in excess of $10 million issued by another public utility. FERC’s prior approval is also required for transactions involving certain transfers of existing generation facilities and certain holding companies’ acquisitions of facilities with a value in excess of $10 million. FERC’s regulations implementing Section 203 provide blanket authorizations for certain types of transactions, including acquisitions by holding companies that are holding companies solely due to their ownership, directly or indirectly, of one or more QFs, EWGs and FUCOs, of the securities of additional QFs, EWGs and FUCOs without FERC prior approval.

FERC Regulation of Qualifying Facilities

Cogeneration and certain small power production facilities are eligible to be QFs under PURPA, provided that they meet certain electricity and thermal energy production requirements and efficiency standards. QF status provides an exemption from PUHCA 2005 and grants certain other benefits to the QF, including in some cases the right to sell power to utilities at the utilities’ avoided cost. Certain types of sales by QFs also are exempt from FERC regulation of wholesale sales of the QFs’ electrical output. QFs are also exempt from most state laws and 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.

 

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An electric utility may be relieved of the mandatory purchase obligation to purchase power from QFs at the utility’s avoided cost if FERC determines that such QFs have access to a competitive wholesale electricity market.

Enforcement Authority

FERC has civil penalty authority over violations of any provision of Part II of the FPA, as well as any rule or order issued thereunder. FERC is authorized to assess a maximum civil penalty of $1 million per violation for each day that the violation continues. The FPA also provides for the assessment of criminal fines and imprisonment for violations under Part II of the FPA. This penalty authority was enhanced in EPAct 2005. In 2007, the first year FERC exercised its enhanced civil penalty authority, FERC’s enforcement activities increased, with the imposition of civil penalties ranging from $300,000 to $10 million, in certain cases for unintentional and self-reported violations. With this expanded enforcement authority, violations of the FPA and FERC’s regulations could potentially have more serious consequences than in the past.

NERC Compliance Requirements

Pursuant to EPAct 2005, NERC has been certified by FERC as the ERO to develop mandatory and enforceable electric system reliability standards applicable throughout the U.S., which are subject to FERC review and approval. Once approved, the reliability standards may be enforced by FERC independently, or, alternatively, by the ERO and regional reliability organizations with frontline responsibility for auditing, investigating and otherwise ensuring compliance with reliability standards, subject to FERC oversight. Monetary penalties of up to $1 million per day per violation may be assessed for violations of the reliability standards. Certain electric reliability standards which apply to us as a generator owner, generator operator or marketer of electric power are effective and mandatory. It is expected that additional NERC reliability standards will be approved by FERC in the coming years requiring us to take additional steps to remain fully compliant.

Regional Regulation

The following summaries of the regional rules and regulations affecting our business focus on the West and Texas because these are the regions in which we have the most significant portfolios of assets. While we provide a brief overview of the primary regional rules and regulations affecting our facilities located in other regions of the country, we do not provide an in-depth discussion of these rules and regulations because our asset portfolio in those regions is not significant. All facility and MW data is reported as of December 31, 2007.

West

Our subsidiaries own 26 gas-fired generating facilities (excluding two facilities under active construction/development) with the capacity to generate a total of 6,521 net MW in the WECC region, which extends from the Rocky Mountains westward. In addition, we own and operate 17 geothermal power plants located in northern California, capable of producing a total of 725 net MW. The majority of these facilities are located in California, in the CAISO balancing area; however, we also own generating facilities in Arizona, Colorado and Oregon.

CAISO is responsible for ensuring the safe and reliable operation of the transmission grid within California and providing open, nondiscriminatory transmission services. Pursuant to a FERC-approved tariff, CAISO has certain abilities to impose penalties on market participants for violations of its rules. CAISO maintains various markets for wholesale sales of electricity, differentiated by time and type of electrical service, into which our subsidiaries may sell electricity from time to time. These markets are subject to various controls, such as price caps and mitigation of bids when reference prices are exceeded. The controls and the markets themselves are subject to regulatory change at any time.

CAISO is in the process of developing the details for implementing MRTU, which was previously approved by FERC. The MRTU is a comprehensive redesign of all CAISO operations currently slated to go into

 

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effect sometime in 2008. Under MRTU, the CAISO will run a new integrated day-ahead market for energy and ancillary services as well as a real-time market and an hour-ahead scheduling protocol. The energy market will change from a zonal to a nodal market. The primary features of a nodal market include a centralized, day-ahead market for energy, a nodal transmission congestion management model that results in locational marginal pricing at each generation location, financial congestion hedging instruments and a centralized day-ahead commitment process. Given the comprehensiveness of the market design, with features that may prove to be both positive and negative for energy sellers, we cannot predict at this time what impact MRTU will have on our business.

Our plants located outside of California either sell power into the markets administered by CAISO or sell power through bilateral transactions outside CAISO. Those transactions occurring outside CAISO are subject to FERC regulation and oversight, but they are not subject to CAISO rules and regulations.

Texas

Our subsidiaries own 12 natural gas-fired generating facilities in Texas with the capacity to generate a total of 7,487 net MW, all of which are physically located in the ERCOT market. ERCOT is an ISO that manages approximately 85% of Texas’ load and an electric grid covering about 75% of the state, overseeing transactions associated with Texas’ competitive wholesale and retail electric market. FERC does not regulate wholesale sales of power in ERCOT. ERCOT is largely a bilateral wholesale power market, which allows buyers and sellers to competitively negotiate contracts for energy, capacity and ancillary services. ERCOT meets its system needs by using ancillary service capacity and running a balancing energy service. ERCOT manages transmission congestion with zonal and intra-zonal type arrangements. ERCOT ensures resource adequacy through an energy-only model rather than capacity-based resource adequacy model more common among RTOs or ISOs in the Eastern Interconnect. In ERCOT there is a market price cap for energy purchased by ERCOT. Under certain market conditions, the offer cap could be lower. Our subsidiaries are subject to the offer cap rules, but only for sales of energy services to ERCOT.

The PUCT exercises regulatory jurisdiction over the rates and services of any electric utility conducting business within Texas. Our subsidiaries that own facilities in Texas have power generation company status at the PUCT, and are either EWGs or QFs and are exempt from PUCT rate regulation.

North

New York and the Northeast regions are part of the NPCC NERC region, in which we have a total of six natural gas-fired generating facilities with the capacity to generate a total of 889 MW. Five of such generating facilities are located in New York. NYISO manages the transmission system in New York and operates the state’s wholesale electricity markets. NYISO manages both day-ahead and real time energy markets using a locationally based marginal pricing mechanism that pays each generator the nodal marginally accepted bid price for the energy it produces.

The remaining generating facility in the NPCC is located in Maine. ISO NE is the RTO for Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont. ISO NE has broad authority over the day-to-day operation of the transmission system and operates a day-ahead and real time wholesale energy market, a forward capacity market, and ancillary services markets. ISO NE also provides for regional transmission planning.

We have one power plant, with the capacity to generate 546 MW, located in the PJM Interconnection region, which is located in the RFC NERC region. However, it is partially committed to load in MISO. PJM operates wholesale electricity markets, a locationally-based capacity market, a forward capacity market and ancillary service markets. They also perform transmission planning for the region.

We have three natural gas-fired plants with the capacity to generate a total of 1,387 MW operating within the MISO market. MISO manages competitive locationally-based wholesale day-ahead and real-time energy

 

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markets. MISO has proposed ancillary service markets and is awaiting FERC’s ruling on its proposal. MISO currently manages an energy-only-based resource adequacy model, but has proposed a capacity-based resource adequacy model which is also pending before FERC.

PJM and the MISO have been directed by FERC to establish a common and seamless market, an effort that is largely dependent upon the ability of stakeholders to forge agreements on design issues and related transition costs. It is unclear at this time if either the respective entities or FERC will approve such costs to achieve a common and seamless market.

Southeast

We have one operating natural gas-fired plant with the capacity to generate 1,134 MW located in SPP. SPP is an RTO approved by FERC that provides independent administration of the electric power grid. SPP manages an energy-only locationally-based real-time wholesale energy market. This market provides both nominal load-following and transmission constraint relief. SPP does not have a day-ahead market, ancillary service markets or a capacity market.

We have 11 natural gas-fired plants with the capacity to generate a total of 5,120 MW operating within the SERC and the FRCC NERC regions. Opportunities to negotiate bilateral, individual contracts and long-term transactions with investor owned utilities, municipalities and cooperatives exist within these footprints. In addition to entering into bilateral transactions, there is a limited opportunity to sell into the short-term market. In the Entergy sub-region, SPP has been designated as the ICT. In this capacity, the ICT provides oversight of the Entergy transmission system. Entergy has also recently filed with FERC a Weekly Procurement Process, which is intended to be a formal process by which Entergy will procure short-term competitive wholesale power.

Federal Regulation of Transportation and Sale of Natural Gas

Because the majority of our electric generating capacity is derived from natural gas-burning facilities, we are broadly impacted by federal regulation of natural gas transportation and sales. Furthermore, our two natural gas transportation pipelines in Texas are subject to FERC regulation. Under the NGA, the NGPA 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 abandonment of facilities; and the rates for services. FERC is also authorized under the NGA to regulate the sale of natural gas at wholesale. FERC also has the authority to regulate the quality of LNG deliveries into the pipeline system. Unless appropriate gas specifications are implemented, LNG supplies could impact in the future our plant operations and the ability to meet emission limits.

FERC has civil penalty authority for violations of the NGA and NGPA, as well as any rule or order issued thereunder. Similar to its penalty authority under the FPA described above, FERC is authorized to assess a maximum civil penalty of $1 million per violation for each day that the violation continues. The NGA and NGPA also provide for the assessment of criminal fines and imprisonment time for violations.

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. Because all of our affiliates are either QFs or EWGs, none of our affiliates are currently subject to direct rate regulation by a state PUC. However, states may 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 CPUC 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. As the owner and operator of generating facilities in California, our subsidiaries are subject to the generation facilities maintenance and operation standards and the general duty standards that are enforced by the CPUC.

 

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In addition, our Texas pipelines are subject to regulation as gas utilities by the Railroad Commission of Texas for rates and services.

Environmental Regulations

Our facilities and equipment necessary to support them 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. 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 that apply to us. In most cases, analogous state laws also exist that may impose similar and, in some cases, more stringent requirements on us than those discussed below. Our general policy with respect to these laws attempts to take advantage of our relatively clean portfolio of power plants as compared to our competitors.

Federal Climate Change Legislation

Our emissions of CO2 amounted to over 35 million tons in 2006. Although there are no federal laws regulating GHG emissions, there has been increased attention to climate change in the U.S. Several bills to regulate GHG from the electricity sector have been introduced in the U.S. House of Representatives and the Senate and more are expected in 2008, making climate change initiatives an emerging priority on the environmental legislative and regulatory front. Therefore, regulation of GHGs could have a material impact on the conduct of our business. We are actively participating in the debates surrounding federal regulation of GHG emissions from the electric generating sector in an attempt to minimize future impacts to our business.

Supreme Court Case Regarding Regulation of GHG

Twelve states and various environmental groups filed suit against the EPA in Commonwealth of Massachusetts, et al. v. U.S. Environmental Protection Agency seeking confirmation that the EPA has an existing obligation to regulate GHGs, under the CAA. The EPA refused to regulate GHG emissions from motor vehicles on the basis that the CAA did not require regulation of GHGs, including CO2, as pollutants. In July 2005, the U.S. Court of Appeals for the District of Columbia Circuit supported the EPA’s position.

After a series of appeals, the U.S. Supreme Court agreed in March 2006 to consider the case. We submitted a brief of amicus curiae in support of the plaintiffs’ case, and oral arguments were made before the U.S. Supreme Court in November 2006. On April 2, 2007, the U.S. Supreme Court ruled that the EPA has the authority to regulate GHG issues under language included in the CAA.

Climate Change — Regional Activities

Although standards have not been developed at the national level, several states and regional organizations are developing, or already have developed, state-specific or regional legislative initiatives to reduce GHG emissions through mandatory programs. The two most advanced programs relate to climate change regulation in California and actions taken by a coalition of northeast states. The evolution of these programs could have a material impact on our business. However, we believe we will face a lower compliance burden than some competitors due to the relatively low GHG emission rates of our fleet.

In California, Assembly Bill 32 and Senate Bill 1368 were signed into law in September 2006. Assembly Bill 32 creates a statewide cap on GHG emissions and requires that the state return to 1990 emission levels by 2020; implementation is slated to begin in 2012. Effective in 2007, Senate Bill 1368 sets a CO 2 emissions performance standard of 1,110 lb/MWh for long-term procurement of electricity by load-serving entities in the state.

 

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Beginning in 2009, ten Northeast and Mid-Atlantic states will launch the Regional Greenhouse Gas Initiative which will affect our facilities in Maine, New York and New Jersey. RGGI will cap CO2 emissions at current levels, through 2015, and the cap will decrease annually by 2.5% until 2019 for a 10% reduction in current levels. Each participating state will receive a share of the total RGGI cap, and decisions on how the allowances will be distributed will be made by each state. Maine, New York and New Jersey have passed legislation and/or proposed implementing regulations requiring public auction of RGGI allowances. If these regulations become final as expected, we will need to purchase allowances to offset CO2 emissions from our facilities in the RGGI region.

Clean Air Act

The CAA provides for the regulation of air quality and air emissions, largely through state implementation of federal requirements. In 1990, Congress amended the CAA to specifically provide for acid deposition control through the regulation of NOx and SO2 emissions from electric generating units. 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 CAA.

Acid Rain Program

As a result of the 1990 CAA amendments, the EPA established a cap and trade program for SO2 emissions from electric generating units throughout the U.S. Under this program, a permanent ceiling (or cap) was set at 8.95 million allowances for total annual SO2 allowance allocations to power generators. Each allowance permits a unit to emit one ton of SO2 during or after a specified year, and allowances may be bought, sold or banked. All but a small percentage of allowances were allocated to electric generating units placed into service before 1990. None of our facilities received an allocation, so we must purchase allowances to cover all SO2 emissions from our affected facilities and satisfy our compliance obligations. Since our entire fleet emits about 200 tons of SO2 per year, we believe that our compliance expense for this program will be relatively insignificant compared to many of our competitors.

NOx State Implementation Plan Call

In response to concerns about interstate contributions to ozone concentrations above the NAAQS, the EPA promulgated regulations establishing a cap and trade program for NOx emissions from electric generating and industrial steam generating units in most of the eastern U.S. in May 2004. Under these regulations, the EPA set a NOx emissions cap for each state and each affected unit receives NOx emissions allowances through allocation mechanisms that vary by state. Emission compliance obligations apply during the ozone season, which extends from May through September. If an affected unit exceeds its allocated allowances, it must purchase additional allowances to resolve the shortfall.

We own and operate numerous facilities that are affected by this program. To date, NOx allowance allocations have been sufficient to cover all emissions and we have sold some surplus allowances for a small profit. We believe that the relatively low NOx emission rate of our fleet in general keeps our compliance costs for this program lower than those of many of our competitors. This program will be replaced by CAIR in 2009.

Clean Air Interstate Rule

CAIR is intended to reduce SO2 and NOx emissions in 29 eastern states and the District of Columbia and address transport of pollutants that contribute to nonattainment of NAAQS for fine particulate matter and ozone. The rule includes both seasonal and annual NOx control programs as well as an annual SO2 control program. A significant portion of our generating fleet will be subject to these programs.

Phase I of the CAIR NOx control program becomes effective in 2009 and the SO2 control program becomes effective in 2010, with the final compliance phase for both beginning in 2015. With respect to SO2

 

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emissions, CAIR relies largely upon the cap and trade mechanism established under the EPA acid rain program discussed above and compliance with CAIR will be demonstrated through the use of SO2 allowances issued under the EPA’s acid rain program. CAIR will require the use of two emission allowances for each ton of SO2 emitted beginning in 2010, and 2.87 emission allowances for each ton of SO2 emitted beginning in 2015. As our fleet’s SO2 emissions are low, we expect our costs of compliance with CAIR to be lower than those of many of our competitors.

CAIR provides for a new NOx cap and trade mechanism that issues allowances to the majority of affected sources. NOx emissions will be covered with a one-for-one ratio of allowances to tons; however, the total emissions cap will be reduced in 2015, which generally will have the effect of reducing allowance allocations to affected sources.

In August 2005, the EPA published a proposed rule to implement the provisions of CAIR. Each CAIR-affected state has the option of adopting the EPA rule or developing their own state-level rule, which allows individual consideration of NOx allocation mechanisms, among other considerations. In general, the EPA allowance allocation mechanism is less favorable to us than the various proposed state-level rulemakings, and we have actively participated in various state-level rulemakings to achieve more favorable allocation treatment for our facilities. We do not believe that CAIR will require significant compliance expenditures as our overall fleet has surplus CAIR allowances.

Houston/Galveston Nonattainment

Regulations adopted by the TCEQ to attain the one-hour NAAQS for ozone included the establishment of a cap and trade program for NOx emitted by power generating facilities in the Houston/Galveston ozone nonattainment area. We own and operate seven facilities that participate in this program, all of which have, or will receive, NOx allowance allocations based on historical operating profiles.

At this time, our Houston-area generating facilities have sufficient NOx allowances to meet forecasted obligations under the program. However, TCEQ may modify future allocations of NOx to facilities participating in the trading program in support of efforts to comply with the new 8-hour ozone NAAQS. Should allowance shortfalls occur, we would be required to purchase NOx allowances or install emissions control equipment on certain facilities.

Clean Water Act

The federal Clean Water Act establishes rules regulating the discharge of pollutants into waters of the U.S. We are required to obtain wastewater and storm water discharge permits for wastewater and runoff, respectively, from certain of our facilities. 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 established the underground injection control program that regulates the disposal of wastes by means of deep well injection, which is used for geothermal production activities. 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

RCRA regulates the management of solid and hazardous waste. With respect to our solid waste disposal practices at the power generation facilities and steam fields located in the Geysers region of northern California,

 

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we are also subject to certain solid waste requirements under applicable California laws. We believe that our operations are in material compliance with RCRA 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 U.S. or exporting natural gas from the U.S. first must obtain an import or export authorization from the U.S. Department of Energy.

EMPLOYEES

As of December 31, 2007, we employed 2,080 full-time employees, of whom 44 were represented by collective bargaining agreements. We have never experienced a work stoppage or strike. As part of our restructuring program, in 2006 and 2007 we implemented staff reductions, and eliminated approximately 1,239 positions.

Item 1A. Risk Factors

Risks Relating to Emergence from Chapter 11

The market pricing of our reorganized Calpine Corporation common stock may be volatile.

Our common stock began trading on the NYSE on a “when issued” basis on January 16, 2008, and began “regular way” trading on the NYSE on February 7, 2008. The liquidity of any market for our common stock will depend, among other things, upon the number of holders of our common stock and on our and our subsidiaries’ financial performance. The market price for our common stock has been volatile in the past, and the price of our common stock could fluctuate substantially in the future. Factors that could affect the price of our common stock in the future include general conditions in our industry, in the power markets in which we participate and in the world, including environmental and economic developments, over which we have no control, as well as developments specific to our Company, including fluctuations in our results of operations, our ability to comply with the covenants under our Exit Facilities and other debt instruments, our ability to execute our business plan,

 

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and other matters discussed in these risk factors. Recipients of reorganized Calpine Corporation common stock under the Plan of Reorganization may seek to sell all or a large portion of their shares in a short period of time which may adversely affect the market price of our common stock. Moreover, in addition to the approximately 421 million shares of reorganized Calpine Corporation common stock that have been distributed to creditors pursuant to the Plan of Reorganization, approximately 64 million shares have been reserved for distribution upon the resolution of disputed claims. Also, approximately 48.5 million shares have been reserved for issuance upon exercise of the warrants distributed to the holders of our previously outstanding common stock; the distribution of these additional shares could have a dilutive effect on our current holders and may adversely affect the market price of our common stock. Accordingly, trading in our securities is highly speculative and poses substantial risks.

Transfers of our equity, or issuances of equity in connection with our reorganization, may impair our ability to utilize our federal income tax net operating loss carryforwards in the future.

Under federal income tax law, NOL carryforwards can be utilized to reduce future taxable income subject to certain limitations if we were to undergo an ownership change as defined by the Internal Revenue Code. We experienced an ownership change on the Effective Date as a result of the distribution of reorganized Calpine Corporation common stock pursuant to the Plan of Reorganization. We do not expect the annual limitation from this ownership change to result in the expiration of the NOL carryforwards if we are able to generate sufficient future taxable income within the carryforward periods. If a subsequent ownership change were to occur as a result of future transactions in our stock, accompanied by a significant reduction in the market value of the company immediately prior to the ownership change, our ability to utilize the NOL carryforwards may be significantly limited.

In accordance with our Plan of Reorganization, our common stock is subject to certain transfer restrictions contained in our amended and restated certificate of incorporation. These restrictions are designed to minimize the likelihood of any potential adverse federal income tax consequences resulting from an ownership change; however, these restrictions may not prevent an ownership change from occurring. These restrictions are not currently operative but could become operative in the future if certain events occur and the restrictions are imposed by our Board of Directors.

Our financial results may be volatile and may not reflect historical trends.

After our emergence from Chapter 11, the amounts reported in our subsequent Consolidated Financial Statements may materially change relative to our historical Consolidated Financial Statements, including as a result of our restructuring activities, the implementation of our Plan of Reorganization and the continued execution of our business strategies. In addition, as part of our emergence from Chapter 11, as of January 31, 2008, we may be required to adopt fresh start accounting. If fresh start accounting were to apply, our assets and liabilities would be recorded at fair value as of the Effective Date which could materially differ from the recorded values of assets and liabilities recorded at historical cost on our Consolidated Balance Sheets. In addition, our financial results after the application of fresh start accounting may not reflect historical trends. See Note 3 of the Notes to Consolidated Financial Statements for further information on our accounting following emergence from Chapter 11.

We may be subject to claims that were not discharged in the Chapter 11 cases, which could have a material adverse effect on our results of operations and profitability.

The nature of our business subjects us to litigation. Although the majority of the material claims against us that arose prior to the Petition Date were resolved during our Chapter 11 cases, certain of such actions, as well as actions instituted during the pendency of our Chapter 11 cases, have not been resolved, and additional actions could be filed against us in the future. In addition, the Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation and certain debts arising afterwards. With few exceptions, all claims that arose prior to the Petition Date and before confirmation

 

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of the Plan of Reorganization (i) are subject to compromise and/or treatment under the Plan of Reorganization or (ii) were discharged in accordance with the Bankruptcy Code and the terms of the Plan of Reorganization. Circumstances in which claims and other obligations that arose prior to the Petition Date were not discharged primarily relate to certain actions by governmental units under police power authority, where we have agreed to preserve a claimant’s claims or the claimant has received court approval to proceed with its claim, as well as, potentially, instances where a claimant had inadequate notice of the Chapter 11 filing. The ultimate resolution of such claims and other obligations may have a material adverse effect on our results of operations and profitability. Additionally, despite our emergence from Chapter 11 on January 31, 2008, several significant matters remain unresolved in connection with our reorganization, including appeals by several shareholders seeking reconsideration of the Confirmation Order. Unfavorable resolution of these matters could have a material adverse effect on our results of operations and profitability. In particular, while we do not believe that the appeals of the Confirmation Order will be successful, if the Confirmation Order were reversed, it would have a material adverse effect on our business.

Our principal shareholders own a significant amount of our common stock, giving them influence over corporate transactions and other matters.

Three holders (or related groups of holders) of reorganized Calpine Corporation common stock have made filings with the SEC reporting beneficial ownership, directly or indirectly, individually or as members of a group, of 10% or more of the shares of our common stock. These shareholders, who together beneficially own more than 45% of our common stock, may be able to exercise substantial influence over all matters requiring shareholder approval, including the election of directors and approval of significant corporate action, such as mergers and other business combination transactions. If two or more of these shareholders (or groups of shareholders) vote their shares in the same manner, their combined stock ownership may effectively give them the power to elect our entire Board of Directors and control our management, operations and affairs. Currently, two members of our Board of Directors, including the Chairman of our Board, are affiliated, directly or indirectly, with SPO Advisory Corp., one of these shareholders.

Circumstances may occur in which the interests of these shareholders could be in conflict with the interests of other shareholders. This concentration of ownership may also have the effect of delaying or preventing a change in control over us unless it is supported by these shareholders. Accordingly, your ability to influence us through voting your shares may be limited or the market price of our common stock may be adversely affected.

Capital Resources; Liquidity

We have substantial liquidity needs and could face liquidity pressure.

Following our reorganization, including the implementation of our Plan of Reorganization pursuant to which we canceled our old common stock and issued new shares of reorganized Calpine Corporation common stock, we repaid certain of our secured and unsecured debt with a combination of cash and cash equivalents, borrowings under our Exit Facilities and shares of our new common stock. Accordingly, as of the Effective Date, our total funded debt was $10.7 billion. Our consolidated debt outstanding was $10.4 billion, of which approximately $6.4 billion was outstanding under our Exit Facilities. Our pro rata share of unconsolidated subsidiary debt was approximately $0.3 billion. In addition, we had approximately $225 million in letters of credit that had been issued against the revolving credit facility portion of our Exit Facilities. As of December 31, 2007, our cash and cash equivalents were $1.9 billion; our total consolidated assets were $18.5 billion and our stockholders’ deficit was $4.7 billion. Although we have reduced our debt as a result of our reorganization, we could face liquidity challenges as we continue to have substantial debt and to have substantial liquidity needs in the operation of our business. Our ability to make payments on our indebtedness (including interest payments on our Exit Facilities and our other outstanding indebtedness) and to fund planned capital expenditures and development efforts will depend on our ability to generate cash in the future. This, to a certain extent, is

 

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dependent upon industry conditions, as well as general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control, such as the recent volatility in the credit markets due to the economic impacts of the turmoil in the subprime debt markets. Although we expect to continue to have sufficient resources and borrowing capacity under the Exit Facilities and our other existing project credit facilities, and we are permitted to enter into new project financing credit facilities to fund our development and construction activities under certain circumstances, there can be no assurance of the success of our business plan, which will depend on our being able to achieve our budgeted operating results including meeting our liquidity needs. See additional discussion regarding our capital resources and liquidity in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.

Our substantial indebtedness could adversely impact our financial health and limit our operations.

Our level of indebtedness has important consequences, including:

 

   

limiting our ability to borrow additional amounts for working capital, capital expenditures, debt service requirements, potential growth 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 governmental 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.

Substantially all of our indebtedness contains floating rate interest provisions, which could adversely affect our financial health if interest rates were to rise significantly.

Substantially all of our indebtedness contains floating rate interest provisions, which we pay on a current basis. However, interest on such obligations could rise to levels in excess of the cash available to us from operations. If we are unable to satisfy our obligations under our floating rate debt, particularly our Exit Facilities, it could result in defaults under our Exit Facilities and other debt instruments. We manage our interest rate risk through the use of derivative instruments, including interest rate swaps. See also Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Market Risks — Interest Rate Risk.”

We may be unable to obtain 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. For example, because of our credit ratings and the restrictions against additional borrowing in our Exit Facilities, we may not be able to obtain any material amount of additional debt financing, other than through refinancing outstanding debt, or through project financings where we are able to pledge the project assets as security. Other factors include:

 

   

general economic and capital market conditions;

 

   

conditions in energy markets;

 

   

regulatory developments;

 

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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.

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 power generation facilities on terms satisfactory to us. We have financed our existing power generation facilities using a variety of leveraged financing structures, consisting of senior secured and unsecured indebtedness, construction financing, project financing, 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.

Our Exit Facilities impose significant 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 Exit Facilities. These restrictions require us to meet certain financial performance tests on a quarterly basis and limit or prohibit our ability, subject to certain exceptions to, among other things:

 

   

incur additional indebtedness and use of proceeds from the issuance of stock;

 

   

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

 

   

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

 

   

use money borrowed under the Exit Facilities for non-guarantors (including foreign subsidiaries);

 

   

make certain investments;

 

   

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;

 

   

limit dividends or other distributions from certain subsidiaries up to Calpine;

 

   

make capital expenditures beyond specified limits;

 

   

engage in certain business activities; and

 

   

acquire facilities or other businesses.

 

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The Exit Facilities contain events of default customary for financings of this type, including cross defaults and certain change of control events. If we fail to comply with the covenants in the Exit Facilities and are unable to obtain a waiver or amendment or a default exists and is continuing under the Exit Facilities, the lenders could give notice and declare outstanding borrowings and other obligations under the Exit Facilities 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 may not be able to obtain such waivers, amendments or alternative financing, or if obtained, it could be on terms that are not acceptable to us. If we are unable to comply with the terms of the Exit Facilities, 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 our business, results of operations and financial condition.

Our credit status is below investment grade, which may restrict our operations, increase our liquidity requirements and restrict financing opportunities.

Our corporate and debt credit ratings are below investment grade. There is no assurance that our credit ratings will improve in the future, which may restrict the financing opportunities available to us. Our impaired credit has resulted in the requirement that we provide additional collateral in the form of letters of credit or cash for credit support obligations and has had certain adverse impacts on our subsidiaries’ and our business, financial position and results of operations.

Many of our customers and counterparties are requiring that our and our subsidiaries’ obligations be secured by letters of credit or cash. 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. We have up to $1.0 billion available for borrowing under our revolving credit facility under our Exit Credit Facility, of which up to $550 million may be used for letters of credit, which, in addition to $150 million of availability under a letter of credit facility of our subsidiary, Calpine Development Holding Inc., we believe will be sufficient to satisfy our cash collateral and letter of credit support requirements; however, it is possible that such amounts may not be sufficient. While we are exploring with counterparties and financial institutions various alternative approaches to credit support, we may not be able to provide alternative credit support in lieu of cash collateral or letter of credit posting requirements.

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 2007, we recognized $5 million in mark-to-market gains on electric power and natural gas derivatives after recognizing $91 million in gains in 2006 and $11 million in gains in 2005. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Application of Critical Accounting Policies” for a discussion of the significant estimates and judgments utilized in the accounting for commodity derivative instruments. We may enter into other transactions in future periods that require us to mark various derivatives to market through earnings. The volume and 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, which include many commodity contracts, are subject to the inherent risks of such transactions. Consequently many companies, including us, may be required to post cash collateral for certain commodity transactions; and, the level of collateral will increase as a company increases its hedging

 

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activities. As of December 31, 2007 and 2006, to support commodity transactions, we had margin deposits with third parties of $314 million and $214 million, respectively; we had gas and power prepayment balances of $74 million and $114 million, respectively; and we had letters of credit outstanding of $55 million and $2 million, respectively. Counterparties had deposited with us $21 million and nil as margin deposits at December 31, 2007 and 2006, 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 — Our credit status is below investment grade, which may restrict our operations, increase our liquidity requirements and restrict financing opportunities,” above. Certain of our financing arrangements for our facilities have required us to post letters of credit which are at risk of being drawn down in the event we or the applicable subsidiary defaults on certain obligations.

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 Exit Facilities, finance our ongoing operations, and fund our restructuring costs. 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, some of these limitations are subject to a number of significant exceptions (including exceptions permitting such restrictions in connection with subsidiary financings). Accordingly, 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, or during the existence of a default.

We may utilize project financing, preferred equity and other types of subsidiary financing transactions when appropriate in the future.

Our ability and the ability of our subsidiaries to incur additional indebtedness is limited in some cases by existing indentures, debt instruments or other agreements. Our subsidiaries may incur additional construction/project financing indebtedness, issue preferred stock to finance the acquisition and development of new power generation facilities and engage in certain types of non-recourse financings to the extent permitted by existing agreements and may continue to do so in order to fund our ongoing operations. Any such newly incurred subsidiary debt would be added to our current consolidated debt levels and could intensify the risks associated with our already substantial leverage. Any such newly incurred subsidiary preferred stock would likely be structurally senior to our debt and could also intensify the risks associated with our already substantial leverage.

Our Exit Facilities and other parent-company debt is effectively subordinated to certain 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 our indebtedness or indebtedness of other subsidiaries or affiliates, and do not guarantee the payment of interest on or principal of such indebtedness. In the event of our bankruptcy, liquidation or reorganization (or the bankruptcy, liquidation or reorganization of a subsidiary or affiliate), 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 assets are made available for distribution to us or the holders of our indebtedness. In addition, we are also permitted to reorganize our subsidiaries in a manner that allows creditors of one subsidiary to collect against assets currently held by another subsidiary. As a result, holders of our indebtedness will be effectively subordinated to all present and future debts and other liabilities (including trade

 

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payables) of our subsidiaries and affiliates, and holders of debt of one of our subsidiaries or affiliates will effectively be so subordinated with respect to all of our other subsidiaries and affiliates. As of December 31, 2007, our subsidiaries had $1.9 billion of secured construction/project financing, which is effectively senior to our Exit Facilities. We may incur additional project financing indebtedness in the future, which will be effectively senior to our other secured and unsecured debt.

Operations

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 (see Note 17 of the Notes to Consolidated Financial Statements for our 2007 and 2006 quarterly operating results), including:

 

   

seasonal variations in energy and gas prices and capacity payments;

 

   

seasonal fluctuations in weather, in particular unseasonable weather conditions;

 

   

production levels of hydro electricity in the West;

 

   

variations in levels of production, including from forced outages;

 

   

availability of emissions credits;

 

   

natural disasters, wars, sabotage, terrorist acts, earthquakes, hurricanes and other catastrophic events; and

 

   

the completion of development and construction projects.

In particular, a disproportionate amount of our total revenue has historically been realized during the third fiscal quarter and we expect this trend to continue in the future as demand for electricity in our markets peaks in our third fiscal quarter. If our total revenue were below seasonal expectations during that quarter, by reason of facility operational performance issues, cool summers, or other factors, it could have a disproportionate effect on our annual operating results.

In certain situations, our PPAs and other contractual arrangements, including construction agreements, commodity contracts, maintenance agreements and other arrangements may be terminated by the counterparty, and/or may allow the counterparty to seek liquidated damages.

The situations that could allow a contract counterparty to terminate the contract and/or seek liquidated damages include:

 

   

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

 

   

failure of a facility to achieve construction milestones or commercial operation by agreed-upon deadlines;

 

   

failure of a facility to achieve certain output or efficiency minimums;

 

   

failure by us to make any of the payments owed to the counterparty or to establish, maintain, restore, extend the term of, or increase any required collateral;

 

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failure of a facility to obtain material permits and regulatory approvals by agreed-upon deadlines;

 

   

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

 

   

events of liquidation, dissolution, insolvency or bankruptcy.

We may be unable to obtain an adequate supply of natural gas in the future at prices acceptable to us.

We obtain substantially all of our physical natural gas supply from third parties pursuant to arrangements that vary in term, pricing structure, firmness and delivery flexibility. Our physical gas supply arrangements must be coordinated with transportation agreements, balancing agreements, storage services, financial hedging transactions and other contracts so that the natural gas is delivered to our generation facilities at the times, in the quantities and otherwise in a manner that meets the needs of our generation portfolio and our customers. We must also comply with laws and regulations governing gas transportation.

While adequate supplies of natural gas are currently available to us at prices we believe are reasonable for each of our facilities, we are exposed to increases in the price of natural gas and it is possible that sufficient supplies to operate our portfolio profitably may not continue to be available to us. In addition, we face risks with regard to the delivery to and use of natural gas by our generation facilities including the following:

 

   

transportation may be unavailable if pipeline infrastructure is damaged or disabled;

 

   

pipeline tariff changes may adversely affect our ability to or cost to deliver gas supply;

 

   

third-party suppliers may default on gas supply obligations and we may be unable to replace supplies currently under contract;

 

   

market liquidity for physical gas or availability of gas services (e.g. storage) may be insufficient or available only at prices that are not acceptable to us;

 

   

natural gas quality variation may adversely affect our plant operations; and

 

   

our gas operations capability may be compromised due to various events such as natural disaster, loss of key personnel or loss of critical infrastructure.

We rely on electric transmission and natural gas distribution facilities owned and operated by other companies.

We depend on facilities and assets that we do not own or control for the transmission to our customers of the electricity produced in our facilities and the distribution of natural gas fuel to our facilities. If these transmission and distribution systems are disrupted or capacity on those systems is inadequate, our ability to sell and deliver electric energy products or obtain fuel may be hindered. ISOs that oversee transmission systems in regional power markets have imposed price limitations and other mechanisms to address volatility in their power markets. Existing congestion as well as expansion of transmission systems could affect our performance.

Our revenues and results of operations depend on market rules, regulation and other forces beyond our control.

Our revenues and results of operations are influenced by factors that are beyond our control, including:

 

   

rate caps, price limitations and bidding rules imposed by ISOs, RTOs and other market regulators that may impair our ability to recover our costs and limit our return on our capital investments; and

 

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some of our competitors’ (mainly utilities) entitlement-guaranteed rates of return on their capital investments, which returns may in some instances exceed market returns, may impact our ability to sell our energy at economical rates.

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 years) PPAs. Our uncontracted capacity is generally sold on the spot market at current market prices. When the terms of each of our various PPAs expire, it is possible that the price paid to us for the generation of electricity under subsequent arrangements or on the spot market may be significantly less than the price that had been paid to us under the PPA.

Certain of our PPAs have values in excess of current market prices (measured over the next five years). The aggregate value of these PPAs is approximately $1.5 billion at December 31, 2007. 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. The aggregate value of such contracts 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 three customers with which we have multiple contracts that, when combined, constitute greater than 10% of this value: CDWR $0.2 billion, Wisconsin Power & Light $0.2 billion, and Carolina Power & Light $0.2 billion. The values by customer are comprised of multiple individual contracts. Approximately 70% of the calculated value of these PPAs will expire over the next three years. Additionally, our PPAs contain termination provisions standard to contracts in our industry such as negligence, performance default or prolonged events of force majeure.

Our power generating operations performance may be below expected levels of output or efficiency.

The operation of power generation facilities involves many risks, including the breakdown or failure of power generation equipment, transmission lines, pipelines or other equipment or processes, performance below expected levels of output or efficiency and risks related to the creditworthiness of our contract counterparties and the creditworthiness of our counterparties’ customers or other parties (such as steam hosts) with whom our counterparties have contracted. From time to time our power generation facilities have experienced equipment breakdowns or failures. We have experienced a high failure rate on certain turbine equipment due to certain manufacturer defects. We and such manufacturers and certain of our third party service providers have programs in place that we believe reduce the risk of equipment failures, however, it is possible that our affected plants may have reduced availability factors in the future due to such equipment failures.

In addition, a breakdown or failure may prevent the affected facility from performing under any applicable PPAs, commodity contracts or other contractual arrangements. Such failure may allow a counterparty to terminate an agreement and/or seek liquidated damages. 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, or may otherwise breach, our financing obligations, particularly with respect to the affected facility, which could result in our losing our interest in the affected facility or, possibly, one or more other power generation facilities.

Our power project development 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 including environmental permits and approvals;

 

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fuel supply and transportation agreements;

 

   

sufficient equity capital and debt financing;

 

   

electricity transmission agreements;

 

   

water supply and wastewater discharge agreements or permits; and

 

   

site agreements and construction contracts.

To the extent that our development activities continue or expand, we may be unsuccessful in developing power generation facilities on a timely and profitable basis. Although we may attempt to minimize the financial risks in the development of a project by securing a favorable PPA and arranging adequate financing prior to the commencement of construction, the development of a power project may require us to expend significant cash 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 governmental permits and approvals is complicated and lengthy, often taking more than one year, and is subject to significant uncertainties.

Our geothermal energy reserves may be inadequate for our operations.

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. In addition, we may not be able to successfully manage the development and operation of our geothermal reservoirs or accurately estimate the quantity or productivity of our steam reserves. An incorrect estimate or inability to manage our geothermal reserves, or a decline in productivity could adversely affect our results of operations or financial condition. In addition, the development and operation of geothermal energy resources are subject to substantial risks and uncertainties. The successful exploitation of a geothermal energy resource ultimately depends upon many factors including the following:

 

   

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, fluids or power generated; and

 

   

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

Natural disasters could damage our projects.

Certain areas where we operate and are developing many of our geothermal and gas-fired projects, particularly in the West, are subject to frequent low-level seismic disturbances. More significant seismic disturbances are possible. In addition, other areas in which we operate, particularly in Texas and the Southeast, experience tornados and hurricanes. Our existing power generation facilities are built to withstand relatively significant levels of seismic and other 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 damages or disturbances to our facilities or our operations due to natural disasters.

 

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We depend on our management and employees.

Our success is largely dependent on the skills, experience and efforts of our people. While we believe that we have excellent depth throughout all levels of management and in all key skill levels of our employees, the loss of the services of one or more members of our senior management or of numerous employees with critical skills could have a negative effect on our business, financial condition and results of operations and future growth if we could not replace them. In particular, our Chief Executive Officer has announced his intent to leave the Company once a successor is in place, and certain of our other senior management positions are currently held by consultants under temporary arrangements. If we are not able to attract talented, committed individuals to fill these positions, it may adversely affect our ability to fully implement our business objectives.

We depend on computer and telecommunications systems we do not own or control.

We have entered into agreements with third parties for hardware, software, telecommunications, and database services in connection with the operation of our facilities. In addition, we have developed proprietary software systems, management techniques and other information technologies incorporating software licensed from third parties. Any interruptions to our arrangements with third parties, to our computing and communications infrastructure, or our information systems could significantly disrupt our business operations.

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 addition, many states are implementing or considering regulatory initiatives designed to increase competition in the domestic power industry. 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 could increase this pressure. In addition, construction during the last decade has created excess power supply and higher reserve margins, which has led to tight liquidity in the energy trading markets, putting downward pressure on prices.

Governmental Regulation

We are subject to complex governmental 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.

Generally, in the U.S., we are subject to regulation by FERC regarding the terms and conditions of wholesale service and the sale and transportation of natural gas, as well as by state agencies regarding physical aspects of the generation facilities. The majority of our generation is sold at market prices under the market-based rate authority granted by the FERC. If certain conditions are not met, FERC has the authority to withhold or rescind market-based rate authority and require sales to be made based on cost-of-service rates. A loss of our market-based rate authority could have a materially negative impact on our generation business. FERC could also impose fines or other restrictions or requirements on us under certain circumstances.

We are also subject to numerous environmental regulations. For example, in March 2005, the EPA adopted a significant air quality regulation, CAIR, that affects our fossil fuel-fired generating facilities located in the eastern half of the U.S. CAIR 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

 

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to individual facilities. States’ allocation mechanisms, which are expected to be complete in 2008, will ultimately determine the net impact to us. In addition, the potential for future regulation of emissions of GHG continues to be on the national agenda. Our power generation facilities are significant sources of CO2 emissions, a GHG. Our compliance costs with any future federal regulation of GHG could be material.

The adoption of new laws and regulations applicable to us or the perception that new laws and regulations will be adopted that are applicable to us could have a material adverse impact on our business, results of operations or financial condition. There are proposals in many jurisdictions both to advance and to reverse the movement toward competitive markets for supply of electricity, at both the wholesale and retail level. In addition, any future legislation favoring large, vertically integrated utilities and a concentration of ownership of such utilities could impact our ability to compete successfully, and our business and results of operations could suffer. 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.

If we were deemed to have market power in certain markets as a result of the ownership of our stock by certain significant shareholders, we could lose FERC authorization to sell power at wholesale at market-based rates in such markets or be required to engage in mitigation in those markets to counteract the market power.

Certain of our significant shareholders own power generating assets in markets where we currently own generating assets. We do not believe that we have market power as a consequence of their ownership of our common stock, and we have submitted an analysis to FERC to support this position. However, it is possible that FERC could have a different view on this issue, in which case FERC would have the authority to, among other things, revoke market-based rate authority for the affected market-based companies or order them to mitigate that market power. If market-based rate authority were revoked for any of our market-based rate companies, those companies would be required to make wholesale sales of power based on cost-of-service rates, which could impact their revenues. A loss of our market-based rate authority, particularly if it affected several of our power plants or was in a significant market such as California, could have a materially negative impact on our business, results of operations and financial condition.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Our principal executive offices are located in San Jose, California and Houston, Texas. These facilities are leased until 2009 and 2013, respectively. We also lease offices for regional operations in Folsom, Sacramento, and Pleasanton, California; Lincolnshire, Illinois; La Porte, Texas; and Washington, D.C.

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

Item 3. Legal Proceedings

See Note 15 of the Notes to Consolidated Financial Statements for a description of our legal proceedings.

 

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

Holders of our common stock outstanding prior to the confirmation of the Plan of Reorganization, as well as holders of certain of our debt securities, including all of our unsecured debt securities, outstanding prior to confirmation of the Plan of Reorganization were among the classes of creditors that voted to approve the Plan of Reorganization, including the amendment and restatement of our certificate of incorporation and the adoption of the Calpine Equity Incentive Plans as provided in the Plan of Reorganization. The Plan of Reorganization was confirmed by the U.S. Bankruptcy Court on December 19, 2007, and became effective on January 31, 2008. See Item 1. “Business — Overview — Chapter 11 Cases and CCAA Proceedings” for more information.

PART II

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

Public trading of our previously outstanding common stock originally 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. From December 6, 2005, to January 31, 2008, our common stock traded in the over-the-counter market as reported on the Pink Sheets under the symbol “CPNLQ.PK.” On January 31, 2008, pursuant to the Plan of Reorganization, our previously outstanding common stock was canceled and we authorized and began issuance of the 485 million shares of reorganized Calpine Corporation common stock to settle unsecured claims pursuant to the Plan of Reorganization. On January 16, 2008, the shares of reorganized Calpine Corporation common stock were admitted to listing on the NYSE and began “when issued” trading under the symbol “CPN-WI.” The reorganized Calpine Corporation common stock began “regular way” trading on the NYSE under the symbol “CPN” on February 7, 2008.

The following table sets forth the high and low bid prices for our old common stock for each quarter of the calendar years 2006 and 2007, as reported on the Pink Sheets. 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/Report  

2007

        

First Quarter

   $                2.19    $                1.09    Pink Sheets

Second Quarter

     4.15      1.99    Pink Sheets

Third Quarter

     3.75      1.05    Pink Sheets

Fourth Quarter

     1.80      0.18    Pink Sheets

2006

        

First Quarter

   $ 0.35    $ 0.15    Pink Sheets

Second Quarter

     0.52      0.21    Pink Sheets

Third Quarter

     0.47      0.32    Pink Sheets

Fourth Quarter

     1.46      0.26    Pink Sheets

As of December 31, 2007, there were 2,222 holders of record of our common stock. See Note 3 of the Notes to Consolidated Financial Statements for a discussion of the effects of emergence from Chapter 11 on our capital structure.

To reduce the risk of a potential adverse effect on our ability to utilize our NOL carryforwards, our amended and restated certificate of incorporation contains certain restrictions on the transfer of our common stock. These transfer restrictions are not currently operative, but could become operative in the future if certain

 

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events occurred and if our Board of Directors determines to implement them. While the purpose of these transfer restrictions is to prevent an “ownership change” from occurring within the meaning of Section 382 of the Internal Revenue Code, no assurance can be given that such an ownership change will not occur.

Our ability to pay cash dividends is restricted under the terms of the Exit Facilities, and it is not anticipated that any cash dividends will be paid on our common stock in the near future. 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 Item 1A. “Risk Factors,” including “— Risks Relating to Emergence from Chapter 11” for a discussion of additional risks related to our common stock.

Item 6. Selected Financial Data

SELECTED CONSOLIDATED FINANCIAL DATA

 

     Years Ended December 31,  
     2007    2006     2005     2004     2003  
     (in millions, except earnings (loss) per share)  

Statement of Operations data:

           

Operating revenues

   $ 7,970    $ 6,937     $ 10,302     $ 8,645     $ 8,405  
                                       

Income (loss) before discontinued operations and cumulative effect of a change in accounting principle(1)

   $ 2,693    $ (1,765 )   $ (9,881 )   $ (420 )   $ (13 )

Discontinued operations, net of tax

                (58 )     177       114  

Cumulative effect of a change in accounting principle, net of tax(2)

                            181  
                                       

Net income (loss)(1)

   $ 2,693    $ (1,765 )   $ (9,939 )   $ (243 )   $ 282  
                                       

Basic earnings (loss) per common share:

           

Income (loss) before discontinued operations and cumulative effect of a change in accounting principle(1)

   $ 5.62    $ (3.68 )   $ (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(2)

                            0.46  
                                       

Net income (loss)(1)

   $ 5.62    $ (3.68 )   $ (21.44 )   $ (0.56 )   $ 0.72  
                                       

Diluted earnings (loss) per common share:

           

Income (loss) before discontinued operations and cumulative effect of a change in accounting principle(1)

   $ 5.62    $ (3.68 )   $ (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(2)

                            0.45  
                                       

Net income (loss)(1)

   $ 5.62    $ (3.68 )   $ (21.44 )   $ (0.56 )   $ 0.71  
                                       

Balance Sheet data:

           

Total assets

   $     18,482    $     18,590     $     20,545     $     27,216     $     27,304  

Short-term debt and capital lease obligations(3)

     1,710      4,569       5,414       1,029       347  

Long-term debt and capital lease obligations(3)(4)

     9,946      3,352       2,462       16,941       17,324  

Liabilities subject to compromise(4)

     8,788      14,757       14,610              

 

 

(1)

As a result of our Chapter 11 and CCAA filings, for the year ended December 31, 2005, we recorded $5.0 billion of reorganization items primarily related to the provisions for expected allowed claims, impairment of our Canadian subsidiaries, guarantees, write-off of unamortized deferred financing costs and losses on

 

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terminated contracts. During 2007, we were released from a portion of our direct and indirect Canadian guarantee of the ULC I notes, ULC II notes and redundant Canadian claims and recorded a $4.1 billion credit for the reversal of these redundant claims.

 

(2) The 2003 gain from the cumulative effect of a change in accounting principle primarily related to a gain of $182 million, net of tax effect, from the adoption of certain provisions of SFAS No. 133.

 

(3) As a result of our Chapter 11 filings, we reclassified approximately $5.1 billion of long-term debt and capital lease obligations to short-term at December 31, 2006 and 2005, as the Chapter 11 filings constituted events of default or otherwise triggered repayment obligations for the Calpine Debtors and certain Non-Debtor entities. We classified our long-term debt and capital lease obligations at December 31, 2007, based upon the refinanced terms of our Exit Facilities. See Note 8 of the Notes to Consolidated Financial Statements for more information.

 

(4) LSTC include 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 Chapter 11 filings and other approved payments such as taxes and payroll. As a result of our Chapter 11 filings, we reclassified approximately $7.5 billion of long-term debt to LSTC at December 31, 2005. We classified our long-term debt based upon the terms of our Plan of Reorganization at December 31, 2007. See Note 3 of the Notes to Consolidated Financial Statements for more information.

See Note 3 of the Notes to Consolidated Financial Statements regarding certain “plan effect” adjustments to our Consolidated Balance Sheet as of the Effective Date.

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

Forward-Looking Information

This Managements’ Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our accompanying Consolidated Financial Statements and related notes. See the cautionary statement regarding forward-looking statements on page 1 of this Report for a description of important factors that could cause actual results to differ from expected results. See also Item 1A. “Risk Factors.”

EXECUTIVE OVERVIEW

Our Business

We are an independent power producer that operates and develops clean and reliable power generation facilities primarily in the U.S. Our fleet of power generation facilities, with nearly 24,000 MW of capacity as of December 31, 2007, makes us one of the largest independent power producers in the U.S. Our portfolio is comprised of two power generation technologies: natural gas-fired combustion (primarily combined-cycle) and renewable geothermal. We operate 60 natural gas-fired power facilities located in the West (approximately 6,521 MW, primarily in California), Texas (approximately 7,487 MW), Southeast (approximately 6,254 MW) and North (approximately 2,822 MW). We also operate 17 geothermal facilities in the Geysers region of northern California capable of producing 725 MW, which are reported within our West segment. Our renewable geothermal facilities are the largest producing geothermal resource in the U.S.

We are focused on maximizing value by leveraging our portfolio of power plants, our geographic diversity and our operational and commercial expertise to provide the optimal combination of products and services to our customers. To accomplish this goal, we seek to maximize asset performance, optimize the management of our commodity exposure and take advantage of growth and development opportunities that fit our core business and are accretive to earnings.

During 2006 and 2007, and through the Effective Date, we conducted our business in the ordinary course as debtors-in-possession under the protection of the Bankruptcy Courts. We emerged from Chapter 11 on January 31, 2008, as described below in “— Our Emergence From Chapter 11.”

 

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Our Business Segments

We assess our business primarily on a regional basis due to the impact on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors impacting supply and demand. Accordingly, our reportable segments are West (including geothermal), Texas, Southeast, North and Other. Our “Other” segment includes fuel management, our turbine maintenance group, our TTS and PSM businesses prior to their sale and certain hedging and other corporate activities.

We use the non-GAAP financial measure “commodity margin” to assess our financial performance on a consolidated basis and by our reportable segments. Commodity margin includes our electricity and steam revenues, hedging and optimization activities, renewable energy credit revenue, transmission revenue and expenses, and fuel and purchased energy expenses, but excludes mark-to-market activity and other service revenues. We believe that commodity margin is a useful tool for assessing the performance of our core operations and is a key operational measure reviewed by our chief operating decision maker. Commodity margin is not a measure calculated in accordance with GAAP, and should be viewed as a supplement to and not a substitute for our results of operations presented in accordance with GAAP. Commodity margin does not purport to represent net income (loss), the most comparable GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly-titled measures reported by other companies. See “— Results of Operations for the Years Ended December 31, 2007 and 2006 — Consolidated Commodity Margin” and “— Results of Operations for the Years Ended December 31, 2006 and 2005 — Consolidated Commodity Margin” for a reconciliation of commodity margin to our GAAP results.

Our Key Financial Performance Drivers

Our commodity margin and cash flows from operations are primarily derived from the sale of electricity and electricity-related products generated predominantly from our natural gas-fired power generation portfolio. Thus, the spread between natural gas prices and power prices contributes significantly to our financial results and is the primary component of our commodity margin. Natural gas prices, weather, generation outages and reserve margins have the most significant impact on our commodity margin due to the impact each has on our power prices and natural gas costs resulting from changes in supply and demand. In addition, our plant operating performance and availability are key to our performance.

Natural gas prices and power prices are generally correlated in our two primary markets, the West and Texas, because plants using natural gas-fired technology tend to be the marginal or price-setting generation units in these regions. Holding other factors constant, where natural gas is the price-setting fuel, higher natural gas prices tend to increase our commodity margin. This is because our combined-cycle plants are more fuel-efficient than many other older gas-fired technologies and peaking units. The older units with higher operating costs often set power prices in our West and Texas regions, creating positive commodity margin for us. However, the positive relationship between natural gas prices and our commodity margin does not take into account the effects of our fixed-price PPAs and will tend to break down where natural gas-fired units are not on the margin such as is often seen in the off-peak periods or in markets where non-gas-fired capacity can satisfy the majority of the demand. Our geothermal units do not consume natural gas, and, because there is a direct relationship between power prices and natural gas prices in the West, increases in natural gas prices generally benefit our geothermal units.

Weather could have a significant short-term impact on supply and demand. In addition, a disproportionate amount of our total revenue is realized during our third fiscal quarter and we expect this trend to continue in the future as U.S. demand for electricity peaks during this time. Typically, demand for and the price of electricity is higher in the summer and winter seasons when temperatures are more extreme, and therefore, our revenues and commodity margin could be negatively impacted due to relatively cool summers or mild winters.

Generation outages and reserve margins also impact supply and demand and the price for electricity, particularly in markets where reserve margins are low or transmission constraints require that baseload generation be served from generation units operating within that market (such as in the West). In addition,

 

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efficient operation of our fleet creates the opportunity to capture commodity margin in a cost effective manner. However, unplanned outages during periods of positive commodity margin could result in a loss of such opportunity. We generally measure our fleet performance based on our availability factors, Heat Rate and plant operating expense. The higher our availability factor, the better positioned we are to capture commodity margin. The less natural gas we must consume for each MWh of electricity generated, the lower our Heat Rate and the higher our commodity margin. See “— Operating Performance Metrics” for additional information.

Our non-operating income and expenses are primarily driven by our financing and restructuring activities. Prior to recording the post-petition interest on LSTC in December of 2007, interest expense related to LSTC was reported only to the extent that it was paid during the pendency of the Chapter 11 cases, was permitted by the Cash Collateral Order or pursuant to orders of the U.S. Bankruptcy Court or was deemed probable of payment. In particular, we made periodic cash adequate protection payments to the holders of Second Priority Debt. We continued to pay the contractual interest on debt not subject to compromise which generally consisted of the project finance facilities of our Non-Debtors. Following the Effective Date, interest expense is accrued on all of our outstanding debt, most significantly the amounts outstanding under our Exit Facilities.

As a result of our restructuring activities, we have incurred substantial expenses or reorganization items which represent the direct and incremental costs related to our Chapter 11 cases such as professional fees, pre-petition liability claim adjustments and losses that are probable and can be estimated, net of interest income earned on cash accumulated during the Chapter 11 cases, gains on the sale of assets or resulting from certain settlement agreements related to our restructuring activities and accruals for emergence incentives and employee severance costs related to our restructuring. Following the Effective Date, any additional income or expense resulting from the implementation of our Plan of Reorganization is included in our operating income (loss).

Our Financial Performance Highlights

During 2007, we recognized net income of $2.7 billion compared to a net loss of $1.8 billion during 2006. Our current year net income primarily resulted from (i) a gain of $4.1 billion in reorganization items related to the Canadian Settlement Agreement, which significantly reduced our obligations under Calpine Corporation’s guarantee of debt issued by certain Canadian Debtors that were deconsolidated in 2005 and (ii) gains from asset sales during 2007. These gains were partially offset by an increase in interest expense of $765 million primarily due to the accrual of post-petition interest expense and an increase in reorganization items for contract rejection and repudiation activities, allowed claim settlements primarily for make whole and other damages claims, asset impairments and costs associated with the refinancing of the Original DIP Facility and repayment of the CalGen Secured Debt.

During 2007, we recognized commodity margin of $2,225 million, an increase of 10% over the same period in 2006. Our gross profit during 2007 was $895 million, as compared to $740 million during 2006. The increase in our core earnings was primarily related to our increase in commodity margin.

Our Emergence from Chapter 11

We emerged from Chapter 11 on January 31, 2008. We were able to meet every critical milestone during our restructuring process and stay on our timeline for emergence pursuant to a comprehensive Plan of Reorganization which, after settlements with certain stakeholders, all classes of creditors voted to approve. Our Plan of Reorganization provides for the discharge of claims through the issuance of reorganized Calpine Corporation common stock, cash and cash equivalents, or a combination thereof. On or about the Effective Date, we canceled all of our then outstanding common stock and authorized the issuance of 485 million shares of reorganized Calpine Corporation common stock for distribution to holders of unsecured claims and for general contingencies pursuant to our Plan of Reorganization. In addition, we issued warrants to purchase 48.5 million shares of reorganized Calpine Corporation common stock to the holders of our previously outstanding common stock that had been canceled on the Effective Date. Our reorganized Calpine Corporation common stock has been re-listed on the NYSE and began “regular way” trading under the symbol “CPN” on February 7, 2008.

 

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During the pendency of the Chapter 11 cases, we undertook an asset rationalization process that resulted in the sale of certain under-performing assets and non-core businesses, the reconfiguration of equipment or restructuring of existing agreements which merited the continued operation of certain projects and the sale of two projects for which construction was suspended. We are also actively marketing two natural gas-fired power plants and their eventual sale remains a possibility. We believe these actions poise us to compete more effectively in the future in the markets in which we operate.

We have also improved our capital structure. At the Petition Date, we carried $17.4 billion of debt with an average interest rate of 10.3%. Over the past two years, we have implemented initiatives to simplify our capital structure and to reduce our contractual interest expense. As a result of retiring unsecured debt with reorganized Calpine Corporation common stock and the sale of certain of our assets and the repayment or refinancing of certain project debt, we have reduced our pre-petition debt by approximately $7.0 billion. On the Effective Date, we closed on our approximately $7.3 billion of Exit Facilities. Amounts drawn under the Exit Facilities at closing, which totaled approximately $6.4 billion, were used to fund cash payment obligations under the Plan of Reorganization including the repayment of a portion of the Second Priority Debt and the payment of administrative claims and other pre-petition claims, as well as to pay fees and expenses in connection with the Exit Facilities and for working capital and general corporate purposes. Upon our emergence from Chapter 11, we carried $10.4 billion of debt with an average interest rate of 8.1%.

Our Challenges

We remain focused on increasing our earnings and generating cash flow sufficient to maintain adequate levels of liquidity to service our debt and to fund our operations. We will continue to pursue opportunities to improve our fleet performance and reduce operating costs. In order to manage our various physical assets and contractual obligations, we will continue to execute commodity hedging agreements within the guidelines of our commodity risk policy. In addition, as we emerge from Chapter 11, we are developing a long-term strategy that seeks to optimize the value from our existing assets and to pursue additional growth opportunities at existing or new sites that will be accretive to our financial results.

We could potentially face downward pressure on our commodity margin as a result of an economic recession. The downward pressure impacts would be highly dependent on the severity and duration of an economic recession. During pronounced recessionary periods, there can be a decrease in power demand primarily driven by decreased usage by the industrial and manufacturing sectors. This “softening” of demand typically results in more demand satisfied by baseload and intermediate units using lower variable cost fuel sources such as coal and nuclear fuel, and less demand served by higher variable cost units such as gas-fired peaking facilities.

The recent push to implement new environmental regulations is expected to have a significant impact on the power generation industry. At the federal level, there has been increased attention to climate change. Several bills to regulate GHG emissions have already been introduced in Congress, and more are expected in 2008. Several states and regional organizations are also developing, or have already developed, state-specific or regional initiatives to reduce GHG emissions through mandatory programs. We are actively participating in these debates at the federal, state and regional levels. Although the ultimate legislation and regulations that result from these activities could have a material impact on our business, we believe we will face a lower compliance burden than some competitors due to the relatively low GHG emission rates of our fleet.

Our success is largely dependent on the skills, experience and efforts of our people. While we believe that we have excellent depth throughout all levels of management and in all key skill levels of our employees, certain of our management positions are currently held by consultants under temporary arrangements in order to provide us with the specific skill sets and experience required to guide us through our restructuring process. As we emerge from Chapter 11, we will be seeking to retain individuals to fill those positions on a long-term basis.

 

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Financial Reporting Matters and Comparability Related to our Emergence

As of the Petition Date, we deconsolidated most of our Canadian and other foreign entities as we determined that the administration of the CCAA proceedings in a jurisdiction other than that of the U.S. Debtors resulted in a loss of the elements of control necessary for consolidation. On February 8, 2008, the Canadian Effective Date, the proceedings under the CCAA were terminated and accordingly, these entities were reconsolidated, which consisted of a 50% ownership interest in the 50-MW Whitby Cogeneration power plant, approximately $34 million of debt and various working capital items. Because the reconsolidation occurred after December 31, 2007, our Consolidated Financial Statements contained herein exclude the financial statements of the Canadian Debtors and the information in this Report principally describes the Chapter 11 cases and only describes the CCAA proceedings where they have a material effect on our operations or where such information provides necessary background information.

In connection with our emergence from Chapter 11, we recorded certain “plan effect” adjustments to our Consolidated Balance Sheet as of the Effective Date in order to reflect certain provisions of our Plan of Reorganization. These “plan effect” adjustments included the distribution of approximately $4.1 billion in cash and the authorized issuance of 485 million shares of reorganized Calpine Corporation common stock primarily for the discharge of LSTC, repayment of the Second Priority Debt and for various other administrative and other post-petition claims. As a result, we estimate that our equity will increase by approximately $8.8 billion.

Future Performance Indicators

Our historical financial performance during the pendency of the Chapter 11 cases and CCAA proceedings is likely not indicative of our future financial performance because, among other things: (i) we generally have not accrued interest expense on our debt classified as LSTC during the pendency of our Chapter 11 cases, except pursuant to orders of the U.S. Bankruptcy Court and post-petition interest expense included in our Plan of Reorganization and accrued during the fourth quarter of 2007; (ii) we have and expect to further dispose of, or restructure agreements relating to, certain plants that do not generate positive cash flow or which are otherwise considered non-strategic; (iii) we have implemented overhead reduction programs, including staff reductions and non-core office closures; (iv) we have rejected, repudiated or terminated certain unprofitable or burdensome contracts and leases; (v) we have been able to assume certain beneficial contracts and leases (vi) on February 8, 2008, we reconsolidated certain Canadian and other foreign subsidiaries that had been deconsolidated during 2006 and 2007 as a result of the CCAA proceedings; during the period they were deconsolidated, we accounted for our investment in such entities under the cost method. See Notes 2 and 3 of the Notes to Consolidated Financial Statements for further information.

 

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RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2007 AND 2006

Set forth below are the results of operations for the year ended December 31, 2007, as compared to the same period in 2006 (in millions, except for unit pricing information and percentages). 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 in the “$ Change” and “% Change” columns.

 

     Years Ended December 31,              
     2007     2006     $ Change     % Change  
     (in millions)  

Operating revenues

   $ 7,970     $ 6,937     $ 1,033     15%  

Cost of revenue:

        

Fuel and purchased energy expenses

     5,683       4,752       (931 )   (20 )

Plant operating expense

     749       750       1      

Depreciation and amortization

     463       470       7     1  

Operating plant impairments

     44       53       9     17  

Other cost of revenue

     136       172       36     21  
                          

Gross profit

     895       740       155     21  
Equipment, development project and other impairments      2       65       63     97  

Sales, general and other administrative expense

     146       175       29     17  

Other operating expenses

     42       36       (6 )   (17 )
                          

Income from operations

     705       464       241     52  

Interest expense

     2,019       1,254       (765 )   (61 )

Interest (income)

     (64 )     (79 )     (15 )   (19 )

Loss from various repurchases of debt

           18       18     #  

Minority interest expense

           5       5     #  

Other (income) expense, net

     (139 )     (5 )     134     #  
                          

Loss before reorganization items and income taxes

     (1,111 )     (729 )     (382 )   (52 )

Reorganization items

     (3,258 )     972       4,230     #  
                          

Income (loss) before income taxes

     2,147       (1,701 )     3,848     #  

Provision (benefit) for income taxes

     (546 )     64       610     #  
                          

Net income (loss)

   $        2,693     $       (1,765 )   $        4,458     #  
                          

 

 

# Variance of 100% or greater

Operating revenues increased primarily as a result of a 9% increase in generation for the year ended December 31, 2007, compared to the same period in 2006, and a 48% increase in hedging and optimization revenues in 2007 as compared to 2006. The reduction in the availability of credit and the termination or disruption of certain customer relationships due to our Chapter 11 filings and reduced generation in 2006 had curtailed the amount of hedging and optimization activity during that period while these conditions were less of a factor in 2007. These factors were partially offset by lower mark-to-market gains on undesignated derivative electricity contracts, which declined by $79 million year over year.

Fuel and purchased energy expenses increased due to higher generation and a 13% increase in the average cost of natural gas consumed for the year ended December 31, 2007, compared to the year ended December 31, 2006. Also contributing to the increase was higher hedging and optimization expenses due to the higher level of such activity in 2007 compared to 2006.

 

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Operating plant impairments of $44 million during the year ended December 31, 2007, were recorded primarily for the Bethpage Power Plant resulting from the expected adverse impact on electric power pricing of new electric power transmission capacity from the PJM market into Long Island. Our operating plant impairments for the year ended December 31, 2006, consisted primarily of a $50 million impairment relating to Fox Energy Center. Certain impairment charges related to our restructuring activities were also recorded during the year ended December 31, 2007, as reorganization items as discussed below.

Other cost of revenue decreased for the year ended December 31, 2007, compared to the year ended December 31, 2006, resulting primarily from lower operating lease expense and lower cost of revenue at PSM, which was sold in March of 2007.

Equipment, development project and other impairments decreased primarily due to the non-recurrence of $65 million in impairment charges recorded for the year ended December 31, 2006, related to certain turbine-generator equipment not assigned to projects for which we determined near-term sales were likely. During the year ended December 31, 2007, an additional $2 million in impairments were recorded related to these turbines resulting from reduced estimated sales prices.

Sales, general and other administrative expense decreased for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily due to an $11 million net reduction in personnel costs resulting from lower headcount and the sale of PSM in early 2007 as well as lower professional fees and consulting fees of $10 million.

Interest expense increased for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily due to $376 million in post-petition interest related to the ULC I notes resulting from the Canadian Settlement Agreement and $347 million in post-petition interest related to other pre-petition obligations recorded during the year ended December 31, 2007, while no similar expense was recorded in the prior year. We also recorded $126 million in default interest in late 2007 related to various settlements reached as well as expected allowed claims for default interest on the CalGen Second Lien Debt and CalGen Third Lien Debt. This was partially offset by the net effect of the refinancings of the CalGen Secured Debt and the Original DIP Facility in late March 2007 primarily using proceeds under the DIP Facility, which carried lower interest rates, and by the repayment of the First Priority Notes in May and June of 2006 using restricted cash and funds available under the Original DIP Facility, which also carried lower interest rates. The total increase in interest expense was also partially offset by a $43 million decrease due to the extinguishment of certain project financing debt as a result of our asset sales, principally related to the Fox Energy Center and Aries Power Plant.

Other (income) expense, net increased for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily as a result of $135 million in income pertaining to a claim settlement with a customer which received court approval during the year ended December 31, 2007. The claim, which was approved by the court hearing the customer’s bankruptcy case, related to the customer’s rejection of our energy services agreement following the customer’s bankruptcy filing, which was unrelated to our Chapter 11 cases.

 

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The table below lists the significant items within reorganization items for the years ended December 31, 2007 and 2006.

 

     2007     2006     $ Change     % Change  
     (in millions)  

Provision for expected allowed claims

   $       (3,687 )   $           845     $        4,532     # %

Gains on asset sales

     (285 )     (106 )     179     #  

Asset impairments

     120             (120 )                  —  
DIP Facility financing and CalGen Secured Debt repayment costs      202       39       (163 )   #  

Interest (income) on accumulated cash

     (59 )     (25 )     34     #  

Professional fees

     217       153       (64 )   (42 )

Other

     234       66       (168 )   #  
                          

Total reorganization items

   $ (3,258 )   $ 972     $ 4,230     #  
                          

 

 

# Variance of 100% or greater

Provision for Expected Allowed Claims — During the year ended December 31, 2007, our provision for expected allowed claims consisted primarily of (i) a $4.1 billion credit related to the settlement of claims related to Calpine Corporation’s guarantee of the ULC I notes and the release of our guarantee of the ULC II notes following repayment of those notes in September 2007, (ii) accruals totaling $275 million for make whole premiums and/or damages related to the First Priority Notes, Second Priority Debt and Unsecured Notes settlements, (iii) $141 million resulting from the termination of the RockGen operating lease agreement and write-off of the related prepaid lease expense, (iv) $112 million resulting from the repudiation of a gas transportation contract, (v) a $99 million credit resulting from the negotiated settlement of certain repudiated gas transportation contracts, (vi) $85 million related to the settlement agreement with Cleco as a result of the rejection of two PPAs for the output of the Acadia Energy Center, and (vii) an additional accrual of $79 million resulting from the rejection of certain leases and other agreements related to the Rumford and Tiverton power plants for which we agreed to allow general unsecured claims in the aggregate of $190 million. During the year ended December 31, 2006, our provision for expected allowed claims related primarily to repudiated gas transportation and power transmission contracts, the rejection of the Rumford and Tiverton power plant leases and the write-off of prepaid lease expense and certain fees and expenses related to the transaction.

Gains on Asset Sales — During the year ended December 31, 2007, gains on asset sales primarily resulted from the sales of the Aries Power Plant, Goldendale Energy Center, PSM and Parlin Power Plant. During the year ended December 31, 2006, gains on asset sales primarily resulted from the sale of the Dighton Power Plant and Fox Energy Center. See Note 7 of the Notes to Consolidated Financial Statements for further information.

Asset Impairments — During the year ended December 31, 2007, asset impairment charges consisted primarily of a pre-tax, predominately non-cash impairment charge of approximately $89 million in reorganization items to record our interest in Acadia PP at fair value less cost to sell. See Note 7 of the Notes to Consolidated Financial Statements for further information.

DIP Facility Financing and CalGen Secured Debt Repayment Costs — During the year ended December 31, 2007, we recorded costs related to the refinancing of our Original DIP Facility and repayment of the CalGen Secured Debt consisting of (i) $52 million of DIP Facility transaction costs, (ii) the write-off of $32 million in unamortized discount and deferred financing costs related to the CalGen Secured Debt and (iii) $76 million as our estimate of the expected allowed claims resulting from the unsecured claims for damages granted to the holders of the CalGen Secured Debt. During the year ended December 31, 2007, we also recorded transaction costs of $22 million related to the execution of a commitment letter to fund additional exit financing as well as $13 million for secured shortfall claims relating to settlements for the First Priority Notes and the CalGen First Lien Debt. See Note 8 of the Notes to Consolidated Financial Statements for further information.

 

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Professional Fees — The increase in professional fees for the year ended December 31, 2007, over the comparable period in 2006 resulted primarily from an increase in activity managed by our third party advisors related to our Plan of Reorganization, litigation and claims reconciliation matters.

Other — Other reorganization items increased primarily due to a $156 million increase in foreign exchange losses on LSTC denominated in a foreign currency over the comparable period in the prior year.

Provision (benefit) for income taxes — For the year ended December 31, 2007, we recorded a tax benefit of approximately $546 million consisting primarily of $485 million related to the release of valuation allowance. See Note 9 of the Notes to Consolidated Financial Statements for further information regarding our income taxes.

Consolidated Commodity Margin

The following table reconciles our commodity margin to our GAAP results for the years ended December 31, 2007 and 2006 (in millions).

 

             2007                     2006          

Operating revenues

   $         7,970     $         6,937  

(Less): Other service revenues

     (57 )     (73 )

(Less): Fuel and purchased energy expenses

     (5,683 )     (4,752 )

Adjustment to remove: Mark-to-market activity, net(1)

     (5 )     (91 )
                

Consolidated commodity margin

   $ 2,225     $ 2,021  
                

 

 

(1) Included in operating revenues and fuel and purchased energy expenses.

Our consolidated commodity margin increased by $204 million, or 10%, for the year ended December 31, 2007, compared to the year ended December 31, 2006. The increase is primarily due to a 9% increase in generation resulting from stronger demand in 2007 over the same period a year ago when we had experienced milder weather in most of our markets. Our average capacity factor, excluding peakers, increased to 46.6% in 2007 compared to 39.2% in 2006. Marginally higher average open market spark spreads in our key markets also contributed to the increase in consolidated commodity margin.

Commodity Margin by Segment

 

     2007     2006     $ Change     % Change  
     (in millions)  

West

     $        1,196     $         1,037     $            159                    15 %

Texas

     500       477       23     5  

Southeast

     268       215       53     25  

North

     283       313       (30 )   (10 )

Other

     (22 )     (21 )     (1 )   (5 )
                          

Consolidated commodity margin

   $ 2,225     $ 2,021     $ 204     10  
                          

Commodity margin increased in our West, Texas and Southeast segments for the year ended December 31, 2007, compared to the year ended December 31, 2006, largely resulting from higher generation in these regions. The decrease in commodity margin in our North segment largely resulted from a decrease in generation during the same periods.

West — Commodity margin in our West segment increased by 15% for the year ended December 31, 2007, compared to the same period a year ago, partially resulting from a 7% increase in generation in spite of a 4% decrease in our average total MW in operation, which was largely due to the sale of the Goldendale Energy

 

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Center in February 2007. Our average capacity factor, excluding peakers, increased in the West segment to 65.3% in 2007 from 58.7% in 2006. Open market spark spreads were higher in 2007 as our West segment experienced warmer temperatures in 2007 compared to 2006. Additionally, in the first half of 2006 there was unseasonably high rainfall in the Pacific Northwest, which led to increased hydroelectric production, which, correspondingly, dampened demand for gas-fired generation. Our geothermal commodity margin also increased, benefiting from higher average electric prices in 2007 and the restructuring of a renewable energy contract.

Texas — Commodity margin in our Texas segment increased by 5% as we experienced a 22% increase in generation for the year ended December 31, 2007, compared to the same period a year ago. We experienced more favorable temperatures during the first half of 2007 compared to the same period in 2006 in our Texas segment which led to increased demand. Our average capacity factor increased in 2007 to 52.1% from 41.7% in 2006 primarily due to the higher demand in 2007 and due to higher unplanned outage hours in 2006 at several of our power plants in Texas. Lower average open market spark spreads in 2007 compared to 2006 partially offset the favorable effects of higher generation.

Southeast — Commodity margin in our Southeast segment increased 25% for the year ended December 31, 2007, compared to the same period in the prior year. The increase can be partially attributed to a 6% increase in generation in 2007 compared to 2006 resulting from warmer temperatures, particularly in the third quarter, which led to increased demand and more favorable pricing conditions. The increased generation occurred although we had a 12% decrease in average total MW in operation in 2007 compared to 2006 due to the sale of our Aries Power Plant in January 2007 and Acadia Energy Center in September 2007. Our average capacity factor, excluding peakers, increased to 25.5% in 2007 from 20.9% in 2006. The increase in commodity margin was also the result of higher average open market spark spreads and higher capacity revenues in 2007.

North — Commodity margin in our North segment decreased by 10% in 2007 compared to 2006 primarily due to a 19% decrease in generation as our average total MW in operation and average availability decreased by 16% and 7%, respectively, for the year ended December 31, 2007, compared to the same period in the prior year. The decrease in total MW in operation resulted from the sale of our Dighton Power Plant in October 2006 and our Parlin Power Plant in July 2007 as well as the rejection of the Rumford and Tiverton power plant operating leases in June 2006. The sale or disposition of these assets also led to a reduction in capacity revenues in 2007.

 

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RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2006 AND 2005

Set forth below are the results of operations for the year ended December 31, 2006, as compared to the same period in 2005 (in millions, except for unit pricing information and percentages); 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 in the “$ Change” and “% Change” columns.

 

     Years Ended December 31,              
     2006     2005     $ Change     % Change  
     (in millions)  

Operating revenues

   $         6,937     $       10,302     $       (3,365)     (33 )%

Cost of revenue:

        

Fuel and purchased energy expenses

     4,752       8,318       3,566     43  

Plant operating expense

     750       717       (33 )   (5 )

Depreciation and amortization

     470       506       36     7  

Operating plant impairments

     53       2,413       2,360     98  

Other cost of revenue

     172       293       121     41  
                          

Gross profit (loss)

     740       (1,945 )     2,685     #  
Equipment, development project and other impairments      65       2,117       2,052     97  

Sales, general and other administrative expense

     175       240       65     27  

Other operating expenses

     36       69       33     48  
                          

Income (loss) from operations

     464       (4,371 )     4,835     #  

Interest expense

     1,254       1,397       143     10  

Interest (income)

     (79 )     (84 )     (5 )   (6 )

Loss (income) from various repurchases of debt

     18       (203 )     (221 )   #  

Minority interest expense

     5       43       38     88  

Other (income) expense, net

     (5 )     72       77     #  
                          

Loss before reorganization items, income taxes and discontinued operations

     (729 )     (5,596 )     4,867     87  

Reorganization items

     972       5,026       4,054     81  
                          

Loss before income taxes and discontinued operations

     (1,701 )     (10,622 )     8,921     84  

Provision (benefit) for income taxes

     64       (741 )     (805 )   #  
                          

Loss before discontinued operations

     (1,765 )     (9,881 )     8,116     82  
Discontinued operations, net of tax provision of $— and $132            (58 )     58     #  
                          

Net loss

   $ (1,765 )   $ (9,939 )   $ 8,174     82  
                          

 

 

# Variance of 100% or greater

Operating revenues decreased as a result of a 5% decrease in generation as well as a 15% decrease in the average realized electric price for the year ended December 31, 2006, compared to the same period in 2005, and a 66% decrease in hedging and optimization revenues year over year. Our hedging and optimization activity was curtailed in 2006 as compared to 2005 due to limitations on our ability to conduct such activities as a result of reduced availability of credit and the termination or disruption of certain customer relationships following our Chapter 11 filings. The decrease related to pricing was generally the result of declining gas prices resulting in a corresponding decrease in power prices.

 

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Fuel and purchased energy expenses decreased due to lower generation and a 28% decrease in the average cost of natural gas consumed for the year ended December 31, 2006, compared to the year ended December 31, 2005. Also contributing to the decrease was lower hedging and optimization expenses due to the lower level of such activity in 2006 compared to 2005.

Plant operating expense increased primarily due to $48 million of higher major maintenance expense, including equipment failure costs and losses on the retirement of scrap parts related to outages. This unfavorable variance was partially offset by regular operations and maintenance costs, which were favorable by $13 million due largely to lower information systems and insurance costs.

Depreciation and amortization expense decreased primarily due to a $79 million decrease in depreciation resulting from the $2.4 billion impairment of certain operating plants in the fourth quarter of 2005, as well as $17 million related to the deconsolidation of our Canadian and other foreign subsidiaries as of the Petition Date. The favorable variance was partially offset by increases of $15 million related to the consolidation of Acadia PP, $19 million related to the purchase of the Geysers Assets in the first quarter of 2006, $9 million related to Pastoria Energy Facility Phase I and II achieving commercial operation in the second and third quarters of 2005, respectively, $6 million related to achieving commercial operation of the auxiliary boilers at the Freeport Energy Center in the first quarter of 2006 and the Mankato Power Plant achieving commercial operation in the third quarter of 2006, and $6 million related to Metcalf Energy Center achieving commercial operation in the second quarter of 2005.

During 2006, we recorded operating plant impairment charges of $53 million primarily related to the sale of the Fox Energy Center. During 2005, we recorded $2.4 billion of impairment charges resulting from the impairment evaluation of our operating plants in connection with our Chapter 11 filings. We recorded operating plant impairments resulting generally from our determination that the likelihood of sale or other disposition had increased.

Other cost of revenue decreased primarily due to (i) the non-recurrence of prior period transaction costs of $20 million associated with a derivative contract at our Deer Park Energy Center, (ii) a decrease of $43 million resulting from the deconsolidation of TTS and certain Canadian subsidiaries as of the Petition Date, (iii) a decrease of $39 million in operating lease expense primarily due to the purchase of the Geysers Assets and the termination of the related facility operating leases in the first quarter of 2006 and the rejection of the Rumford and Tiverton power plant leases in the first half of 2006 and (iv) a decrease of $12 million due to the termination of our construction management agreement at Greenfield Energy Centre during 2006.

During 2006, we recorded equipment, development project, and other impairment charges of $65 million primarily related to certain turbine-generator equipment not assigned to projects for which we determined near-term sales were likely. During 2005, we recorded $2.1 billion of impairment charges resulting from the impairment evaluation of our construction and development projects, joint venture investments and certain notes receivable performed in connection with our Chapter 11 filings.

Sales, general and other administrative expense decreased primarily related to the net reduction in personnel costs of $34 million resulting from lower headcount for the year ended December 31, 2006, compared to the year ended December 31, 2005. In addition, legal fees decreased by $31 million over the prior year related primarily to fees incurred in 2005 in connection with liquidity problems and other litigation matters prior to our Chapter 11 filings.

Other operating expenses decreased primarily as a result of the non-recurrence of charges of $34 million related to the cancellation of 12 LTSAs with GE recorded during 2005.

Interest expense decreased during 2006, as compared to 2005, due to a decrease of $470 million related to discontinuing the accrual of interest expense related to debt instruments reclassified to LSTC, other than certain

 

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debt classified as LSTC on which interest was accrued in accordance with U.S. Bankruptcy Court orders, primarily the Second Priority Debt on which we continued to make adequate protection payments. The favorable variance was also due to a decrease of $47 million related to the repayment of the remaining $646 million outstanding balance on our First Priority Notes in the second quarter of 2006. These favorable variances were partially offset by a reduction in capitalized interest of $170 million related to certain power plants entering commercial operations and project development activities winding down and increases of (i) $77 million related to the effect of prior year interest expense reclassified to discontinued operations, (ii) $50 million related to higher interest rates and additional draws on the CalGen Secured Debt, and (iii) $75 million in interest on borrowings under the DIP Facility during 2006.

During 2006, we recognized a loss of $18 million on the repurchase of the First Priority Notes. During 2005, we recorded an aggregate gain of $203 million primarily related to the repurchase of $917 million aggregate principal amount of senior notes.

Minority interest expense decreased due to the deconsolidation of our Canadian and other foreign subsidiaries in December 2005.

The favorable variance of $77 million in other (income) expense, net was due in part to a $6 million distribution received in 2006 from the AELLC bankruptcy estate, gains in 2006 of $6 million related to the sale of auxiliary boilers, and a $3 million increase in the sale of emission reduction credits and allowances in 2006 over the same period a year ago. Also, during 2005, we recorded a $15 million foreign exchange loss, primarily on intercompany loans with our Canadian and other foreign subsidiaries. This foreign exchange loss did not recur in 2006 following the write-off of the loans at the time of our Chapter 11 and CCAA filings on the Petition Date. Also included in 2005 were $17 million of increased expenses related to letter of credit fees, a $19 million loss related to the sale of our investment in Gray’s Ferry in June 2005, $10 million of increased legal reserves, which included $5 million related to an arbitration claim involving Auburndale PP, and a $6 million write-off of unamortized deferred financing costs due to the refinancing of the Metcalf construction loan.

The table below lists the significant items within reorganization items for the years ended December 31, 2006 and 2005.

 

     Years Ended December 31,             
     2006     2005    $ Change     % Change  
     (in millions)  

Provision for expected allowed claims

   $             845     $          3,931    $          3,086     79 %

Gains on asset sales

     (106 )          106                     —  

DIP Facility financing costs

     39            (39 )    

Interest (income) on accumulated cash

     (25 )          25      

Professional fees

     153       36      (117 )   #  
Impairment of investment in Canadian subsidiaries            879      879     #  
Write-off of deferred financing costs and debt discounts            148      148     #  

Other

     66       32      (34 )   #  
                         

Total reorganization items

   $ 972     $ 5,026    $ 4,054     81  
                         

 

 

# Variance of 100% or greater

Provision for Expected Allowed Claims — During the year ended December 31, 2006, our provision for expected allowed claims related primarily to repudiated gas transportation and power transmission contracts, the rejection of the Rumford and Tiverton power plant leases, the write-off of prepaid lease expense and certain fees

 

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and expenses related to the transaction and a claim resulting from Calpine Corporation’s guarantee related to CES-Canada’s repudiation of its tolling contract with Calgary Energy Centre. During 2005, we recorded a provision for expected allowed claims related to U.S. Debtor guarantees of debt issued by certain of our deconsolidated Canadian entities. Some of the guarantee exposures are redundant; however, we determined the duplicative guarantees were probable of being allowed into the claim pool by the U.S. Bankruptcy Court.

Gains on Asset Sales — During the year ended December 31, 2006, gains on asset sales primarily resulted from the sale of the Dighton Power Plant and Fox Energy Center. See Note 7 of the Notes to Consolidated Financial Statements for further information.

DIP Facility Financing Costs — During the year ended December 31, 2006, we recorded costs related to the closing of our Original DIP Facility.

Professional Fees — The increase in professional fees for the year ended December 31, 2006, over the comparable period in 2005 resulted primarily from a full year of activity of our third party advisors in 2006.

Impairment of Investment in Canadian Subsidiaries — During the year ended December 31, 2005, we recorded the impairment of our investment in Canadian and other foreign subsidiaries upon their deconsolidation as of the Petition Date.

Write-off of Deferred Financing Costs and Debt Discounts — During the year ended December 31, 2005, all deferred financing costs, discounts and premiums related to debt that was reclassified as LSTC were written off.

Other — During the year ended December 31, 2006, other reorganization items consisted primarily of employee severance and incentive costs and foreign exchange losses on LSTC denominated in a foreign currency and governed by foreign law. During the year ended December 31, 2005, other reorganization items consisted primarily of non-cash charges related to certain interest rate swaps that no longer met the hedge criteria as a result of our payment default or expected payment default on the underlying debt instruments due to our Chapter 11 filings.

Provision (benefit) for income taxes — During the year ended December 31, 2006, we recorded tax expense of $64 million, primarily related to recording valuation allowances against our deferred tax assets compared to recording a deferred tax benefit of $741 million for the year ended December 31, 2005.

Consolidated Commodity Margin

The following table reconciles our commodity margin to our GAAP results for the years ended December 31, 2006 and 2005 (in millions).

 

     2006     2005  

Operating revenues

   $           6,937     $         10,302  

(Less): Other service revenues

     (73 )     (143 )

(Less): Fuel and purchased energy expenses

     (4,752 )     (8,318 )

Adjustment to remove: Mark-to-market activity, net(1)

     (91 )     (11 )
                

Consolidated commodity margin

   $ 2,021     $ 1,830  
                

 

 

(1) Included in operating revenues and fuel and purchased energy expenses.

Our consolidated commodity margin increased by $191 million, or 10%, for the year ended December 31, 2006, compared to the year ended December 31, 2005. The convergence of several factors contributed to the

 

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improvement in our consolidated commodity margin: (i) favorable weather patterns; (ii) the termination of certain marginally priced PPAs and (iii) the short gas position created from our portfolio of fixed-price power contracts, which benefited due to the decline in gas prices in 2006 compared to 2005.

Commodity Margin by Segment

 

     2006     2005     $ Change    % Change  
     (in millions)  

West

   $          1,037     $          1,072     $            (35)    (3 )%

Texas

     477       391       86    22  

Southeast

     215       149       66    44  

North

     313       276       37    13  

Other

     (21 )     (58 )     37    64  
                         

Consolidated commodity margin

   $ 2,021     $ 1,830     $ 191                    10  
                         

Commodity margin increased in our Texas, Southeast and North segments for the year ended December 31, 2006, compared to the year ended December 31, 2005, largely resulting from favorable weather patterns in these regions as opposed to a slight decrease in commodity margin in our West segment which experienced milder than normal weather and strong hydroelectric generation in the first half of 2006, which together lessened demand for gas-fired generation.

West — Commodity margin in our West segment decreased by 3% for the year ended December 31, 2006, compared to the year ended December 31, 2005, largely due to milder weather and increased hydroelectric production in the Pacific Northwest resulting from unseasonably high rainfall and snowmelt in the first half of 2006. Our average capacity factor decreased in our West segment to 58.7% in 2006 from 62.8% in 2005 due partly to unplanned outages occurring in 2006. Also contributing to the decrease was lower hedging and optimization activity in 2006 compared to 2005 resulting from our Chapter 11 filings in December of 2005. Partially offsetting the negative impacts to commodity margin was unseasonably hot weather in the third quarter of 2006 which lead to average spot market commodity margins that were at or near five-year highs.

Texas — Commodity margin in our Texas segment increased by $86 million, or 22%, due to warmer temperatures for the year ended December 31, 2006, compared to the same period a year ago. We experienced warmer than normal temperatures during 2006, particularly in the third quarter where unseasonably hot weather combined with tight reserve margins to produce average spot market commodity margins that were at or near five-year highs. Partially offsetting the increase was a decrease in our average capacity factor in 2006 to 41.7% from 50.0% in 2005 primarily due to unplanned outages at several of our power plants in Texas in 2006. The decrease in our average capacity factor also contributed to a 16% decrease in generation in 2006 compared to 2005.

Southeast — Commodity margin in our Southeast segment increased by $66 million, or 44%, for the year ended December 31, 2006, compared to the same period in 2005. The increase can be attributed to a 39% increase in generation in 2006 compared to 2005 resulting from warmer temperatures and more favorable pricing conditions as our average cost of natural gas decreased. Our average capacity factor, excluding peakers, increased to 20.9% in 2006 from 16.9% in 2005.

North — Commodity margin in our North segment increased $37 million, or 13%, in 2006, compared to 2005 as we reduced generation at certain of our power plants with unfavorable pricing in this region following our Chapter 11 filings. Generation in our North segment decreased by 32% in 2006 compared to 2005. Prior to our Chapter 11 filings, we were required to run certain power plants in our North segment under contracts which contained pricing features that did not allow us to fully recover our costs to operate the facilities. After our Chapter 11 filings, we rejected the leases of the Rumford and Tiverton power plants in June 2006 and sold our Dighton Power Plant in October 2006.

 

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NON-GAAP FINANCIAL MEASURES

Management’s Discussion and Analysis of Financial Condition and Results of Operations includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures, such as commodity margin, as discussed in “— Executive Overview.” See “— Results of Operations for the Years Ended December 31, 2007 and 2006 — Consolidated Commodity Margin” and “— Results of Operations for the Years Ended December 31, 2006 and 2005 — Consolidated Commodity Margin” for a reconciliation of commodity margin to our GAAP results. In addition, our management utilizes another non-GAAP financial measure, Adjusted EBITDA, as a measure of our liquidity and performance. Generally, a non-GAAP financial measure is a numerical measure of financial performance, financial position or cash flows that exclude (or include) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP.

We define Adjusted EBITDA as EBITDA as adjusted for certain items described below and presented in the accompanying reconciliation. Adjusted EBITDA is not a measure calculated in accordance with GAAP, and should be viewed as a supplement to and not a substitute for our results of operations presented in accordance with GAAP. Adjusted EBITDA does not purport to represent cash flow from operations or net income (loss) as defined by GAAP as an indicator of operating performance. Furthermore, Adjusted EBITDA is not necessarily comparable to similarly-titled measures reported by other companies.

We believe Adjusted EBITDA is used by and useful to investors and other users of our financial statements in analyzing our liquidity as it is the basis for material covenants under our DIP Facility which was our primary source of financing during our Chapter 11 cases. Under the DIP Facility, we are required to maintain certain levels of Adjusted EBITDA (called “Consolidated EBITDA” in the DIP Facility) on a rolling 12 month basis and as of certain points in time. Additionally, under the Exit Facilities, we are required not to exceed a consolidated leverage ratio calculated by dividing total net debt by Consolidated EBITDA (as defined in the Exit Facilities), and must also comply with (i) a minimum ratio of Consolidated EBITDA to cash interest expense and (ii) a maximum ratio of total senior net debt to Consolidated EBITDA. Non-compliance with these covenants could result in the lenders requiring us to immediately repay all amounts borrowed. In addition, if we cannot satisfy these financial covenants, we may be prohibited from engaging in other activities, such as incurring additional indebtedness and making restricted payments.

We also believe Adjusted EBITDA is used by and is useful to investors and other users of our financial statements in evaluating our operating performance because it provides them with an additional tool to compare business performance across companies and across periods. We believe that EBITDA is widely used by investors to measure a company’s operating performance without regard to items such as interest expense, taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired.

Additionally, we believe that investors commonly adjust EBITDA information to eliminate the effect of restructuring and other expenses, which vary widely from company to company and impair comparability. As we define it, Adjusted EBITDA excludes the impact of reorganization items and impairment charges, among other items as detailed in the below reconciliation. We have recognized substantial reorganization items, both direct and incremental, in connection with our Chapter 11 cases as well as substantial asset impairment charges related to our Chapter 11 filings and actions we have taken with respect to our portfolio of assets in connection with our reorganization efforts. These reorganization items and impairment charges are not expected to continue at these levels following our emergence from Chapter 11, but rather are expected to be reduced over time in the periods following our emergence. Therefore, we exclude reorganization items and impairment charges from Adjusted EBITDA as our management believes that these items would distort their ability to efficiently view and assess our core operating trends.

Our management uses Adjusted EBITDA (i) as a measure of liquidity in determining our ability to maintain borrowings under the Exit Facilities, (ii) as a measure of operating performance to assist in comparing

 

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performance from period to period on a consistent basis and to readily view operating trends; (iii) as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations; and (iv) in communications with our Board of Directors, shareholders, creditors, analysts and investors concerning our financial performance.

The below table provides a reconciliation of Adjusted EBITDA to our cash flow from operations and GAAP net income (loss):

 

     Years Ended December 31,  
     2007     2006     2005  
     (in millions)  

Cash provided by (used in) operating activities

   $ 182     $ 156     $ (708 )

Less:

      

Changes in operating assets and liabilities, excluding the effects of acquisition

     686       259       (332 )

Additional adjustments to reconcile GAAP net loss to net cash provided by (used in) operating activities from both continuing and discontinued operations:

      

Depreciation and amortization expense(1)

     554       585       760  

Deferred income taxes

     (517 )     22       (610 )

Mark-to-market activity, net

     13       (99 )     (11 )

Non-cash reorganization items

     (3,342 )     807       5,013  

Impairment charges and other

     95       347       4,411  
                        

GAAP net income (loss)

     2,693       (1,765 )     (9,939 )

Less: Loss from discontinued operations

                 (58 )
                        

Net income (loss) from continuing operations

     2,693       (1,765 )     (9,881 )

Add:

      

Adjustments to reconcile Adjusted EBITDA to net income (loss) from continuing operations:

      

Interest expense, net of interest income

     1,955       1,175       1,313  

Depreciation and amortization expense, excluding deferred financing costs(1)

     507       522       558  

Income tax provision (benefit)

     (546 )     64       (741 )

Impairment charges

     46       118       4,530  

Reorganization items

     (3,258 )     972       5,026  

Major maintenance expense

     98       77       70  

Operating lease expense

     54       66       105  

Loss (income) on various repurchases of debt

           18       (203 )

(Gains) losses on derivatives

     2       (213 )     52  

(Gains) losses on sales of assets and contract restructuring, excluding reorganization items

     (7 )     (6 )     18  

Claim settlement income

     (135 )            

Other

     3       1       80  
                        

Adjusted EBITDA

   $             1,412     $             1,029     $             927  
                        

 

 

(1) Depreciation and amortization in the GAAP net income (loss) calculation on our Consolidated Statements of Operations excludes amortization of other assets and amounts classified as sales, general and other administrative expenses.

 

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OPERATING PERFORMANCE METRICS

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

 

   

Total MWh generated. We generate power that we sell to third parties. The volume in MWh is a direct indicator of our level of electricity generation activity.

 

   

Average availability and average capacity factor, excluding peakers. 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 average capacity factor, excluding peakers 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 capacity factor, excluding peakers 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 average capacity factor, excluding peakers will reflect that decision as well as both scheduled and unscheduled outages due to maintenance and repair requirements.

 

   

Steam adjusted Heat Rate for gas-fired fleet of power plants expressed in Btus of fuel consumed per KWh generated. We calculate the steam adjusted Heat Rate for our gas-fired power plants (excluding peakers) by dividing (a) fuel consumed in Btu by (b) KWh generated. 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. The resultant steam adjusted Heat Rate is a measure of fuel efficiency, so the lower the steam adjusted Heat Rate, the lower our cost of generation.

 

   

Average realized electric price expressed in dollars per MWh generated. Our energy trading and optimization activities are integral to our power generation business and directly impact our total realized revenues from generation. Accordingly, we calculate the average realized electric price per MWh generated by dividing (a) adjusted electricity and steam revenue, which includes capacity revenues, energy revenues, thermal revenues, the spread on sales of purchased electricity for hedging, balancing, and optimization activity by (b) total generated MWh in the period.

 

   

Average cost of natural gas expressed in dollars per MMBtu of fuel consumed. Our energy trading 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 and the spread on sales of purchased gas for hedging, balancing, and optimization activity, by (b) the heat content in millions of Btu of the fuel we consumed in our power plants for the period.

 

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

 

     Years Ended December 31,  
     2007     2006     2005  
     (in thousands, except percentages,  
     Heat Rate, price and cost information)  

Total MWh generated

     90,811     83,146       87,431  

West

     36,837     34,567       33,949  

Texas

     33,154     27,169       32,536  

Southeast

     14,795     13,954       10,031  

North

     6,025     7,456       10,915  

Average Availability

     90.8 %   91.3 %     91.5 %

West

     90.8 %   91.6 %     90.0 %

Texas

     90.8 %   88.6 %     89.0 %

Southeast

     92.1 %   92.6 %     92.8 %

North

     87.4 %   93.7 %     95.1 %

Average total MW in operation

     24,755     26,785       25,207  

West

     7,281     7,608       7,027  

Texas

     7,266     7,430       7,430  

Southeast

     7,222     8,184       7,279  

North

     2,986     3,563       3,471  

Average MW of peaker facilities

     3,014     2,965       2,965  

West

     983     983       983  

Texas

                

Southeast

     963     963       963  

North

     1,068     1,019       1,019  

Average capacity factor, excluding peakers

     46.6 %   39.2 %     43.9 %

West

     65.3 %   58.7 %     62.8 %

Texas

     52.1 %   41.7 %     50.0 %

Southeast

     25.5 %   20.9 %     16.9 %

North

     33.6 %   32.3 %     48.5 %

Steam adjusted Heat Rate

     7,184     7,223       7,187  

West

     7,336     7,321       7,300  

Texas

     6,830     6,878       6,955  

Southeast

     7,511     7,579       7,476  

North

     7,646     7,486       7,359  

Average realized electric price

   $         67.90     $        63.02     $         74.46  

Average cost of natural gas per MMBtu

   $ 6.45     $          5.70     $ 7.89  

LIQUIDITY AND CAPITAL RESOURCES

Our business is capital intensive. Our ability to successfully implement our business plan, including operating our current fleet of power plants, 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, as well as exploring potential growth opportunities, is dependent on the continued availability of capital on attractive terms. As described below, upon implementation of our Plan of Reorganization and emergence from Chapter 11, we converted our existing DIP Facility into exit financing under our Exit Facilities, which, including the term loans funded, provide approximately $7.3 billion of term and revolving credit.

 

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We currently obtain cash from our operations, borrowings under credit facilities including the Exit Facilities, project financings and refinancings. In the past, we have also obtained cash from issuances of securities, proceeds from sale/leaseback transactions, contract monetizations, and sale or partial sale of certain assets. We or our subsidiaries may in the future complete similar transactions consistent with achieving the objectives of our business plan. We utilize this cash to fund our operations, service or prepay debt obligations, fund acquisitions, develop and construct power generation facilities, finance capital expenditures, support our hedging, balancing and optimization activities, and meet our other cash and liquidity needs. We reinvest any cash from operations into our business or use it to reduce or pay interest on our debt, rather than to pay cash dividends. We do not intend to pay any cash dividends on our common stock in the foreseeable future because of our ongoing liquidity constraints and the needs of our business operations. In addition, our ability to pay cash dividends is restricted under the Exit Facilities and certain of 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.

In order to improve our liquidity position, maximize our core strategic assets in the markets in which we operate and control our business growth, we have taken steps to stabilize, improve and strengthen our power generation business and our financial health by reducing activities and curtailing expenditures in certain non-core areas. We expect to continue our efforts to reduce overhead and discontinue activities that do not have compelling profit potential or otherwise do not constitute a strategic fit with our core business of generating and selling electricity and electricity-related products. Our development activities have been reduced, and we have only one project, Russell City Energy Center, currently in active development. We have interests in two projects, Otay Mesa Energy Center and Greenfield Energy Centre, currently under construction. We continue to review our other development opportunities, which we have put on hold, to determine what actions we should take. We may pursue new opportunities that arise, particularly if power contracts and financing are available and attractive returns are expected. We have completed the sale of certain of our power plants or other assets, and expect that, as a result of our ongoing review process, additional power plants or other assets may be sold, the agreements relating to certain of our facilities may be restructured, or commercial operations may be suspended at certain of our power plants. See Note 7 of the Notes to Consolidated Financial Statements and “— Asset Sales and Purchase” below for further details.

Ultimately, whether we will have sufficient liquidity from cash flow from operations, borrowings available under our existing debt facilities and project financings, as well as proceeds from other activities such as asset sales, sufficient to fund our operations, including anticipated capital expenditures and working capital requirements, as well as to satisfy our current obligations under our outstanding indebtedness 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 the discussion of forward-looking statements in Item 1. “Business” and the risk factors included in Item 1A. “Risk Factors.”

We believe the actions we have taken, including the implementation of our Plan of Reorganization, the execution of our Exit Facilities, reducing activities in certain non-core areas and disposing of certain underperforming assets, will allow us to generate sufficient resources to support our operations over the next 12 months. Our ability to generate sufficient resources is dependent upon, among other things: (i) improving the profitability of our operations; (ii) complying with the covenants related to our Exit Facilities and other existing financing obligations; (iii) developing a long-term strategy focused on projects that fit our core business; and (iv) stabilizing and increasing future contractual cash flows.

DIP Facility — As of December 31, 2007, our primary debt facility was the DIP Facility. The DIP Facility consisted of a $4.0 billion first priority senior secured term loan and a $1.0 billion first priority senior secured revolving credit facility together with an uncommitted term loan facility that permitted us to raise up to $2.0 billion of incremental term loan funding on a senior secured basis with the same priority as the current debt under the DIP Facility. In addition, under the DIP Facility, the U.S. Debtors had the ability to provide liens to

 

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counterparties to secure obligations arising under certain hedging agreements. The DIP Facility was priced at LIBOR plus 2.25% or base rate plus 1.25% and matured upon the Effective Date, when the loans and commitments under the DIP Facility were converted to loans and commitments under our Exit Facilities. Due to the conversion of the loans under the DIP Facility to loans under our Exit Facilities and our emergence from Chapter 11 prior to the issuance of our Consolidated Financial Statements for the year ended December 31, 2007, the borrowings under the DIP Facility were classified as non-current at December 31, 2007. Amounts drawn under the DIP Facility had been applied on March 29, 2007, to the repayment of a portion of the approximately $2.5 billion outstanding principal amount of CalGen Secured Debt, and to the refinancing of our Original DIP Facility. Borrowings under the Original DIP Facility had been used to repay a portion of the First Priority Notes and to pay a portion of the purchase price for the Geysers Assets, as well as to fund our operational needs.

As of December 31, 2007, under the DIP Facility there was approximately $4.0 billion outstanding under the term loan facility, no borrowings outstanding under the revolving credit facility and $235 million of letters of credit issued against the revolving credit facility.

Exit Facilities — Upon our emergence from Chapter 11, we converted the loans and commitments outstanding under our $5.0 billion DIP Facility into loans and commitments under our approximately $7.3 billion of Exit Facilities. The Exit Facilities provide for approximately $2.0 billion in senior secured term loans and $300 million in senior secured bridge loans in addition to the loans and commitments that had been available under the DIP Facility. The facilities under the Exit Facilities include:

The Exit Credit Facility, comprising:

 

   

approximately $6.0 billion of senior secured term loans;

 

   

a $1.0 billion senior secured revolving facility; and

 

   

ability to raise up to $2.0 billion of incremental term loans available on a senior secured basis in order to refinance secured debt of subsidiaries under an “accordion” provision.

The Bridge Facility, comprising:

 

   

a $300 million senior secured bridge term loan.

In addition, under the Exit Facilities, we continue to have the ability to provide liens to counterparties to secure obligations arising under certain hedging agreements.

The approximately $6.0 billion of senior secured term loans and the $300 million senior secured bridge facility were fully drawn on the Effective Date. The proceeds of the drawdowns, above the amounts that had been applied under the DIP Facility as described above, were used to repay a portion of the Second Priority Debt, fund distributions under the Plan of Reorganization to holders of other secured claims and to pay fees, costs, commissions and expenses in connection with the Exit Facilities and the implementation of our Plan of Reorganization. Term loan borrowings under the Exit Facilities bear interest at a floating rate of, at our option, LIBOR plus 2.875% per annum or base rate plus 1.875% per annum. Borrowings under the Exit Credit Facility term loan facility requires quarterly payments of principal equal to 0.25% of the original principal amount of the term loan, with the remaining unpaid amount due and payable at maturity on March 29, 2014. Borrowings under the Bridge Facility mature 366 days after the Effective Date.

The obligations under the Exit Facilities are unconditionally guaranteed by certain of our direct and indirect domestic subsidiaries and are secured by a security interest in substantially all of the tangible and intangible assets of Calpine Corporation and the guarantors. The obligations under the Exit Facilities are also secured by a pledge of the equity interests of the direct subsidiaries of each guarantor, subject to certain

 

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exceptions, including exceptions for equity interests in foreign subsidiaries, existing contractual prohibitions and prohibitions under other legal requirements.

The Exit Facilities contain restrictions, including limiting our ability to, among other things: (i) incur additional indebtedness and use of proceeds from the issuance of stock; (ii) make prepayments on or purchase indebtedness in whole or in part; (iii) pay dividends and other distributions with respect to our stock or repurchase our stock or make other restricted payments; (iv) use money borrowed under the Exit Facilities for non-guarantors (including foreign subsidiaries); (v) make certain investments; (vi) create or incur liens to secure debt; (vii) consolidate or merge with another entity, or allow one of our subsidiaries to do so; (viii) lease, transfer or sell assets and use proceeds of permitted asset leases, transfers or sales; (ix) limit dividends or other distributions from certain subsidiaries up to Calpine; (x) make capital expenditures beyond specified limits; (xi) engage in certain business activities; and (xii) acquire facilities or other businesses.

The Exit Facilities also require compliance with financial covenants that include (i) a maximum ratio of total net debt to Consolidated EBITDA (as defined in the Exit Facilities), (ii) a minimum ratio of Consolidated EBITDA to cash interest expense and (iii) a maximum ratio of total senior net debt to Consolidated EBITDA.

Cash Management — During the pendency of our Chapter 11 cases, we were permitted to continue to manage our cash in accordance with our pre-Petition Date intercompany cash management system, subject to the requirements of the DIP Facility, the Cash Collateral Order and the 345(b) Waiver Order, as well as the ongoing oversight of the U.S. Bankruptcy Court. With our emergence from Chapter 11 on the Effective Date, we continue to manage our cash in accordance with our intercompany cash management system, subject now only to the requirements of our Exit Facilities. Pursuant to this system, we maintain our bank and other investment accounts and manage our cash on an integrated basis through Calpine Corporation. Pursuant to the cash management system, and in accordance with the Exit Facilities, intercompany transfers are generally recorded as intercompany loans.

During the pendency of our Chapter 11 cases, in lieu of distributions, our U.S. Debtor subsidiaries were permitted under the terms of the Cash Collateral Order to make transfers from their excess cash flow in the form of loans to other U.S. Debtors, notwithstanding the existence of any default or event of default related to our Chapter 11 cases.

Capital Spending and Project Financing — We have one consolidated project (Russell City Energy Center) in active development. We currently are in discussions with PG&E to amend the terms and conditions under which this project will be constructed and operated. Construction is anticipated to begin once all permits and other required approvals are final and non-appealable, and project financing has closed. Upon completion, this project would bring on line approximately 362 MW of net interest baseload capacity (390 MW with peaking capacity) representing our 65% share. We expect to fund the costs to complete under project financing facilities.

We hold interests in two unconsolidated projects under construction at December 31, 2007. Greenfield Energy Centre, which is expected to come on line in 2008 and Otay Mesa Energy Center, which is expected to come on line in 2009. The completion of these projects will bring on line approximately 898 MW of net interest baseload capacity (1,099 MW with peaking capacity) representing our proportionate share of these projects. The projected cost to complete these projects is $376 million, which we are funding under separate project financing facilities. See “ Off Balance Sheet Commitments of Unconsolidated Subsidiaries” below.

 

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

 

     Years Ended December 31,  
     2007    2006    2005  
     (in millions)  

Beginning cash and cash equivalents

   $          1,077    $             786    $             718  
                      

Net cash provided by (used in):

        

Operating activities

   $ 182    $ 156    $ (708 )

Investing activities

     478      14      917  

Financing activities

     178      121      (160 )
                      

Net increase in cash and cash equivalents including discontinued operations cash

   $ 838    $ 291    $ 49  
Change in discontinued operations cash classified as assets held for sale                19  
                      

Net increase in cash and cash equivalents

   $ 838    $ 291    $ 68  
                      

Ending cash and cash equivalents

   $ 1,915    $ 1,077    $ 786  
                      

2007 – 2006

Cash flows from operating activities for the year ended December 31, 2007, increased $26 million as compared to 2006. The net income for the year ended December 31, 2007, adjusted for non-cash operating items (mainly depreciation, amortization, operating plant impairments, deferred income taxes and reorganization items) decreased by $401 million, resulting in net outflows of $504 million, compared to outflows of $103 million in 2006. Offsetting these outflows was an increase in cash flows from changes in operating assets and liabilities of $427 million, primarily due to an increase in accounts payable, LSTC and accrued expenses for the year ended December 31, 2007, as compared to 2006. The increase in accounts payable, LSTC and accrued expenses is primarily a result of the settlement of outstanding claims in connection with our Chapter 11 cases. Partially offsetting these increases was an increase in accounts receivable, due to higher sales, and increases in margin deposits and gas prepayments due in part to higher generation and fuel consumption. Cash paid for interest increased by $164 million in 2007 to $1,143 million for the year ended December 31, 2007, as compared to $979 million in 2006, primarily due to additional adequate protection payments on our Second Priority Debt.

Cash flows from investing activities for the year ended December 31, 2007, increased $464 million as compared to 2006. The increase in cash flows from investing activities was largely the result of proceeds from asset sales in 2007 of $541 million compared to $275 million 2006. Please refer to Note 7 of the Notes to Consolidated Financial Statements for a list of assets sold during 2007. During the year ended December 31, 2007, we did not have any outflows of cash for the purchase of assets, as compared to outflows of $267 million in 2006 for the purchase of the Geysers Assets. Cash flows from investing activities also increased due to net inflows of $5 million from derivatives not designated as hedges during the year ended December 31, 2007, as compared to net outflows of $144 million in 2006. Additionally, investing cash flows increased during 2007 due to a $104 million return of investment in Greenfield LP, $75 million related to the Canadian Debtors, and a decrease of $16 million in capital expenditures to $196 million for the year ended December 31, 2007, as compared to $212 million in 2006. Net inflows during 2007 were offset by a $347 million decrease in the net reduction of restricted cash to $37 million for the year ended December 31, 2007, compared to $384 million for 2006. The decrease in restricted cash during the year ended December 31, 2006, was primarily due to the repayment of the First Priority Notes. Additionally, investing cash outflows included $68 million in advances to joint ventures compared to $59 million in 2006 and $29 million related to the 2007 deconsolidation of Otay Mesa.

Cash flows from financing activities for the year ended December 31, 2007, resulted in net inflows of $178 million, as compared to net inflows of $121 million in 2006. The primary sources of cash during the year

 

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ended December 31, 2007, were borrowings under the DIP Facility of $614 million, mainly used for working capital and other general corporate purposes, $151 million from the sale of bonds issues by ULC I that were held by us and $21 million from project financing. This compares to borrowings of $1.2 billion under the Original DIP Facility and $141 million from project financing in 2006. The primary uses of cash during the year ended December 31, 2007, were repayments of $224 million related to the CalGen financing, $135 million for notes payable and other lines of credit, $119 million for project financing and $38 million related to the DIP Facility. During 2006, our primary uses of cash included a $646 million non-recurring repayment related to the First Lien Senior Notes, $180 million for notes payable and other lines of credit, $179 million for the Original DIP Facility and $110 million for project borrowings. In addition, we paid financing fees of $81 million in 2007, primarily related to the DIP Facility, as compared to $39 million in 2006, related to the Original DIP Facility.

2006 – 2005

Cash flows from operating activities for the year ended December 31, 2006, increased $864 as compared to 2005. The increase in cash flows from operating activities was primarily driven by the improvement in gross profit net of non-cash adjustments (mainly for depreciation and amortization, as well as operating plant impairments), to $1.3 billion in 2006, as compared to $999 million in 2005. Also contributing to the increase in cash flows from operating activities were net inflows resulting from a decrease in margin deposits and gas and power prepayment balances supporting commodity transactions of $633 million due to the settlement of contracts and a decrease in commodity prices for the year ended December 31, 2006, as compared to net outflows of $35 million in 2005 resulting from higher commodity prices during that period. Uses of cash included interest payments of $979 million for the year ended December 31, 2006, as compared to $1.3 billion in 2005 resulting from the discontinuation of interest payments on debt classified as LSTC, other than certain debt for which interest was paid pursuant to U.S. Bankruptcy Court orders. Partially offsetting these increases in cash flows from operating activities was net cash paid for reorganization items, primarily professional fees, of $120 million during the year ended December 31, 2006, and changes in working capital items—accounts receivable and accounts payable, liabilities subject to compromise and accrued expenses—that generated net inflows of $130 million during the year ended December 31, 2006, as compared to net outflows of $154 million in 2005.

Cash flows from investing activities for the year ended December 31, 2006, decreased $903 million as compared to 2005. The decrease in cash flows from investing activities was largely the result of proceeds from asset sales in 2005 of $2.1 billion, primarily from the sale of our natural gas assets, Saltend facility and certain other power projects, as compared to $252 million in 2006, primarily from the sale of various combustion turbines and the Dighton Power Plant. Additional investing activities in 2005 reflect the receipt of $133 million from the disposition of our investment in HIGH TIDES III securities, offset by a $91 million decrease in cash due to the deconsolidation of our Canadian and foreign entities. Also contributing to the decrease in cash flows from investing activities was the purchase of the Geysers Assets from the owner lessor in 2006 which used $267 million in cash, and contributions of $59 million to our investment in Greenfield LP. Cash flow from investing activities also decreased due to net outflows of $144 million from derivatives not designated as hedges during the year ended December 31, 2006, as compared to net inflows of $103 million in 2005. Partially offsetting these decreases in cash flows from investing activities is the reduction in capital expenditures, including capitalized interest, for the completion of our power facilities from $784 million in 2005 to $212 million in 2006 as a result of the reduction of our development and construction activities since the Petition Date and a reduction (inflow) in restricted cash of $384 million for the year ended December 31, 2006, as compared to a net increase (outflow) of $536 million in 2005.

Cash flows from financing activities for the year ended December 31, 2006, provided net inflows of $121 million, as compared to net outflows of $160 million in the prior year. Sources of cash during the year ended December 31, 2006, were borrowings under the DIP Facility of $1.2 billion and project borrowings of $141 million used primarily to fund construction activities at the Freeport and Mankato power plants. During 2005, we received proceeds of $865 million from the issuance of redeemable preferred shares for Calpine Jersey II, Metcalf and CCFCP, $751 million from project borrowings, $650 million from the issuance of convertible senior

 

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notes, $264 million from a prepaid commodity derivative contract at our Deer Park facility and $31 million from other debt. Uses of cash during the year ended December 31, 2006, were repayments of $646 million for the First Priority Notes, $180 million for notes payable, $179 million for the DIP Facility, $110 million for project borrowings and $17 million for other debt. For 2005, we used $880 million to repay or repurchase Senior Notes, $779 million to repay preferred security offerings (including the Calpine Jersey II mentioned above), $518 million to repay HIGH TIDES III and $390 million to repay notes payable and project financing debt. In addition, we paid financing fees of $39 million in 2006, primarily related to the DIP Facility, as compared to $154 million in 2005.

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 Chapter 11 filings 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 of us by our trading counterparties and also reduced the number of trading counterparties currently willing 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 as a result of our Chapter 11 cases for some period following the Effective Date.

Letter of Credit Facilities — At December 31, 2007 and 2006, we had approximately $348 million and $264 million, respectively, in letters of credit outstanding under various credit facilities to support our risk management and other operational and construction activities. Subsequent to December 31, 2007, we entered into a letter of credit facility under which up to $150 million is available for letters of credit, subject to permitted uses as defined in the letter of credit facility agreement.

Commodity Margin Deposits and Other Credit Support — As of December 31, 2007 and 2006, to support commodity transactions, we had margin deposits with third parties of $314 million and $214 million, respectively; we had gas and power prepayment balances of $74 million and $114 million, respectively; and we had letters of credit outstanding of $55 million and $2 million, respectively. Counterparties had deposited with us $21 million and nil as margin deposits at December 31, 2007 and 2006, respectively. Also, counterparties had posted letters of credit to us of $18 million and $4 million at December 31, 2007 and 2006, respectively. In addition, we have granted additional first priority liens on the assets currently subject to first priority liens under the DIP Facility as collateral under certain of our power agreements, natural gas agreements and interest rate swap agreements that qualify as “eligible commodity hedge agreements” under the DIP Facility in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to the counterparties under such agreements. The counterparties under such agreements will share the benefits of the collateral subject to such first priority liens ratably with the lenders under the DIP Facility. As of December 31, 2007 and 2006, our net discounted exposure under the power and natural gas agreements collateralized by such first priority liens was approximately $22 million and nil, respectively, and our net discounted exposure under the interest rate swap agreements collateralized by such first priority liens was approximately $151 million and nil, respectively.

We use margin deposits, first priority liens (as discussed above), prepayments and letters of credit as credit support for commodity procurement and risk management activities. Future cash collateral and first priority lien 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.

 

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Asset Sales and Purchase — A significant component of our restructuring activities has been to return our focus to our core strategic assets and selectively dispose of certain less strategically important assets. As a result of the review of our asset portfolio, we sold or otherwise disposed of the following assets throughout our Chapter 11 cases during the years ended December 31, 2007 and 2006, and through the filing of this Report:

 

Asset

 

Transaction Description

 

Closing Date

 

Consideration

2008:

     

Fremont development project

  Sale of assets   Pending   $254 million

Hillabee development project

  Sale of assets   February 14, 2008   $156 million

RockGen Energy Center

  Purchase of assets   January 15, 2008   $145 million allowed unsecured claim

2007:

     

Acadia PP

  Sale of 50% equity interest   September 13, 2007   $104 million in cash, plus the payment of $85 million priority distributions due to Cleco

Parlin Power Plant

  Sale of assets   July 6, 2007   $3 million, plus the agreement to waive certain claims

PSM

  Sale of assets   March 22, 2007   $242 million

Goldendale Energy Center

  Sale of assets   February 21, 2007   $120 million

Aries Power Plant

  Sale of assets   January 16, 2007   $234 million(1)

2006:

     

Fox Energy Center

  Sale of leasehold interest   October 11, 2006   $16 million, plus the extinguishment of $352 million in debt

Dighton Power Plant

  Sale of assets   October 1, 2006   $90 million

TTS

  Sale of entire equity interest   September 28, 2006   $24 million

Rumford and Tiverton Power Plants

  Turnover to lenders   June 23, 2006   N/A

 

 

(1) As part of the sale we were also required to use a portion of the proceeds to repay approximately $159 million principal amount of financing obligations, $8 million in accrued interest, $11 million in accrued swap liabilities and $14 million in debt pre-payment and make whole premium fees to our project lenders.

See Note 7 of the Notes to Consolidated Financial Statements for further information related to these asset sales and purchase.

In addition, we have restructured agreements or reconfigured equipment at Clear Lake Power Plant, Hog Bayou Energy Center, Pine Bluff Energy Center, Santa Rosa Energy Center and Texas City Power Plant such that continued operation of the facilities is merited, although eventual sale remains a possibility.

Credit Considerations — Our Exit Facilities have been rated B+ by Standard and Poor’s and B2 by Moody’s Investors Service and our corporate rating has been rated B by Standard and Poor’s and B2 by Moody’s Investors Service as of the Effective Date.

Off Balance Sheet Commitments of Unconsolidated Subsidiaries — Our facility 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. 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

 

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those typically found in project finance debt instruments. We have no ownership or other interest in any of these special-purpose entities. See Note 15 of the Notes to Consolidated Financial Statements for the future minimum lease payments under our power plant operating leases.

The debt on the books of our unconsolidated investments is not reflected on our Consolidated Balance Sheets. As of December 31, 2007, our equity method investees (Greenfield LP and OMEC) had aggregate debt outstanding of $436 million. Based on our pro rata share of each of the investments, our share of such debt would be approximately $253 million. All such debt is non-recourse to us. As of December 31, 2006, our equity method investee (Greenfield LP) did not carry any debt and OMEC which was consolidated as of December 31, 2006, likewise carried no debt. See Note 5 of the Notes to Consolidated Financial Statements for additional information on our investments.

Commercial Commitments — Our primary commercial obligations as of December 31, 2007, are as follows (in millions):

 

     Amounts of Commitment Expiration per Period

Commercial Commitments

   2008    2009    2010    2011    2012    Thereafter    Total
Amounts
Committed

Guarantee of subsidiary debt(1)

   $       2,155    $           20    $           8    $           7    $           7    $         380    $       2,577

Standby letters of credit(2)(4)

     282      38           28                348

Surety bonds(3)(4)(5)

                              11      11
Guarantee of subsidiary operating lease payments(4)      17      18      17      74      12      235      373
                                                

Total

   $ 2,454    $ 76    $ 25    $ 109    $ 19    $ 626    $ 3,309
                                                

 

 

(1) Represents Calpine Corporation guarantees of certain project financings, facility operating leases and other miscellaneous debt. All of such guaranteed debt is recorded on our Consolidated Balance Sheets.

 

(2) The standby letters of credit disclosed above include those disclosed in Note 8.

 

(3) The majority of surety bonds do not have expiration or cancellation dates.

 

(4) These are off balance sheet obligations.

 

(5) As of December 31, 2007, $11 million of cash collateral is outstanding related to these bonds.

 

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Contractual Obligations — Our contractual obligations related to continuing operations as of December 31, 2007, are as follows (in millions):

 

    2008    2009    2010    2011   2012     Thereafter     Total

Total operating lease obligations(1)

  $         56    $         59    $         54    $         110   $         47   $         413   $         739
                                            

Debt not subject to compromise(2)

  $ 1,640    $ 947    $ 571    $ 1,867   $ 131   $ 6,431   $ 11,587
                                            

Liabilities subject to compromise(3)

  $ 8,788    $    $    $   $   $   $ 8,788
                                            
Interest payments on debt not subject to compromise   $ 832    $ 803    $ 702    $ 637   $ 532   $ 558   $ 4,064
                                            

Allowed post-petition interest(3)

  $ 347    $    $    $   $   $   $ 347
                                            

Interest rate swap agreement payments

  $ 53    $ 75    $ 30    $ 8   $ 3   $   $ 169
                                            

Purchase obligations:

                

Turbine commitments

                              

Commodity purchase obligations(4)

    2,023      893      706      567     398     4,233     8,820

Land leases

    6      6      7      6     7     356     388

Long-term service agreements

    17      15      17      5     8     31     93

Costs to complete construction projects(5)

    140      287      112      3             542

Other purchase obligations(6)

    92      92      109      109     49     1,063     1,514
                                            

Total purchase obligations(7)(8)

  $ 2,278    $ 1,293    $ 951    $ 690   $ 462   $ 5,683   $ 11,357
                                            

Liability for uncertain tax positions

  $ 96    $    $    $   $   $ 42   $ 138
                                            

Other contractual obligations

  $ 50    $ 6    $ 2    $   $   $ 66   $ 124
                                            

 

 

(1) Included in the total are future minimum payments for power plant operating leases, and office and equipment leases. See Note 15 of the Notes to Consolidated Financial Statements for more information.

 

(2) A note payable totaling $99 million associated with the sale of the PG&E note receivable to a third party is excluded from debt not subject to compromise for this purpose as it is a non-cash liability. Also included in debt not subject to compromise is $3.7 billion for the repayment of the Second Priority Debt using a combination of available cash and amounts drawn under the Exit Facilities.

 

(3) These liabilities were generally extinguished with cash or distribution of shares of reorganized Calpine Corporation common stock on or shortly after the Effective Date.

 

(4) 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 Sheets. See “— Financial Market Risks” for a discussion of our commodity derivative contracts recorded at fair value on our Consolidated Balance Sheets.

 

(5) Does not include Greenfield LP or OMEC, which are unconsolidated investments.

 

(6) The amounts include obligations under employment agreements. They do not include success fees for which amounts had not been earned or awarded as of December 31, 2007. See Item 11. “Executive Compensation” for a further discussion of employment agreements entered into with certain of our executive officers.

 

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

 

(8) Does not include certain success fees that could be paid to third party financial advisors retained by the Company and the Committees in connection with our Chapter 11 cases. Currently, we estimate these success fees could amount to approximately $41 million in the aggregate.

 

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Special Purpose Subsidiaries — Pursuant to applicable transaction agreements, we have established certain of our entities separate from Calpine and our other subsidiaries. In accordance with applicable accounting standards, we consolidate these entities. As of the date of filing this Report, these entities included: Rocky Mountain Energy Center, LLC, Riverside Energy Center, LLC, Calpine Riverside Holdings, LLC, PCF, PCF III, Gilroy Energy Center, LLC, Calpine Gilroy Cogen, L.P., Calpine Gilroy 1, Inc., King City Cogen, LLC, Calpine Securities Company, L.P. (a parent company of King City Cogen, LLC), Calpine King City, LLC (an indirect parent company of Calpine Securities Company, L.P.), Calpine Deer Park Partner, LLC, Calpine DP, LLC, Deer Park Energy Center Limited Partnership, CCFCP, Metcalf and Russell City Energy Company, LLC. The following disclosures are required under certain applicable agreements and pertain to some of these entities. The financial information provided below represents the assets, liabilities, and results of operations for each of the special purpose subsidiaries as reflected on our Consolidated Financial Statements. These amounts may differ materially from the assets, liabilities, and results of operations of these entities on a stand-alone basis as presented in their individual financial statements.

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 totaling $802 million original principal amount. The Senior Secured Notes Due 2006 were paid in accordance with their terms upon maturity in 2006 and are no longer outstanding. PCF’s 6.256% Senior Secured Notes due 2010 are secured by fixed cash flows from a fixed-priced, long-term PPA 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 under the CDWR PPA. The spread between the price for power under the CDWR PPA and the price for power under the third party PPA provides the cash flow to pay debt service on the Senior Secured Notes due 2010 and PCF’s other expenses. The Senior Secured Notes due 2010 are non-recourse to us and our other subsidiaries.

PCF has been established as an entity with its existence separate from us and other subsidiaries of ours. PCF’s assets and liabilities, consisting of cash (maintained in a debt reserve fund), the third party PPA, the CDWR PPA and the remaining outstanding Senior Secured Notes Due 2010 are assets and liabilities of PCF, separate from our assets and liabilities and those of other subsidiaries of ours. 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. The following table sets forth selected financial information of PCF as of and for the year ended December 31, 2007 (in millions):

 

     2007

Assets

   $         283

Liabilities

     297

Total revenue

     513

Total cost of revenue

     437

Interest expense

     28

Net income

     54

See Notes 8 and 13 of the Notes to Consolidated Financial Statements for further information.

On June 2, 2004, our wholly owned indirect subsidiary, PCF III, issued $85 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 million at December 31, 2007 and 2006. We received cash proceeds of approximately $50 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 Calpine Corporation and other subsidiaries of ours. The following table sets forth the

 

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assets and liabilities of PCF III as of December 31, 2007, and does not include the balances of PCF III’s subsidiary, PCF (in millions):

 

     2007

Assets

   $           —

Liabilities

     82

See Note 8 of the Notes to Consolidated Financial Statements for further information.

GEC, a wholly owned subsidiary of GEC Holdings, LLC, has been established as an entity with its existence separate from us and other subsidiaries of ours. We consolidate this entity. On September 30, 2003, GEC, a wholly owned subsidiary of our subsidiary GEC Holdings, LLC, completed an offering of $302 million of 4% Senior Secured Notes Due 2011. 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 million. This preferred interest meets the criteria of a mandatorily redeemable financial instrument and has been classified as debt 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 million over the 8-year period. As of December 31, 2007 and 2006, there was $44 million and $51 million, respectively, outstanding under the preferred interest.

A long-term PPA between CES and CDWR was 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 Corporation and our other subsidiaries. In addition to the PPA and nine peaker power plants (including Creed and Goose Haven) 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 GEC, 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 a peaker power plant and other assets. The following table sets forth selected financial information of GEC for the year ended December 31, 2007 (in millions):

 

     2007

Assets

   $         700

Liabilities

     337

Total revenue

     88

Total cost of revenue

     31

Interest expense

     12

Net income

     48

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 for $133 million in cash. Because the transaction did not satisfy the criteria for sales treatment in accordance with applicable accounting standards it was recorded on our Consolidated Financial Statements as a secured financing, with a note payable of $133 million. The notes receivable balance and note payable balance are both reduced as PG&E makes payments to the buyers of the notes receivable. The $24 million difference between the $157 million book value of the notes 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

 

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ours. The following table sets forth the assets and liabilities of Gilroy and Calpine Gilroy I, Inc. as of December 31, 2007 (in millions):

 

     2007

Assets

   $         331

Liabilities

     100

Liabilities subject to compromise

     2

See Notes 6 and 8 of the Notes to Consolidated Financial Statements for further information.

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 million comprising $633 million of First Priority Secured Floating Rate Term Loans Due 2011 and a $28 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 Corporation and other subsidiaries of ours. The following table sets forth the assets and liabilities of these entities as of December 31, 2007 (in millions):

 

     Rocky Mountain
Energy Center, LLC
2007
   Riverside
Energy Center, LLC
2007
   Calpine Riverside
Holdings, LLC

2007

Assets

   $                    428    $                    768    $                    399

Liabilities

   239    368   

See Note 8 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 $196 million, net of $17 million in transaction costs during the first quarter of 2005, and subsequently received additional cash payments of $76 million, net of $3 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.

The following table sets forth the assets and liabilities of Deer Park as of December 31, 2007 (in millions):

 

     2007

Assets

   $         529

Liabilities

     702

See Note 13 of the Notes to Consolidated Financial Statements for further information.

On October 14, 2005, our indirect subsidiary, CCFCP, issued $300 million of 6-year redeemable preferred shares. The CCFCP redeemable preferred shares are mandatorily redeemable on the maturity date of October 13, 2011, and are accounted for as long-term debt and any related preferred dividends will be accounted for as interest expense.

 

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The following table sets forth the assets and liabilities of CCFCP as of December 31, 2007 (in millions):

 

     2007

Assets

   $         2,221

Liabilities

     1,258

See Note 8 of the Notes to Consolidated Financial Statements for further information.

On June 20, 2005, Metcalf consummated the sale of $155 million of 5.5-year redeemable preferred shares. Concurrent with the closing, Metcalf entered into a 5-year, $100 million senior term loan. Proceeds from the senior term loan were used to refinance all outstanding indebtedness under the existing $100 million non-recourse construction credit facility.

The following table sets forth the assets and liabilities of Metcalf as of December 31, 2007 (in millions):

 

     2007

Assets

   $         1,070

Liabilities

     640

See Note 8 of the Notes to Consolidated Financial Statements for further information.

In September 2006, we sold a 35% equity interest in Russell City Energy Center, a proposed 600-MW, natural gas-fired power plant to be located in Hayward, California, to ASC for approximately $44 million and ASC’s obligation to post a $37 million letter of credit. We own the remaining 65% interest. Construction is anticipated to begin on this project once all permits and other required approvals are final and non-appealable, and project financing has closed.

The following table sets forth the assets and liabilities of Russell City Energy Center as of December 31, 2007 (in millions):

 

     2007

Assets

   $             94

Liabilities

     10

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, 2007, through December 31, 2007, is summarized in the table below (in millions):

 

Fair value of contracts outstanding at January 1, 2007

   $ (202 )

Gains (losses) recognized or otherwise settled during the period(1)

     77  

Fair value attributable to new contracts

     (160 )

Changes in fair value attributable to price movements

     91  

Terminated derivatives

      
        

Fair value of contracts outstanding at December 31, 2007(2)

   $         (194 )
        

 

 

(1)

Recognized gains from commodity cash flow hedges of $10 million (represents a portion of the realized value of natural gas and power cash flow hedge activity of $6 million as disclosed in Note 13 of the Notes to

 

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Consolidated Financial Statements), gains related to deferred items of $110 million and losses related to undesignated derivatives of $43 million (represents a portion of the operating revenues as reported on our Consolidated Statements of Operations).

 

(2) Net commodity derivative liabilities reported in Note 13 of the Notes to Consolidated Financial Statements.

Of the total mark-to-market gain of $5 million for the year ended December 31, 2007, which has components in both operating revenues and fuel and purchased energy expenses, there was a realized gain of $39 million, and an unrealized loss of $34 million. The realized gain included a non-cash gain of approximately $54 million from amortization of various items.

The fair value of outstanding derivative commodity instruments at December 31, 2007, based on price source and the period during which the instruments will mature, are summarized in the table below (in millions):

 

Fair Value Source

   2008     2009-2010     2011-2012     After 2012    Total  

Prices actively quoted

   $         (21 )   $         (16 )   $         —     $         —    $         (37 )

Prices provided by other external sources

     (1 )     (132 )     (13 )          (146 )
Prices based on models and other valuation methods                  (11 )          (11 )
                                       

Total fair value

   $ (22 )   $ (148 )   $ (24 )   $    $ (194 )
                                       

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 “— Application of 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, 2007, and the period during which the instruments will mature are summarized in the table below (in millions):

 

<

Credit Quality

(Based on Standard & Poor’s Ratings as of

December 31, 2007)

   2008     2009-2010     2011-2012     After 2012    Total  

Investment grade

   $         136     $         56     $         (24 )   $         —    $         168  

No external ratings

     (158 )     (204 )