Attached files

file filename
EX-21.1 - SUBSIDIARIES OF THE COMPANY - CALPINE CORPdex211.htm
EX-32.1 - SECTION 906 CERTIFICATIONS OF CEO AND CFO - CALPINE CORPdex321.htm
EX-31.1 - SECTION 302 CERTIFICATION OF CEO - CALPINE CORPdex311.htm
EX-23.1 - CONSENT OF PRICEWATERHOUSECOOPERS LLP - CALPINE CORPdex231.htm
EX-18.1 - LETTER OF PREFERABILITY - CALPINE CORPdex181.htm
EX-23.2 - CONSENT OF PRICEWATERHOUSECOOPERS LLP - RELATING TO OTAY MESA ENERGY - CALPINE CORPdex232.htm
EX-10.2.5 - U.S. SEVERANCE PROGRAM - CALPINE CORPdex1025.htm
EX-10.2.10 - CHANGE IN CONTROL AND SEVERANCE BENEFITS PLAN - CALPINE CORPdex10210.htm
EX-31.2 - SECTION 302 CERTIFICATION OF CFO - CALPINE CORPdex312.htm
Table of Contents
Index to Financial Statements

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form 10-K

 

                [X]   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934   
For the fiscal year ended December 31, 2009
                [    ]   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934   
For the transition period from                      to                     

Commission File No. 001-12079

 

 

Calpine Corporation

(A Delaware Corporation)

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

717 Texas Avenue, Suite 1000, Houston, Texas 77002

Telephone: (713) 830-8775

Not Applicable

(Former Address)

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 [X]    No [    ]

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 whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).     Yes [    ]     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.    [    ]

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 Act).     Yes [    ]     No [X]

State the aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2009, the last business day of the registrant’s most recently completed second fiscal quarter: approximately $2,018 million.

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 [    ]

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: Calpine Corporation: 442,890,684 shares of common stock, par value $.001, were outstanding as of February 22, 2010.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved.

Designated portions of the Proxy Statement relating to the 2010 Annual Meeting of Shareholders are incorporated by reference into Part III (Items 11, 12, 13, 14 and portions of Item 10)

 

 

 


Table of Contents
Index to Financial Statements

CALPINE CORPORATION AND SUBSIDIARIES

FORM 10-K

ANNUAL REPORT

For the Year Ended December 31, 2009

TABLE OF CONTENTS

 

          Page
   PART I   

Item 1.

   Business    3

Item 1A.

   Risk Factors    36

Item 1B.

   Unresolved Staff Comments    53

Item 2.

   Properties    53

Item 3.

   Legal Proceedings    53

Item 4.

   Submission of Matters to a Vote of Security Holders    53
   PART II   

Item 5.

   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities    54

Item 6.

   Selected Financial Data    57

Item 7.

   Management’s Discussion and Analysis of Financial Condition and Results of Operations    58

Item 7A.

   Quantitative and Qualitative Disclosures about Market Risk    105

Item 8.

   Financial Statements and Supplementary Data    105

Item 9.

   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure    105

Item 9A.

   Controls and Procedures    105

Item 9B.

   Other Information    106
   PART III   

Item 10.

   Directors, Executive Officers and Corporate Governance    107

Item 11.

   Executive Compensation    108

Item 12.

   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters    108

Item 13.

   Certain Relationships and Related Transactions and Director Independence    108

Item 14.

   Principal Accounting Fees and Services    108
   PART IV   

Item 15.

   Exhibits, Financial Statement Schedule    109
Signatures    114
Power of Attorney    115
Index to Consolidated Financial Statements    116

 

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Table of Contents
Index to Financial Statements

DEFINITIONS

As used in this Report, the following abbreviations and terms have the meanings as listed 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, for the period from December 20, 2005, through February 7, 2008, such terms do not include the Canadian Debtors and other foreign subsidiaries that were deconsolidated as of the Petition Date. The term “Calpine Corporation” refers 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 in each case as amended, restated, supplemented or otherwise modified to the date of filing this Report.

 

ABBREVIATION

  

DEFINITION

Acadia PP    Acadia Power Partners, LLC
Adjusted EBITDA    EBITDA as adjusted for the effects of (a) impairment charges, (b) reorganization items, (c) major maintenance expense, (d) operating lease expense, (e) any non-cash realized gains on derivatives and any unrealized gains or losses on commodity derivative mark-to-market activity, (f) adjustments to reflect only the Adjusted EBITDA from our unconsolidated investments, (g) claim settlement income, (h) stock-based compensation expense (income), (i) non-cash gains or losses on sales or dispositions of assets, (j) non-cash gains and losses from intercompany foreign currency translations, (k) any gains or losses on the repurchase or extinguishment of debt and (l) any other extraordinary, unusual or non-recurring items
Aircraft Services    Aircraft Services Corporation, an affiliate of General Electric Capital Corporation
AOCI    Accumulated Other Comprehensive Income
Aries Power Plant    MEP Pleasant Hill, LLC
Auburndale    Auburndale Holdings, LLC
Average availability    Represents the total hours during the period that our plants were in-service or available for service as a percentage of the total hours in the period

Average capacity

factor (excluding peakers)

   The average capacity factor (excluding peakers) is a measure of total actual generation as a percent of total potential generation. It is calculated by dividing (a) total MWh generated by our power plants (excluding peakers) by (b) the product of multiplying (i) the average total MW in operation during the period by (ii) the total hours in the period
Bankruptcy Code    U.S. Bankruptcy Code
BLM    Bureau of Land Management of the U.S. Department of the Interior
Blue Spruce    Blue Spruce Energy Center LLC
Btu    British thermal unit(s), a measure of heat content
CAA    Federal Clean Air Act, U.S. Code Title 42, Chapter 85
CAISO    California ISO
CalGen    Calpine Generating Company, LLC

 

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Index to Financial Statements

ABBREVIATION

  

DEFINITION

CalGen Secured Debt    Collectively the: CalGen First Lien Debt comprised of (a) $235,000,000 First Priority Secured Floating Rate Notes Due 2009, (b) $600,000,000 First Priority Secured Institutional Term Loans Due 2009, and (c) $200,000,000 First Priority Revolving Loans issued on or about March 23, 2004; CalGen Second Lien Debt comprised of (a) $640,000,000 Second Priority Secured Floating Rate Notes Due 2010, and (b) $100,000,000 Second Priority Secured Institutional Term Loans Due 2010; and CalGen Third Lien Debt. In each case, issued by CalGen or CalGen and CalGen Finance Corp. and repaid on March 29, 2007
CalGen Third Lien Debt    Together, the $680,000,000 Third Priority Secured Floating Rate Notes Due 2011, issued by CalGen and CalGen Finance Corp.; and the $150,000,000 11 1/2% Third Priority Secured Notes Due 2011, issued by CalGen and CalGen Finance Corp., in each case repaid on March 29, 2007
Calpine Debtors    The U.S. Debtors and the Canadian Debtors
Calpine Equity Incentive Plans    Collectively, the MEIP and the DEIP, 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 Debtors    The subsidiaries and affiliates of Calpine Corporation that were 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
Cap-and-trade    A government imposed GHG emissions reduction program that would place a cap on the amount of GHG emissions that can be emitted from certain sources, such as power plants. In its simplest form, the cap amount is set as a reduction from the total emissions during a base year and for each year over a period of years the cap amount would be reduced to achieve the targeted overall reduction by the end of the period. Allowances or credits for emissions in an amount equal to the cap would be issued or auctioned to companies with facilities, permitting them to emit up to a certain amount of GHG during each applicable period. After allowances have been distributed or auctioned, they can be transferred, or traded
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 dated 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

 

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Index to Financial Statements

ABBREVIATION

  

DEFINITION

CCAA    Companies’ Creditors Arrangement Act (Canada)
CCFC    Calpine Construction Finance Company, L.P.
CCFC Finance    CCFC Finance Corp.
CCFC Guarantors    Hermiston Power LLC and Brazos Valley Energy LLC, wholly owned subsidiaries of CCFC
CCFC New Notes    The $1.0 billion aggregate principal amount of 8.0% Senior Secured Notes due 2016 issued May 19, 2009, by CCFC and CCFC Finance
CCFC Old Notes    The $415 million total aggregate principal amount of Second Priority Senior Secured Floating Rate Notes Due 2011 issued by CCFC and CCFC Finance, comprising $365 million aggregate principal amount issued August 14, 2003, and $50 million aggregate principal amount issued September 25, 2003, and redeemed on June 18, 2009
CCFC Refinancing    The issuance of the CCFC New Notes on May 19, 2009, pursuant to Rule 144A and Regulation S under the Securities Act, and the related transactions including repayment of the CCFC Term Loans and the redemption of the CCFC Old Notes and CCFCP Preferred Shares
CCFC Term Loans    The $385 million First Priority Senior Secured Institutional Term Loans due 2009 borrowed by CCFC under the Credit and Guarantee Agreement, dated as of August 14, 2003, among CCFC, the guarantors party thereto, and Goldman Sachs Credit Partners L.P., as sole lead arranger, sole bookrunner, administrative agent and syndication agent, and repaid on May 19, 2009
CCFCP    CCFC Preferred Holdings, LLC
CCFCP Preferred Shares    The $300 million of six-year redeemable preferred shares due 2011 issued by CCFCP and redeemed on or before July 1, 2009
CDWR    California Department of Water Resources
CES    Calpine Energy Services, L.P.
CFTC    U.S. Commodities Futures Trading Commission
Chapter 11    Chapter 11 of the Bankruptcy Code
CO2    Carbon dioxide
Cogeneration    Using a portion or all of the steam generated in the power generating process to supply a customer with steam for use in the customer’s operations
Commodity Collateral Revolver    Commodity Collateral Revolving Credit Agreement, dated as of July 8, 2008, among Calpine Corporation as borrower, Goldman Sachs Credit Partners L.P., as payment agent, sole lead arranger and sole bookrunner, and the lenders from time to time party thereto
Commodity expense    The sum of our expenses from fuel and purchased energy expense, fuel transportation expense, transmission expense and cash settlements from our marketing, hedging and optimization activities that are included in our mark-to-market activity in fuel and purchased energy expense, but excludes the unrealized portion of our mark-to-market activity

 

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Index to Financial Statements

ABBREVIATION

  

DEFINITION

Commodity Margin    Non-GAAP financial measure that includes power and steam revenues, sales of purchased power and natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, RGGI compliance costs, and cash settlements from our marketing, hedging and optimization activities that are included in mark-to-market activity, but excludes the unrealized portion of our mark-to-market activity and other revenues
Commodity revenue    The sum of our revenues from power and steam sales, sales of purchased power and natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue, and cash settlements from our marketing, hedging and optimization activities that are included in our mark-to-market activity in operating revenues but excludes the unrealized portion of our mark-to-market activity
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 Senior Notes    Collectively, Calpine Corporation’s 4% Contingent Convertible Notes Due 2006, Contingent Convertible Notes Due 2014, 7 3/4% Contingent Convertible Notes Due 2015 and 4 3/4% Contingent Convertible Senior Notes Due 2023, all of which were terminated and settled with reorganized Calpine Corporation common stock on the Effective Date
CPUC    California Public Utilities Commission
Creed    Creed Energy Center, LLC
Deer Park    Deer Park Energy Center Limited Partnership
DEIP    Calpine Corporation 2008 Director Incentive Plan, which provides for grants of equity awards to non-employee members of Calpine’s Board of Directors
DIP    Debtor-in-possession
DIP Facility    The Revolving Credit, Term Loan and Guarantee Agreement, dated as of March 29, 2007, among Calpine Corporation, as borrower, certain of Calpine Corporation’s subsidiaries, as guarantors, the lenders party thereto, and Credit Suisse, as administrative agent and collateral agent, and the other agents, arrangers and bookrunners named therein
Disclosure Statement    Disclosure Statement for the U.S. Debtors’ Joint Plan of Reorganization Pursuant to Chapter 11 of the 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

 

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Index to Financial Statements

ABBREVIATION

  

DEFINITION

Emergence Date Market

Capitalization

   The weighted average trading price of Calpine Corporation’s common stock over the 30-day period following the date on which it emerged from Chapter 11 bankruptcy protection, as defined in and calculated pursuant to Calpine Corporation’s amended and restated certificate of incorporation and reported in its Current Report on Form 8-K filed with the SEC on March 25, 2008
EPA    U.S. Environmental Protection Agency
ERCOT    Electric Reliability Council of Texas
EWG(s)    Exempt wholesale generator(s)
Exchange Act    U.S. Securities Exchange Act of 1934, as amended
FDIC    U.S. Federal Deposit Insurance Corporation
FERC    U.S. Federal Energy Regulatory Commission
First Lien Credit Facility    Credit Agreement, dated as of January 31, 2008, as amended by the First Amendment to Credit Agreement and Second Amendment to Collateral Agency and Intercreditor Agreement, dated as of August 20, 2009, among Calpine Corporation, as borrower, certain subsidiaries of the Company named therein, as guarantors, the lenders party thereto, Goldman Sachs Credit Partners L.P., as administrative agent and collateral agent, and the other agents named therein
First Lien Facilities    Together, our First Lien Credit Facility and $300 million Bridge Loan Agreement dated January 31, 2008 repaid on March 6, 2008
First Lien Notes    $1.2 billion aggregate principal amount of 7 1/4% senior secured notes due 2017 issued October 21, 2009, in exchange for a like principal amount of term loans under the First Lien Credit Facility
First Priority Notes    9 5/8% First Priority Senior Secured Notes Due 2014, repaid in May and June 2006
FRCC    Florida Reliability Coordinating Council
Fremont    Fremont Energy Center, LLC
GAAP    Generally accepted accounting principles
GE    General Electric International, Inc.
GEC    Collectively, Gilroy Energy Center, LLC, Creed and Goose Haven
Geysers Assets    Our geothermal power plant assets, including our steam extraction and gathering assets, located in northern California consisting of 15 operating power plants and one plant not in operation
GHG(s)    Greenhouse gas(es), primarily CO2, and including methane (CH4), nitrous oxide (N2O), sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs) and perfluorocarbons (PFCs)
Gilroy    Calpine Gilroy Cogen, L.P.
Goose Haven    Goose Haven Energy Center, LLC
Greenfield LP    Greenfield Energy Centre LP
Heat Rate(s)    A measure of the amount of fuel required to produce a unit of power
Hg    Mercury
Hillabee    Hillabee Energy Center, LLC
IRC    Internal Revenue Code

 

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Index to Financial Statements

ABBREVIATION

  

DEFINITION

ISO(s)    Independent System Operator(s)
ISO NE    ISO New England
Knock-in Facility    Letter of Credit Facility Agreement, dated as of June 25, 2008, among Calpine Corporation as borrower and Morgan Stanley Capital Services Inc., as issuing bank which matured on June 30, 2009
KWh    Kilowatt hour(s), a measure of power produced
LIBOR    London Inter-Bank Offered Rate
LSTC    Liabilities subject to compromise
LTSA(s)    Long-Term Service Agreement(s)
Market Capitalization    As of any date, Calpine Corporation’s then market capitalization calculated using the rolling 30-day weighted average trading price of Calpine Corporation’s common stock, as defined in and calculated in accordance with the Calpine Corporation amended and restated certificate of incorporation
Market Heat Rate(s)    The regional power price divided by the corresponding regional natural gas price
MEIP    Calpine Corporation 2008 Equity Incentive Plan, which provides for grants of equity awards to Calpine employees and non-employee members of Calpine’s Board of Directors
Metcalf    Metcalf Energy Center, LLC
MISO    Midwest ISO
MMBtu    Million Btu
MRO    Midwest Reliability Organization
MW    Megawatt(s), a measure of plant capacity
MWh    Megawatt hour(s), a measure of power produced
NERC    North American Electric Reliability Council
NOL(s)    Net operating loss(es)
NOx    Nitrogen oxide
NPCC    Northeast Power Coordinating Council
NYISO    New York ISO
NYMEX    New York Mercantile Exchange
NYSE    New York Stock Exchange
OCI    Other Comprehensive Income
OMEC    Otay Mesa Energy Center, LLC
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 the 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, 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 and the other agents named therein, refinanced in March 2007 with the DIP Facility

 

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ABBREVIATION

  

DEFINITION

OTC    Over-the-Counter
Panda    Panda Energy International, Inc., and related party PLC II, LLC
PCF    Power Contract Financing, L.L.C.
PCF III    Power Contract Financing III, LLC
Petition Date    December 20, 2005
PG&E    Pacific Gas & Electric Company
PJM    Pennsylvania-New Jersey-Maryland Interconnection
Plan of Reorganization    Sixth Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the 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
Pomifer    Pomifer Power Funding, LLC, a subsidiary of Arclight Energy Partners Fund I, L.P.
PPA(s)    Any term power purchase agreement or other contract for a physically settled sale (as distinguished from a financially settled future, option or other derivative or hedge transaction) of any power product, including power, 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 the purchaser provides the fuel required by us to generate such power and we receive a variable payment to convert the fuel into power and steam
PSM    Power Systems Manufacturing, LLC
PUCT    Public Utility Commission of Texas
PUHCA 1935    U.S. Public Utility Holding Company Act of 1935
PUHCA 2005    U.S. Public Utility Holding Company Act of 2005
PURPA    U.S. 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 power and thermal energy production requirements and efficiency standards. QF status provides an exemption from PUHCA 2005 and grants certain other benefits to the QF
REC(s)    Renewable energy credit(s)
Reserve margin(s)    The measure of how much the total generating capacity installed in a region exceeds the peak demand for power in that region
RFC    ReliabilityFirst Corporation
RGGI    Regional Greenhouse Gas Initiative
RMR Contract(s)    Reliability Must Run contract(s)
RockGen    RockGen Energy LLC
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.
RPS    Renewable Portfolio Standards
SDG&E    San Diego Gas & Electric Company

 

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ABBREVIATION

  

DEFINITION

SEC    U.S. Securities and Exchange Commission
Second Circuit    U.S. Court of Appeals for the Second Circuit
Second Priority Debt    Collectively, 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 and Second Priority Senior Secured Term Loans Due 2007; all of which were repaid on the Effective Date
Securities Act    U.S. Securities Act of 1933, as amended
SERC    Southeastern Electric Reliability Council
SO2    Sulfur dioxide
Spark spread(s)    The difference between the sales price of power per MWh and the cost of fuel to produce it
SPP    Southwest Power Pool
Steam Adjusted Heat Rate    The adjusted Heat Rate for our natural gas-fired power plants, excluding peakers, calculated by dividing (a) the fuel consumed in Btu reduced by the net equivalent Btu in steam exported to a third party by (b) the KWh generated. Steam Adjusted Heat Rate is a measure of fuel efficiency, so the lower our Steam Adjusted Heat Rate, the lower our cost of generation
Steamboat    Calpine Steamboat Holdings, LLC, an indirect, wholly owned subsidiary of Calpine Corporation

Steamboat Amended Credit

Facility

   The Amended and Restated Credit Agreement dated November 24, 2009 between Steamboat, as borrower, the lenders named therein, Calyon New York Branch as lead arranger, co-book runner, administrative agent, collateral agent and Security Fund LC issuer and the other agents, bookrunners and agents named therein amending and restating the Credit Agreement, dated as of February 25, 2005, among the parties as defined therein
TRE    Texas Regional Entity
ULC I    Calpine Canada Energy Finance ULC
ULC II    Calpine Canada Energy Finance II ULC
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 constitute a portion of Calpine Corporation’s Unsecured Senior Notes all of which were terminated and settled with Calpine Corporation common stock on the Effective Date
Unsecured Senior Notes    Collectively, Calpine Corporation’s 7 5/8% Senior Notes due 2006, 10 1/2% Senior Notes due 2006, 8 3/4% Senior Notes due 2007, 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, all of which were terminated and settled with Calpine Corporation common stock on the Effective Date
U.S. Bankruptcy Court    U.S. Bankruptcy Court for the Southern District of New York

 

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Index to Financial Statements

ABBREVIATION

  

DEFINITION

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)
VAR    Value-at-risk
VIE(s)    Variable interest entity(ies)
WECC    Western Electricity Coordinating Council
Whitby    Whitby Cogeneration Limited Partnership
WP&L    Wisconsin Power & Light Company

 

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Index to Financial Statements

Forward-Looking Statements

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,” “should,” “estimate,” “potential,” “project” 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:

 

   

The uncertain length and severity of the current general financial and economic downturn, the timing and strength of an economic recovery, if any, and their impacts on our business including demand for our power and steam products, the ability of customers, suppliers, service providers and other contractual counterparties to perform under their contracts with us and the cost and availability of capital and credit;

 

   

Financial results that may be volatile and may not reflect historical trends due to, among other things, fluctuations in prices for commodities such as natural gas and power, fluctuations in liquidity and volatility in the energy commodities markets and our ability to hedge risks;

 

   

Our ability to manage our customer and counterparty exposure and credit risk, including our commodity positions;

 

   

Our ability to manage our significant liquidity needs and to comply with covenants under our First Lien Credit Facility, our First Lien Notes and other existing financing obligations;

 

   

Competition, including risks associated with marketing and selling power in the evolving energy markets;

 

   

Regulation in the markets in which we participate and our ability to effectively respond to changes in laws and regulations or the interpretation thereof including changing market rules and evolving federal, state and regional laws and regulations including those related to GHG emissions and derivative transactions;

 

   

Natural disasters, such as hurricanes, earthquakes and floods, or acts of terrorism that may impact our power plants or the markets our power plants serve;

 

   

Seasonal fluctuations of our results and exposure to variations in weather patterns;

 

   

Disruptions in or limitations on the transportation of natural gas and transmission of power;

 

   

Our ability to attract, retain and motivate key employees;

 

   

Our ability to implement our business plan and strategy;

 

   

Risks related to our geothermal resources, including the adequacy of our steam reserves, unusual or unexpected steam field well and pipeline maintenance requirements, variables associated with the injection of wastewater to the steam reservoir and potential regulations or other requirements related to seismicity concerns that may delay or increase the cost of developing or operating geothermal resources;

 

   

Risks associated with the operation, construction and development of power plants including unscheduled outages or delays and plant efficiencies;

 

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Present and possible future claims, litigation and enforcement actions;

 

   

The expiration or termination of our PPAs and the related results on revenues; and

 

   

Other risks identified in this Report.

Given the risks and uncertainties surrounding forward-looking statements, you should not place undue reliance on these statements. Many of these factors are beyond our ability to control or predict. Our forward-looking statements speak only as of the date of this Report. Other than as required by law, we undertake no obligation to update or revise forward-looking statements, whether as a result of new information, future events, or otherwise.

Where You Can Find Other Information

Our website is www.calpine.com. Information contained on our website is not part of this Report. Information that we furnish or file with the SEC, including our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to or exhibits included in these reports are available for download, free of charge, on our website soon after such reports are filed with or furnished to the SEC. Our SEC filings, including exhibits filed therewith, are also available at the SEC’s website at www.sec.gov. You may obtain and copy any document we furnish or file with the SEC at the SEC’s public reference room at 100 F Street, NE, Room 1580, Washington, D.C. 20549-1004. You may obtain information on the operation of the SEC’s public reference facilities by calling the SEC at 1-800-SEC-0330. You may 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.

 

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PART I

Item 1. Business

BUSINESS AND STRATEGY

Business

We aspire to be recognized as the premier independent power producer in the U.S. We seek to achieve this objective by delivering operational excellence, effectively executing our hedging strategy, reinvigorating our customer origination program, completing, on schedule and budget, our growth capital projects, and strengthening our balance sheet. We are the largest independent wholesale power company in the U.S. measured by power produced. We own and operate natural gas-fired and geothermal power plants in North America and have a significant presence in major competitive power markets in the U.S., including California and Texas, and to a lesser extent, in the competitive PJM, ISO NE and NYISO markets. Since our inception in 1984, we have been a leader in environmental stewardship and have invested exclusively in clean power generation to become a recognized leader in developing, constructing, owning and operating an environmentally responsible portfolio of power plants. Our portfolio is comprised of two types of power generation technologies: natural gas-fired combustion turbines, which are primarily combined-cycle plants, and renewable geothermal conventional steam turbines. We are among the world’s largest owners and operators of industrial gas turbines as well as cogeneration power plants. Our Geysers Assets located in northern California represent the largest geothermal power generation portfolio in the U.S. and produced approximately 21% of all renewable energy produced in the state of California during 2008. We sell wholesale power, steam, capacity, renewable energy credits and ancillary services to our customers, including utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities, power marketers and others. We purchase natural gas as fuel for our power plants, engage in related natural gas transportation and storage transactions and we purchase electric transmission rights to deliver power to our customers. We also enter into natural gas and power-related commodity and derivative transactions to financially hedge certain business risks and optimize our portfolio of power plants.

Our portfolio, including partnership interests, consists of 77 operating power plants, located throughout 16 states and Canada, with an aggregate generation capacity of approximately 24,802 MW. In addition, we are actively pursuing the development of our Russell City Energy Center, in which we have a net interest of approximately 400 MW, and an upgrade of 120 MW to our Los Esteros Critical Energy Facility, both located in the San Francisco Bay Area. We also have begun geothermal exploration to increase our generation capability at our Geysers Assets.

The environmental profile of our power plants reflects our commitment to environmental leadership and stewardship. We have invested the necessary capital to develop a power generation portfolio that has the lowest GHG footprint per MWh of any major independent power producer in the U.S. The combination of our Geysers Assets and our high efficiency portfolio of natural gas-fired power plants results in substantially lower emissions of these gases compared to our competitors’ power plants using other fossil fuels, such as coal. In addition, we strive to preserve our nation’s valuable water and land resources. To condense steam, we use cooling towers with a closed water cooling system, or air cooled condensers and do not employ “once-through” water cooling, which uses large quantities of water from adjacent waterways negatively impacting aquatic life. Since our plants are modern and efficient and utilize clean burning natural gas, we do not require large areas of land for our power plants nor do we require large specialized landfills for the disposal of coal ash or nuclear plant waste. We believe that we will be less adversely impacted by cap-and-trade limits, carbon taxes or required environmental upgrades as a result of future potential regulation or legislation addressing GHG, other air emissions, as well as water use or emissions, than compared to our competitors who use other fossil fuels or steam condensation technologies.

We remain focused on increasing our earnings and generating cash flow sufficient to maintain adequate levels of liquidity in order to service our debt, meet our collateral needs and fund our operations and growth. We

 

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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. Our fleet of natural gas-fired turbines is the youngest in the U.S. among large independent power producers and utilities, with a weighted average age, based upon MW capacities in operation, of about eight years. As a result, in the near term we do not expect that it will be necessary to invest significant expenditures for environmental retrofits or repowering projects to comply with current or reasonably anticipated GHG, other air emissions or water regulations. Our power plants taken as a whole or by region, have an effective Heat Rate lower than that of our major competitors, which we believe gives us a competitive edge in markets such as Texas, California and some northeastern states where natural gas-fired generation generally sets the market price for power.

We sell a substantial portion of our power and other products under PPAs with a duration greater than one year. The contracted sale of power, steam and capacity from our cogeneration power plants, combustion turbine power plants and geothermal power plants, as well as the sale of renewable energy credits, or RECs, from geothermal power plants, provide a stable source of revenue. Our portfolio also affords us the flexibility to sell power and other products forward for shorter terms or on a merchant basis into the spot markets, where we are able to realize attractive pricing particularly during peak demand periods. Additionally, we sell capacity or similar products to retail power providers, utilities, municipalities and others required to acquire capacity and similar products by regulatory or market rules and we sell ancillary services to independent system operators and utilities to support power transmission system reliability. We believe we have substantially hedged our Commodity Margin for 2010. By contrast, we remain exposed to significant commodity price movements for 2011 and beyond.

Our principal offices are located in Houston, Texas with a regional office in Dublin, California, an engineering office in La Porte, Texas and representative offices in Washington D.C., Sacramento, California and Austin, Texas. We operate our business through a variety of divisions, subsidiaries and affiliates.

Strategy

Our goal is to be recognized as the premier independent power company in the U.S. as measured by our customers, regulators, shareholders and communities in which our power plants reside. We seek to achieve sustainable growth through financially disciplined power plant development, construction, operations and ownership. Our strategy to achieve this is reflected in the six major initiatives described below:

 

  1. Premier Operating Company — Our objective is to be the “best-in-class” in regards to certain operational performance metrics, such as safety, availability, reliability, efficiency and outage management. Throughout 2009, our plant operating personnel exceeded the first quartile performance for employee lost time incident rate for fossil fuel electric power generation companies with 1,000 or more employees. In addition, for the past nine consecutive years, our Geysers Assets have continued to generate approximately 6 million MWh per year and achieved an exceptional equivalent availability factor of over 97% in 2009. Our natural gas-fired fleet achieved exceptional performance during 2009, with an equivalent forced outage factor of 2.7%, an improvement of 35% over full year 2008. Lastly, we completed 14 major inspections and 13 hot gas path inspections on schedule and on budget during 2009 and completed one of several planned natural gas-fired turbine upgrades and two steam turbine upgrades, which not only added incremental capacity but improved the efficiency of the entire turbines.

 

  2.

Leader in Environmental Responsibility — Our focus is to utilize our modern, efficient fleet to deliver lower carbon energy solutions. We continue to actively participate in legislative and regulatory processes addressing environmental concerns and support legislative and regulatory action to address GHG and other emissions from fossil fuel generation. We intend to leverage our baseload geothermal expertise to grow our renewable energy portfolio. Our strong and continuing commitment to environmental responsibility and leadership is exemplified by our development of the Russell City Energy Center. On

 

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February 4, 2010, we received the Prevention of Significant Deterioration, or PSD, air permit, the final permit necessary, to begin construction of our Russell City Energy Center. Russell City Energy Center is intended to become the first power plant in the U.S. with a federal limit on GHG emissions, and will be designed to operate in a way that produces 25% fewer GHG emissions than the CPUC standard. The power plant will use 100% reclaimed water from the City of Hayward’s Water Pollution Control Facility for cooling and boiler makeup, which will prevent nearly four million gallons of wastewater per day from being discharged into the San Francisco Bay. We initiated and agreed to accept the GHG permit limit and designed the plant to benefit local water resources.

 

  3. Leverage our Scale with our Existing Portfolio of Power Plants — Our goal is to continue to grow our presence in our core markets, particularly, our two largest markets, California and Texas, with an emphasis on expansions or upgrades of existing power plants. We will consider selective acquisitions or additions of new capacity supported by long-term hedging programs, including PPAs and natural gas tolling agreements, particularly where limited or non-recourse project financing is available. We intend to take an opportunistic approach to continue to design, develop, construct and operate the next generation of highly efficient, operationally flexible and environmentally responsible power plants. During 2009, we had the following notable achievements related to this initiative:

 

   

OMEC, located in San Diego, California, achieved commercial operations on October 3, 2009, adding 608 MW of capacity to our fleet. OMEC is a state-of-the-art, environmentally friendly power plant that operates one of the world’s largest air-cooled condenser thereby minimizing our water usage at the site. OMEC operates under a ten-year tolling agreement with SDG&E.

 

   

Under a new ten-year power contract with PG&E, we will modernize and upgrade our Los Esteros Critical Energy Facility to add 120 MW by converting it from simple-cycle (peaking) to combined-cycle technology, increasing the efficiency and environmental performance of the power plant.

 

   

We received the Russell City Energy Center PSD air permit. We hope to complete financing and break ground for this new state-of-the-art power plant during 2010 with commercial operations scheduled to begin in 2013.

 

   

Turbine Upgrades — During the fourth quarter of 2009, we completed a natural gas-fired turbine upgrade at our Deer Park Energy Center, and have an additional ten natural gas-fired turbine upgrades scheduled. We have also upgraded the steam turbines at our McCabe and Ridgeline geothermal power plants that improved the overall turbine efficiency. We have two additional steam turbine upgrades scheduled for 2011 and 2012, and are considering others.

 

  4. Three Scale Regions — We intend to grow our presence in the mid-Atlantic and northeast regions of the U.S. through opportunistic and financially disciplined purchase of existing power plant assets as well as new build projects. We believe this market will result in continued diversification of our asset portfolio, significant near-term growth opportunity and accretive financial strengthening and value.

 

  5. Customer-Oriented Origination Business — Our focus is to maximize and stabilize our Commodity Margin through the utilization of physical forward sales and purchases, and financial tools such as collars, swaps and options. During 2009, we reorganized our customer origination function to allow our dedicated group of professionals to more effectively help manage this function. Their charter is to understand our customer’s wants and needs and to rally our organization to develop unique, cost-effective solutions that benefit us and our customers. This effort is beginning to deliver real, tangible results. For example, we entered into new PPAs and amended certain PPAs with PG&E, and also entered into a new PPA with Southern California Edison related to certain of our power plants in California. The amended and new PPAs are all on mutually beneficial terms, many are subject to regulatory approvals and, among other things, provide for the following:

 

   

We and PG&E have agreed to an extension of the term and an increase in the volume under the existing contracts for delivery of power from our Geysers Assets. Our Geysers Assets currently

 

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provide PG&E 375 MW of power under two contracts. We have agreed to increase the volume to 425 MW through 2017, and from 2018 through the end of 2021, our Geysers Assets will supply PG&E 250 MW of renewable energy.

 

   

Our wholly owned subsidiaries, Gilroy Energy Center, LLC, Creed and Goose Haven, have entered into a replacement contract with PG&E, whereby PG&E will have greater dispatch flexibility for all 11 of our peaking units in California through 2017 and for seven of our peaking units through 2021.

 

   

We and PG&E negotiated a new agreement to replace the existing CDWR contract and facilitate the upgrade of our Los Esteros Critical Energy Facility from a 188 MW simple-cycle generation power plant to a 308 MW combined-cycle generation power plant. In addition to the increase in capacity, the upgrade will increase the efficiency and environmental performance of the power plant by lowering the Heat Rate. While the upgrade is under construction, we will provide capacity to PG&E from our Gilroy Cogeneration Plant. Upon completion of the upgrade, PG&E will purchase all of the capacity from our Los Esteros Critical Energy Facility for a term of ten years.

 

   

We have entered into a new tolling arrangement with PG&E for all of the capacity from our Delta Energy Center from 2011 through 2013.

 

   

We executed a resource adequacy agreement for all of the capacity from our Pastoria Energy Center with Southern California Edison for 2012 and 2013.

 

   

We executed a contract for 500 MW of capacity from our Morgan Energy Center with the Tennessee Valley Authority through 2011.

 

   

We executed a contract for 485 MW of capacity from our Carville Energy Center with Entergy Corporation through May 2012.

 

   

We executed a contract for 200 MW of capacity from our Oneta Energy Center with American Electric Power through 2010.

 

   

In addition to the suite of products we plan to supply through the agreements described above, our commercial operations team is also identifying creative opportunities to match our capabilities with the needs of our customers. During 2009, we entered into a PPA with the Los Angeles Department of Water and Power to provide integration services of up to 270 MW, leveraging our quick-responding natural gas-fired Hermiston Power Project located in Hermiston, Oregon, as well as its contracted transmission resources in the northwest as back up for wind generated power.

The last transaction is an indication of the need our customers and more generally the market will have to utilize flexible natural gas-fired generation to assure reliability of supply while integrating intermittent and variable renewable resources, such as wind and solar power, that they are required to procure as part of a renewable energy portfolio.

 

  6. Continued Strengthening of Our Balance Sheet — We have opportunistically completed several financing transactions for a total of approximately $3.0 billion to improve our flexibility and management of our balance sheet. Significant transactions in 2009 include, but are not limited to, the following:

 

   

On November 24, 2009, we amended and extended our Steamboat project debt which extended the maturity date from December 2011 to November 24, 2017.

 

   

On December 11, 2009, we amended the letter of credit facility related to our subsidiary, Calpine Development Holdings, Inc., to extend the maturity from January 31, 2010 to December 11, 2012, with an option to increase the letters of credit available from $150 million to $200 million by satisfying certain conditions.

 

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On August 20, 2009, we amended our First Lien Credit Facility and related collateral agency and intercreditor agreement in several respects to give us greater flexibility, including allowing us to exchange First Lien Credit Facility term loans for First Lien Notes.

 

   

On October 21, 2009, we issued approximately $1.2 billion aggregate principal amount of First Lien Notes in a private placement as a permitted debt exchange pursuant to our First Lien Credit Facility, which retired an aggregate principal amount of term loans under our First Lien Credit Facility equal to the aggregate principal amount of First Lien Notes issued. As a result of the issuance of the First Lien Notes, we were able to extend the maturities of approximately $1.2 billion in debt to 2017, at the same time converting it from a variable to a fixed interest rate.

 

   

On May 19, 2009, our wholly owned subsidiaries, CCFC and CCFC Finance, issued approximately $1.0 billion aggregate principal amount of CCFC New Notes in a private placement. The net proceeds were used to repay the CCFC Term Loans, CCFC Old Notes and CCFCP Preferred Shares. As a result of the CCFC Refinancing transactions, we were able to extend the maturities of approximately $1.0 billion of debt by several years, at the same time converting it from a variable to a fixed interest rate and lowering our effective interest rates.

 

   

On January 21, 2009, we closed on our Deer Park $156 million senior secured credit facilities, which included a $150 million term facility and a $6 million letter of credit facility. Proceeds received were used to settle an existing commodity contract of approximately $79 million, pay financing and legal fees, fund additional restricted cash and for general corporate purposes.

THE MARKET FOR POWER

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 of $357.1 billion in power sales in 2009 based on information published by the EIA. Historically, vertically integrated power utilities with monopolistic control over franchised territories dominated the power generation industry in the U.S. Over the last 25 years, industry trends and regulatory initiatives, culminating with the deregulation trend of the late 1990’s and early 2000’s, provided opportunities for independent wholesale power producers to compete to provide the power needed by customers in many states. Although different regions of the country have very different models and rules of competition, all of the markets in which we operate have some form of wholesale market competition. California (included in our West segment) and Texas, which are two of our largest markets, have emerged as among the most competitive wholesale markets in the U.S. We also operate, to a lesser extent, in the competitive PJM, ISO NE and NYISO markets.

We produce several products for sale to our customers.

 

   

First, we produce power for sale to utilities, municipalities, retail power providers, independent electric system operators, large end-use industrial or agricultural processing customers or power marketers.

 

   

Second, we produce steam for sale to customers for use in industrial or other heating, ventilation and air conditioning operations.

 

   

Third, we sell regulatory capacity. In various regional markets, retail power providers are required to demonstrate adequate resources to meet their power sales commitments. To meet this obligation, they procure a market product known as capacity, which allows them to attribute the approved capacity of existing power plants to satisfy the obligation. Electricity market administrators have acknowledged

 

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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 have been implemented in the northeast, mid-Atlantic and some mid-west regional markets to address this issue. California has a bilateral capacity program. Texas does not have a capacity market and there is no concrete proposal under consideration by the regulators.

 

   

Fourth, we provide ancillary service products to wholesale power markets. These products include the right for the purchaser to call on our generation units to provide flexibility to the market. As an example, we are sometimes paid to reserve a portion of some capacity at some of our power plants that could be deployed quickly should there be an unexpected increase in load.

 

   

Fifth, we sell RECs from our Geysers Assets in northern California. California has an RPS that requires load serving entities to have RECs for a certain percentage of their demand for the purpose of guaranteeing a certain level of renewable generation in the state. Because geothermal is a renewable source of energy, we receive a REC for each MWh we produce and are able to sell our RECs to load serving entities.

Although all of the products mentioned above contribute to our financial performance, the most important is our sale of wholesale power whether by contract for some term or on a merchant basis into the spot market.

Our Power Market Economics

The market spark spread, sales of RECs, revenues from our steam sales and the results from our marketing, hedging and optimization activities are the primary components of our Commodity Margin and contribute significantly to our financial results. Our Commodity Margin from power and steam sales is largely determined by the pricing associated with our customer contracts. For power that is not sold under customer contracts, the short-term and spot market supply and demand fundamentals determine the sale price for our power. All of our steam production is sold under long-term contracts with industrial customers or steam hosts.

For sales of power from our natural gas-fired fleet into the short-term or spot markets, we attempt to maximize our operations when the market spark spread is positive. Assuming economic behavior by market participants, generating units generally are dispatched in order of their variable costs, with units with lower costs being dispatched first and units with higher costs dispatched as demand, or “load,” grows beyond the capacity of the lower cost units. For this reason, in a competitive market, the price of power typically is related to the variable operating costs of the marginal generator, which is the last unit to be dispatched in order to meet demand. Our fleet is modern and more efficient than the average generation fleet; accordingly, we run more and earn incremental margin in markets in which less efficient natural gas units frequently set the power price. In such cases, our margin is positively correlated with how much more efficient our fleet is than our competitors’ fleets and with higher natural gas prices. Much of our generating capacity is in our West and Texas segments, which are regional markets where natural gas-fired units set prices during most hours, although incremental renewable generation has moderated this dynamic somewhat in off-peak hours over the last year. Due to natural gas prices generally (although not always) being higher than most other input fuels for power production per MMBtu, these regions generally have higher power prices than regions where coal-fired units set power prices. Outside of the California (included in our West segment) and Texas markets (and some northeast markets), other generating technologies, typically coal-fired power plants, tend to set power prices more often, reducing average prices and our Commodity Margin.

Reserve Margins — Reserve margin, a measure of how much excess generation capacity is present in a market, is a key indicator of the competitive conditions in the markets in which we operate. For example, a reserve margin of 15% indicates that supply is 115% of expected peak power demand. Holding other factors constant, lower reserve margins typically lead to higher power prices because the less efficient capacity in the

 

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region would be needed to satisfy power demand. Markets with tight demand and supply conditions often display price spikes and improved bilateral contract opportunities. Typically, the market price impact of reserve margins, as well as other supply/demand factors, is reflected in the “Market Heat Rate” calculated as the local market power price divided by the local natural gas price.

Natural Gas Prices and Supply — Our fuel requirements are predominantly met with natural gas. We procure natural gas from multiple suppliers and transportation sources. Although availability is generally not an issue, localized shortages, transportation availability and supplier financial stability issues can and do occur.

In markets where natural gas is often the price-setting fuel, such as in Texas and California, increases in natural gas prices may increase our unhedged Commodity Margin in any given year because our combined-cycle power plants in those markets are more fuel-efficient than conventional gas-fired technologies and peaker power plants. Conversely, decreases in natural gas prices tend to decrease our unhedged Commodity Margin. In other cases, changes in natural gas prices can have a neutral impact on us in the short term, such as where we have entered into tolling agreements under which the customer provides the natural gas and in return we convert it to power for a fee, or where we enter into indexed-based agreements with a contractual Heat Rate at or near our actual Heat Rate for a monthly payment. Changes in natural gas prices may also affect our liquidity as we could be required to post additional cash collateral or letters of credit during periods of increasing natural gas prices. Despite some of these short-term dynamics, over the long run, more moderate natural gas prices may actually enhance the competitiveness of our modern, natural gas-fired fleet by making investment in other technologies such as coal, nuclear, or renewables less economic.

Weather Patterns and Natural Events — Weather could have a significant short-term impact on supply and demand for power and natural gas. Historically, demand for and the price of power is higher in the summer and winter seasons when temperatures are more extreme, and therefore, our revenues and Commodity Margin could be negatively impacted by relatively cool summers or mild winters. Additionally, a disproportionate amount of our total revenue is usually realized during our third fiscal quarter during the summer months. We expect this trend to continue in the future as U.S. demand for power generally peaks during this time.

Operating Heat Rate and Availability — 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 can result in a loss of that opportunity. We generally measure our fleet performance based on our operating Heat Rate and availability factors. 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 power generated, the lower our Heat Rate. The lower our operating Heat Rate compared to the Market Heat Rate, the more favorable the impact on our Commodity Margin.

Market Fundamentals

For much of the 1990’s, utilities invested relatively sparingly in new generating capacity. As a result, by the late 1990’s, many regional markets had low reserve margins and were in need of new capacity to meet growing power 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 U.S. In most regions, these capacity additions far outpaced the growth of demand, resulting in “overbuilt” markets, that is, 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. This surge of generation investment subsided after 2003. Recent investment in new generation capacity over the last several years has occurred, but on a smaller scale.

During 2009, the general supply and demand fundamentals were negatively impacted by the combination of recent new generation investment coming on line and a general decline in weather adjusted load year-over-year due to the economic recession. Lower weather adjusted demand and higher supply would, in a normal

 

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weather year, lead to higher reserve margins and lower Market Heat Rates. While Texas and California experienced very hot weather at certain times during 2009, which somewhat compensated for these fundamental demand shifts, this was not the case across the U.S. Although it appears that the load is now returning in several markets with the beginning of an economic recovery, it remains early in the recovery and it remains unclear from current data sources how our future supply and demand fundamentals will be impacted. Reserve margins by NERC region in 2009 for each of our segments are listed below:

 

West:

  

WECC

   28.2

Texas:

  

TRE

   15.8

Southeast:

  

SERC

   23.9

SPP

   14.7

North:

  

NPCC

   25.5

MRO

   21.8

RFC

   27.0

Lower natural gas prices represent one of the biggest factors impacting the power industry in 2009. Monthly average natural gas prices (NYMEX, Henry Hub) generally fluctuated between $6/MMBtu —$8/MMBtu in 2007 and $6/MMBtu — $13/MMBtu in 2008 with spikes during the months of April through July of $10/MMBtu — $13/MMBtu. In 2009, we experienced a significant decrease in monthly average natural gas prices from a high of $5.35/MMBtu in December 2009 to a low of $3.31/MMBtu in August 2009.

Natural gas prices in some parts of the country in 2009 were low enough that modern combined-cycle natural gas-fired generation became less expensive on a marginal basis than coal-fired generation. The result was that natural gas displaced coal as a less expensive generation resource resulting in what the industry describes as coal-to-gas switching. Owners of modern combined-cycle natural gas-fired fleets, like ours, experienced significantly increased production in the southeast and some other parts of the eastern U.S.

Although some of this lower pricing dynamic can certainly be attributed to the recent economic recession (power load and natural gas demand fell off with the economic recession even while new resources were coming on line), there is a growing school of thought that the availability of non-conventional natural gas supplies, in particular shale gas, could have a longer-term and more profound impact on natural gas markets. The U.S. Department of Energy estimates that shale gas production has the potential of 3 trillion to 4 trillion cubic feet per year and may be sustainable for decades with enough natural gas reserves to supply the U.S. for the next 90 years. Accordingly, there is an emerging view of potentially lower priced natural gas for the medium to long-term future.

In addition to the immediate effects of weather and lower priced natural gas on our supply and demand fundamentals, several other key factors, especially regulatory factors, are emerging that could impact the wholesale power market fundamentals. We believe that we will be favorably impacted by these factors based upon the characteristics of our power plant portfolio. These factors include, but are not limited to:

 

   

increased penetration of power generated from renewable sources;

 

   

increasing environmental pressures on generation, especially pressures on high GHG, NOx and Hg emitting resources. A significant portion of the capacities within the regions we operate include capacities from older, less efficient fossil-fuel power plants that emit much higher amounts of GHG, NOx and Hg which we anticipate will be more negatively impacted by future potential GHG or other

 

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air emission legislation. The estimated amounts of MW capacity for plants which are older than 50 years by NERC region are as follows:

 

West:

  

WECC

   3,981 MW

Texas:

  

TRE

   1,354 MW

Southeast:

  

SERC

   17,362 MW

SPP

   3,581 MW

North:

  

NPCC

   4,543 MW

MRO

   3,015 MW

RFC

   18,943 MW

 

   

an increasing focus in some markets, including California, on limiting the impact of using once-through cooling technology that can be harmful to aquatic life;

 

   

an increasing focus by utilities on demand side management – managing the absolute level and timing of power usage such as “smart grid” technologies that improve the efficiencies, dispatch usage and reliability of electric grids; and

 

   

increasingly onerous permitting requirements, including those in California, one of our major markets.

With the exception of demand side management, many of these trends are generally positive for the economic outlook of a modern, flexible natural gas-fired fleet. For a discussion of federal, state and regional legislative and regulatory initiatives and how they might affect us, see “— Governmental and Regulatory Matters.”

Ultimately, it is very difficult to predict the continued evolution of our markets due to the uncertainty of the following:

 

   

number of market participants buying and selling;

 

   

amount of power normally available in the market;

 

   

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

 

   

fluctuations in power demand due to weather and other factors;

 

   

cost of fuel used by generators, which could be impacted by the efficiency of generation technology and fluctuations in fuel supply or interruptions in natural gas transportation;

 

   

relative ease or difficulty of developing and constructing new power plants;

 

   

availability and cost of power transmission;

 

   

creditworthiness and other risks associated with counterparties;

 

   

bidding behavior of market participants;

 

   

regulatory and ISO guidelines and rules;

 

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structure of the commercial products transacted; and

 

   

ability to optimize the market’s mix of alternative sources of power such as renewable and hydroelectric power.

Hedging

We seek to actively manage the commodity price risk to our economic performance with a variety of tools, including the use of PPAs and other long-term contracts for the sale of both power and steam. We also pursue other long-term sales opportunities, as well as shorter term market transactions, including bilateral originated sales contracts, and purchase and sale of exchange-traded instruments. We actively monitor key commodity price risks such as Market Heat Rate and natural gas price exposure, as well as other risks related to the value of our generation such as regulatory capacity, REC and emission credit pricing. The relative quantity of our products sold under longer term contracts compared to the quantity subject to shorter term price fluctuations is determined by our need to manage our liquidity, the availability of forward product sales opportunities, and our view of the attractiveness of the pricing available for forward sales. It is our strategy to seek stronger bilateral relationships and longer term contracts with load serving entities that can benefit us and our customers.

We provide more detail on our hedging programs in “— Marketing, Hedging and Optimization Activities” below.

COMPETITION

Wholesale power generation is a capital-intensive, commodity-driven business with numerous industry participants. We compete against other independent power producers, power marketers or trading companies, including those owned by financial institutions, retail load aggregators, municipalities, retail power providers, cooperatives and regulated utilities to supply power and power-related products to our customers in major markets in the U.S. In addition, in some markets, we compete against some of our customers.

In less regulated markets, such as California and Texas, our natural gas-fired power plants compete directly with all other sources of power. Even though most new power plants are fueled by natural gas, the EIA estimates that in 2009 only 24% of the power generated in the U.S. was fueled by natural gas and that approximately 65% of power generated in the U.S. was still produced by coal and nuclear facilities, which generated approximately 45% and 20%, respectively. The EIA estimates that the remaining 11% of power generated in the U.S. was fueled by hydroelectric, fuel oil and other energy sources. 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 plants. Federal and state legislative and regulatory actions continue to change how our business is regulated. The federal government is expected to take action on climate change legislation, as well as other air pollutant emissions, and many states and regions in the U.S. have implemented or are considering implementing regulations to reduce GHG emissions. Although we cannot predict the ultimate effect any future climate change legislation or regulations could have on our business, as a clean energy provider, we believe that we are well positioned on a net basis for potential regulation of GHG emissions. We are actively participating in these debates at the federal, regional and state levels. For a further discussion of the environmental and other governmental regulations that affect us, see “— Governmental and Regulatory Matters.”

As environmental regulations continue to evolve, the proportion of power generated by natural gas and other low emissions resources is expected to increase in most markets. As a result, many of the existing coal-fired power plants will likely have to install costly emission control devices or limit their operations. Meanwhile, the federal government and many states are considering or have already mandated that certain percentages of power delivered to end users in their jurisdictions be produced from renewable resources, such as geothermal, wind and solar energy.

 

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Competition from other sources of power, such as nuclear energy and renewables, is expected to increase in the future. The combination of emerging air emissions regulations, federal and state financial incentives and RPS requirements for renewables are expected to result in increased investment in cleaner sources of generation, which could also cause some coal-fired power plants to be retired, thereby allowing a greater proportion of power to be produced by power plants fueled by natural gas, nuclear, wind, solar, hydroelectric, geothermal or other resources that have a less adverse environmental impact. Generation quantities from nuclear power plants and renewable sources are not available in the quantities needed to meet energy demand. There are permitting hurdles, long lead times and general resistance to nuclear generation and there are concerns over the reliability and adequacy of transmission infrastructure to transmit certain renewable generation from its source to where it is needed. Consequently, longer-term, natural gas is still needed as baseload and “back-up” generation.

We believe our ability to compete effectively in our environment will be substantially driven by the extent to which we are able to accomplish the following:

 

   

maintain excellence in operations;

 

   

achieve and maintain a lower cost of production, primarily by maintaining unit availability and efficiency;

 

   

benefit from future environmental regulation and legislation;

 

   

effectively manage and accurately assess our risk; and

 

   

provide reliable service to our customers.

MARKETING, HEDGING AND OPTIMIZATION ACTIVITIES

The majority of our marketing, hedging and optimization activities are related to risk exposures that arise from our ownership and operation of power plants. Most of the power generated by our power plants is sold, scheduled and settled by our energy marketing unit, which sells to entities such as utilities, municipalities and cooperatives, as well as to retail power 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 marketing, hedging and optimization activities. Our marketing, hedging and optimization activities endeavor to protect and enhance our Commodity Margin.

We are one of the largest consumers of natural gas in the U.S. having consumed approximately 650 Bcf (billion cubic feet) during 2009. We employ a variety of market transactions to satisfy most of our natural gas fuel requirements. We enter into long-term, short-term and spot natural gas purchase agreements, as well as storage and transport agreements, to achieve delivery flexibility and to enhance our optimization capabilities. We continually evaluate our natural gas needs, adjusting our natural gas position in an effort to minimize the delivered cost of natural gas, while adjusting for risk within the limitations prescribed in our commodity risk policy.

We are exposed to commodity price volatility in the markets in which our power plants operate. Natural gas prices and power prices are generally correlated in our two primary markets, California and Texas, because power plants using natural gas-fired technology tend to be the marginal or price-setting generation units in these regions. We actively seek to manage the commodity risks of our portfolio, using multiple strategies of buying and selling power or natural gas to manage our spark spread, or selling Heat Rate transactions. We use derivative instruments, which include physical commodity contracts and financial commodity instruments such as OTC and exchange traded swaps, futures, options, forward agreements and instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) for the purchase and sale of power, natural gas, and emission allowances to manage commodity price risk and to maximize the risk-adjusted returns from our power

 

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and natural gas assets. We also use interest rate swaps to manage the interest rate risk of our variable rate debt. We conduct these hedging and optimization activities within a structured risk management framework based on controls, policies and procedures. We monitor these activities through active and ongoing management, oversight, defined roles and responsibilities, and daily risk measurement and reporting. Additionally, we seek to manage the associated risks through diversification, by controlling position sizes, by using portfolio position limits and by entering into offsetting positions that lock in a margin.

Along with our portfolio of hedging transactions, we enter into power and natural gas positions that often act as hedges to our asset portfolio, but do not qualify as hedges under hedge accounting guidelines, such as commodity options transactions and instruments that settle on power price to natural gas price relationships (Heat Rate swaps and options). While our selling and purchasing of power and natural gas is mostly physical in nature, we also engage in marketing, hedging and optimization activities, particularly in natural gas, that are financial in nature.

While we enter into these transactions primarily to provide us with improved price and price volatility transparency, as well as greater market access, which benefits our hedging activities, we also are exposed to commodity price movements (both profits and losses) in connection with these transactions. These positions are included in and subject to our consolidated risk management portfolio position limits and controls structure. Changes in fair value of commodity positions that do not qualify for either hedge accounting or the normal purchase normal sale exemption are recognized currently in earnings in mark-to- market activity within operating revenues in the case of power transactions, and within fuel and purchased energy expense in the case of natural gas transactions.

We have VAR limits that govern the overall risk of our portfolio of power plants, energy contracts, financial hedging transactions and other contracts. Our VAR limits, transaction approval limits and other risk related controls, are dictated by our commodity risk policy which is approved by our Board of Directors and by our Risk Management Committee comprised of members of our senior management 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. While this policy limits our potential upside from hedging 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, 2009, we have economically hedged a substantial portion of our generation and natural gas portfolio mostly through power and natural gas forward physical and financial transactions for 2010; however, we remain susceptible to significant price movements for 2011 and beyond. By entering into these transactions, we are able to economically hedge a portion of our spark spread at pre-determined generation and price levels. Our future hedged status and marketing and optimization activities are subject to change as determined by our commercial operations group, Chief Risk Officer, Risk Management Committee of senior management 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 power plants are located in regional power markets where the greatest demand for power occurs during the summer months, which is our fiscal third quarter. Depending on existing contract obligations and forecasted weather and power demands, we may maintain either a larger or smaller open position on fuel supply and committed generation during the summer months in order to protect and enhance our Commodity Margin accordingly.

SEGMENT AND SIGNIFICANT CUSTOMER INFORMATION

See Note 18 of the Notes to Consolidated Financial Statements for a discussion of financial information by reportable segment and sales in excess of 10% of our annual consolidated revenues to one of our customers.

 

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DESCRIPTION OF OUR POWER PLANTS

LOGO

LOGO

 

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Power Plants in Operation at December 31, 2009

We operate 77 power plants, with an aggregate operating generation capacity of approximately 24,802 MW.

Natural Gas-Fired Fleet

Our natural gas-fired power plants utilize two types of design: 3,216 MW of simple-cycle combustion turbines and 20,861 MW of combined-cycle combustion turbines. Simple-cycle combustion turbines burn natural gas to spin a single turbine to generate power. A combined-cycle combusts as a simple-cycle and also uses the exhaust heat from the simple-cycle combustion to help create steam which can then spin a steam turbine. Simple-cycle turbines are easier to maintain, but combined-cycle turbines operate with much higher efficiency. Our “all in” Steam Adjusted Heat Rate for 2009 for the power plants we operate was 7,263 Btu/KWh which results in a power conversion efficiency of approximately 47%. The power conversion efficiency is a measure of how efficiently a fossil fuel power plant converts thermal energy to electrical energy. Our “all in” Heat Rate includes all fuel required to dispatch our power plants including “start-up” and “shut-down” fuel, as well as all non-steady state operations. Once our power plants achieve steady state operations, our combined-cycle power plants achieve an average power conversion efficiency of approximately 50%. Additionally, we also sell steam from our cogeneration power plants, which improves our power conversion efficiency in steady state operations from these power plants to an average of approximately 53%. Due to our modern combustion turbine fleet, our power conversion efficiency is significantly better than that of older technology natural gas-fired power plants and coal-fired power plants, which typically have power conversion efficiencies that range from 31% to 36%.

Each of our power plants currently in operation is capable of producing power for sale to a utility, other third-party end user or an intermediary such as a marketing company. At some of our power plants we also produce thermal energy (primarily steam and chilled water), which can be sold to industrial and governmental users.

Our natural gas fleet is relatively young with a weighted average age, based upon MW capacities in operation, of approximately eight years. Taken as a portfolio, our natural gas power plants are among the most efficient in converting natural gas to power and emit far fewer pollutants than most typical utility fleets. The age, scale, efficiency and cleanliness of our power plants is a unique profile in the independent power sector.

The majority of the combustion turbines in our fleet are one of two technologies: GE 7FA or Siemens 501FD turbines. We maintain our fleet through a regular and rigorous maintenance program. As units reach certain targets recommended by the original equipment manufacturer, which are typically based upon service hours, we perform the maintenance that is required for that unit at that stage in its life. Our large fleet of similar technologies has enabled us to build significant technical and engineering experience with these units. We leverage this experience by performing much of our major maintenance ourselves with our Turbine Maintenance Group subsidiary.

Geothermal

Our Geysers Assets are a 725 MW fleet of 15 operating power plants in northern California. Geothermal power is considered a renewable energy because the steam harnessed to power our turbines is produced inside the Earth and does not require burning fuel. The steam is produced below the Earth’s surface from reservoirs of hot water, both naturally occurring and injected. The steam is piped directly from the underground production wells to the power plants and used to spin turbines to make power. For the past nine consecutive years, our Geysers Assets have continued to generate approximately 6 million MWh per year. Unlike other renewable resources such as wind or sunlight, which depend on intermittent sources to generate power, making them less reliable, geothermal power provides a consistent source of energy as evidenced by our Geysers Assets’ availability record of 97% in 2009.

We inject water back into the steam reservoir, which extends the useful life of the resource and helps to maintain the output of our Geysers Assets. The water we inject comes from the condensate associated with the steam extracted to generate power, wells and creeks, as well as water purchase agreements for reclaimed

 

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wastewater from the City of Santa Rosa Recharge Project and from Lake County. We currently receive an average of 15 million gallons of reclaimed wastewater a day which is injected into the steam reservoir to replenish the natural steam withdrawn for the production of power. As a result, steam flow decline rates have become very small. We expect that, as a result of the water injection program, the reservoir at our Geysers Assets will be able to supply economic quantities of steam for the foreseeable future.

We periodically obtain independent geothermal studies to help us assess the economic life of our geothermal reserves. Our most recent independent geothermal reserve study was conducted in 2006. Our evaluations of our geothermal reserves, including our review of any applicable independent studies conducted, indicate that our Geysers Assets should continue to supply sufficient steam to generate positive cash flows at least through 2050. In reaching this conclusion, our evaluation, consistent with the 2006 study, assumes that defined “proved reserves” are those quantities of geothermal energy which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions, operating methods, and government regulations. We used as our “given date forward” our projected schedule of development, operation and investment for the period 2006 to 2050.

We lease the geothermal steam fields from which we extract steam for our Geysers Assets. We have leasehold mineral interests in 110 leases comprising approximately 29,019 acres of federal, state and private geothermal resource lands in The Geysers region of northern California. Our leases cover one contiguous area of property that comprises approximately 45 square miles in the northwest corner of Sonoma County and southeast corner of Lake County. The approximate breakout by volume of steam removed under the above leases for the year ended 2009 is:

 

   

29% related to leases with the federal government via the Minerals Management Service,

 

   

27% related to leases with the California State Lands Commission, and

 

   

44% related to leases with private landowners/leaseholders.

In general, our geothermal leases grant us 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 on a monthly basis from 10 to 31 days (depending upon the lease terms) following the close of the production month. Such royalties and other payments are payable to landowners, state and federal agencies and others, and vary widely as to the particular lease. In general, royalties payable are calculated based upon a percentage of total gross revenue received by us associated with our geothermal leases. Each lease’s royalty calculation is based upon its percentage of revenue as calculated by its steam generated to the total steam generated by our Geysers Assets as a whole.

Our geothermal leases are generally for initial terms varying from 10 to 20 years or for so long as geothermal resources are produced and sold. A few of our geothermal leases were signed in excess of 30 years ago. Our federal leases are, in general, for an initial 10-year period with renewal clauses for an additional 40 years for a maximum of 50 years. The 50-year term expires in 2024 for the majority of our federal leases. However, our federal leases allow for a preferential right to renewal for a second 40-year term on such terms and conditions as the lessor deems appropriate if, at the end of the initial 40-year term, geothermal steam is being produced or utilized in commercial quantities. The majority of our other leases run through the economic life of our Geysers Assets and provide for renewals so long as geothermal resources are being produced or utilized, or are capable of being produced or utilized, in commercial quantities from the leased land or from land unitized with the leased land. Although we believe that we will be able to renew our leases through the economic life of our Geysers Assets on terms that are acceptable to us, it is possible that certain of our leases may not be renewed, or may be renewable only on less favorable terms.

 

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In addition, we hold 40 geothermal leases comprising approximately 43,840 acres of federal geothermal resource lands in the Glass Mountain area in northern California, which is separate from The Geysers region. Four test production wells were drilled prior to our acquisition of these leases and we have drilled one test well since their acquisition, which produced commercial quantities of steam during flow tests. However, the properties subject to these leases have not been developed and there can be no assurance that these leases will ultimately be developed. We are currently involved in litigation concerning our Glass Mountain leases and expect further developments related to this litigation in 2010. See Note 17 of the Notes to Consolidated Financial Statements for a description of litigation relating to our Glass Mountain area leases.

Table of Operating Power Plants and Projects Under Advanced Development

Set forth below is certain information regarding our operating power plants and projects under advanced development as of December 31, 2009.

 

SEGMENT / Power Plant

  NERC
Region
  U.S. State or
Canadian
Province
  Technology   Calpine
Interest
Percentage
    Calpine Net
Interest
Baseload
(MW)(1)(3)
  Calpine Net
Interest
With
Peaking
(MW)(2)(3)
  2009
Total
MWh
Generated(4)

WEST

             

Geothermal

             

McCabe #5 & #6

  WECC   CA   Geothermal   100   78   78   689,757

Ridge Line #7 & #8

  WECC   CA   Geothermal   100   69   69   589,538

Calistoga

  WECC   CA   Geothermal   100   66   66   493,338

Eagle Rock

  WECC   CA   Geothermal   100   66   66   524,822

Quicksilver

  WECC   CA   Geothermal   100   53   53   407,495

Cobb Creek

  WECC   CA   Geothermal   100   52   52   425,813

Lake View

  WECC   CA   Geothermal   100   52   52   402,385

Sulphur Springs

  WECC   CA   Geothermal   100   51   51   420,978

Socrates

  WECC   CA   Geothermal   100   50   50   394,322

Big Geysers

  WECC   CA   Geothermal   100   48   48   484,393

Grant

  WECC   CA   Geothermal   100   43   43   341,975

Sonoma

  WECC   CA   Geothermal   100   42   42   299,430

West Ford Flat

  WECC   CA   Geothermal   100   24   24   222,485

Aidlin

  WECC   CA   Geothermal   100   17   17   144,098

Bear Canyon

  WECC   CA   Geothermal   100   14   14   108,608

Natural Gas-Fired

             

Delta Energy Center

  WECC   CA   Natural Gas   100   835   857   5,032,618

Pastoria Energy Center

  WECC   CA   Natural Gas   100   750   729   4,979,649

Rocky Mountain Energy Center

  WECC   CO   Natural Gas   100   479   621   3,543,289

Hermiston Power Project

  WECC   OR   Natural Gas   100   547   616   3,466,313

Metcalf Energy Center

  WECC   CA   Natural Gas   100   564   605   2,797,458

Sutter Energy Center

  WECC   CA   Natural Gas   100   542   578   2,315,457

Los Medanos Energy Center

  WECC   CA   Natural Gas   100   506   560   3,391,651

South Point Energy Center

  WECC   AZ   Natural Gas   100   520   530   2,076,629

Blue Spruce Energy Center

  WECC   CO   Natural Gas   100     310   419,361

Los Esteros Critical Energy Facility

  WECC   CA   Natural Gas   100     188   73,098

Gilroy Energy Center

  WECC   CA   Natural Gas   100     141   59,523

Gilroy Cogeneration Plant

  WECC   CA   Natural Gas   100   117   128   262,270

King City Cogeneration Plant

  WECC   CA   Natural Gas   100   120   120   629,617

Pittsburg Power Plant

  WECC   CA   Natural Gas   100   64   64   125,190

Greenleaf 1 Power Plant

  WECC   CA   Natural Gas   100   50   50   223,474

Greenleaf 2 Power Plant

  WECC   CA   Natural Gas   100   49   49   234,211

Wolfskill Energy Center

  WECC   CA   Natural Gas   100     48   19,186

Yuba City Energy Center

  WECC   CA   Natural Gas   100     47   31,083

Feather River Energy Center

  WECC   CA   Natural Gas   100     47   27,255

Creed Energy Center

  WECC   CA   Natural Gas   100     47   12,283

Lambie Energy Center

  WECC   CA   Natural Gas   100     47   13,696

Goose Haven Energy Center

  WECC   CA   Natural Gas   100     47   11,791

Riverview Energy Center

  WECC   CA   Natural Gas   100     47   18,471

King City Peaking Energy Center

  WECC   CA   Natural Gas   100     44   16,316

Watsonville (Monterey) Cogeneration Plant

  WECC   CA   Natural Gas   100   29   29   153,505

Agnews Power Plant

  WECC   CA   Natural Gas   100   28   28   150,060

Otay Mesa Energy Center(5)

  WECC   CA   Natural Gas   100   513   608   774,104
                   

Subtotal

          6,438   7,910   36,806,995

 

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SEGMENT / Power Plant

  NERC
Region
  U.S. State or
Canadian
Province
  Technology   Calpine
Interest
Percentage
    Calpine Net
Interest
Baseload
(MW)(1)(3)
  Calpine Net
Interest
With
Peaking
(MW)(2)(3)
  2009
Total
MWh
Generated(4)

TEXAS

             

Freestone Energy Center

  TRE   TX   Natural Gas   100   1,038   994   3,263,701

Deer Park Energy Center

  TRE   TX   Natural Gas   100   799   970   5,686,340

Baytown Energy Center

  TRE   TX   Natural Gas   100   740   800   3,893,026

Pasadena Power Plant

  TRE   TX   Natural Gas   100   753   771   2,929,281

Magic Valley Generating Station

  TRE   TX   Natural Gas   100   662   692   3,057,649

Brazos Valley Power Plant

  TRE   TX   Natural Gas   100   508   594   2,374,891

Channel Energy Center

  TRE   TX   Natural Gas   100   463   608   2,645,794

Corpus Christi Energy Center

  TRE   TX   Natural Gas   100   426   500   2,316,051

Texas City Power Plant

  TRE   TX   Natural Gas   100   400   453   1,451,085

Clear Lake Power Plant

  TRE   TX   Natural Gas   100   344   400   508,920

Hidalgo Energy Center

  TRE   TX   Natural Gas   78.5   392   374   1,560,341

Freeport Energy Center(6)

  TRE   TX   Natural Gas   100   210   236   1,404,067
                   

Subtotal

          6,735   7,392   31,091,146

SOUTHEAST

             

Broad River Energy Center

  SERC   SC   Natural Gas   100     847   351,868

Morgan Energy Center

  SERC   AL   Natural Gas   100   720   807   4,250,780

Decatur Energy Center

  SERC   AL   Natural Gas   100   782   795   3,043,345

Columbia Energy Center

  SERC   SC   Natural Gas   100   455   606   43,660

Carville Energy Center

  SERC   LA   Natural Gas   100   449   501   2,443,567

Santa Rosa Energy Center

  SERC   FL   Natural Gas   100   235   225   168,387

Hog Bayou Energy Center

  SERC   AL   Natural Gas   100   235   237   262,423

Pine Bluff Energy Center

  SERC   AR   Natural Gas   100   184   215   1,340,696

Oneta Energy Center

  SPP   OK   Natural Gas   100   980   1,134   2,981,783

Osprey Energy Center

  FRCC   FL   Natural Gas   100   537   599   2,459,755

Auburndale Peaking Energy Center

  FRCC   FL   Natural Gas   100     117   24,167
                   

Subtotal

          4,577   6,083   17,370,431

NORTH

             

Riverside Energy Center

  MRO   WI   Natural Gas   100   518   603   974,899

RockGen Energy Center

  MRO   WI   Natural Gas   100     503   147,930

Mankato Power Plant

  MRO   MN   Natural Gas   100   280   375   337,542

Westbrook Energy Center

  NPCC   ME   Natural Gas   100   537   537   2,485,501

Kennedy International Airport Power Plant

  NPCC   NY   Natural Gas   100   110   121   503,650

Bethpage Energy Center 3

  NPCC   NY   Natural Gas   100   60   80   288,799

Bethpage Power Plant

  NPCC   NY   Natural Gas   100   55   56   108,362

Bethpage Peaker

  NPCC   NY   Natural Gas   100     48   37,662

Stony Brook Power Plant

  NPCC   NY   Natural Gas   100   45   47   251,868

Whitby Cogeneration(7)

  NPCC   ON   Natural Gas   50   25   25   86,057

Greenfield Energy Centre(8)

  NPCC   ON   Natural Gas   50   422   519   1,326,829

Zion Energy Center

  RFC   IL   Natural Gas   100     503   112,894
                   

Subtotal

          2,052   3,417   6,661,993
                   

Total operating power plants (77)

          19,802   24,802   91,930,565
                   

Projects under advanced development

             

Russell City Energy Center

  WECC   CA   Natural Gas   65   362   390   n/a

Los Esteros Critical Energy Facility (Upgrade)

  WECC   CA   Natural Gas   100   120   120   n/a
                 

Total operating power plants and projects

          20,284   25,312  
                 

 

(1) Natural gas-fired fleet capacities are derived on as-built as-designed outputs, including upgrades, based on site specific annual average temperatures and average process steam flows for cogeneration power plants, as applicable. Geothermal capacities are derived from historical generation output and steam reservoir modeling under average ambient conditions (temperatures and rainfall).

 

(2) Natural gas-fired fleet peaking capacities are primarily derived on as-built as-designed peaking outputs based on site specific average summer temperatures and include power enhancement features such as heat recovery steam generator duct-firing, gas turbine power augmentation, and/or other power augmentation features. For certain power plants with definitive contracts, capacities at contract conditions have been included.

 

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(3) These outputs do not factor in the typical MW loss and recovery profiles over time, which natural gas-fired turbine power plants display associated with their planned major maintenance schedules.

 

(4) MWh generation is shown here as our net operating interest.

 

(5) Otay Mesa Energy Center began commercial operation on October 3, 2009, and is an unconsolidated subsidiary (see Note 4 of the Notes to Consolidated Financial Statements).

 

(6) Freeport Energy Center is owned by us; however, it is contracted and operated by The Dow Chemical Company.

 

(7) We hold a less-than-majority owned (50%) equity interest in Whitby Cogeneration; however, it is operated by Atlantic Packaging Products Ltd., and is an unconsolidated subsidiary (see Note 4 of the Notes to Consolidated Financial Statements).

 

(8) We hold a 50% joint venture interest in Greenfield Energy Centre; however, it is operated by a third party, and is an unconsolidated subsidiary (see Note 4 of the Notes to Consolidated Financial Statements).

We provide operations and maintenance services for all but three 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 natural gas pipelines. We also supervise maintenance, materials purchasing and inventory control, manage cash flow, train staff and prepare operations and maintenance manuals for each power plant that we operate. As a power plant develops an operating history, we analyze its operation and may modify or upgrade equipment, or adjust operating procedures or maintenance measures to enhance the power plant’s reliability or profitability.

Certain power plants 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 power (and, if applicable, thermal energy and capacity) produced by such power plants and generally provides that the obligations to pay interest and principal on the loans and are secured solely by the capital stock or partnership interests, physical assets, contracts and/or cash flows attributable to the entities that own the power plants. 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 power plants. However, defaults under some project financings may result in cross-defaults to certain of our other debt, and under certain of our debt instruments, including our First Lien Credit Facility and First Lien Notes. Acceleration of the maturity of a project financing following a default may also result in a cross-acceleration of such other debt.

Substantially all of the power plants in which we have an interest are located on sites which we own or lease on a long-term basis.

Projects Under Advanced Development and Planned Upgrades at December 31, 2009

The development and construction of power generation projects involves numerous elements, including evaluating and selecting development opportunities, designing and engineering the project, obtaining PPAs, acquiring necessary land rights, permits and fuel resources, obtaining financing, procuring equipment and managing construction. 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.

Russell City Energy Center — This is a proposed 600 MW, natural gas-fired power plant to be located in Hayward, California. In September 2006, we sold a 35% equity interest in the project to Aircraft Services for approximately $44 million and Aircraft Services’ obligation to post a $37 million letter of credit. We own the

 

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remaining 65% interest. Under the LLC agreement with Aircraft Services, Aircraft Services’ equity is to be applied toward completion of development and construction of the power plant, and Aircraft Services is also to provide related credit support for the project.

Russell City Energy Center remains under advanced development. 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. The PPA was amended in 2008 and was approved by the CPUC on April 16, 2009. On February 4, 2010, we received the PSD air permit, the final permit necessary, to begin construction of our Russell City Energy Center. Russell City Energy Center is intended to become the first power plant in the U.S. with a federal limit on GHG emissions, and will be designed to operate in a way that produces 25% fewer GHG emissions than the CPUC standard. The power plant will use 100% reclaimed water from the City of Hayward’s Water Pollution Control Facility for cooling and boiler makeup, which will prevent nearly four million gallons of wastewater per day from being discharged into the San Francisco Bay. We hope to complete financing and break ground for this new state-of-the-art power plant during 2010 with commercial operations scheduled to begin in 2013. Upon completion, this project would bring on line approximately 362 MW of net interest baseload capacity (390 MW with peaking capacity) representing our 65% interest.

Los Esteros Critical Energy Facility Upgrade — We and PG&E negotiated a new agreement, subject to regulatory approval, to replace the existing CDWR contract and facilitate the upgrade of our Los Esteros Critical Energy Facility from a 188 MW simple-cycle generation power plant to a 308 MW combined-cycle generation power plant. In addition to the increase in capacity, the upgrade will increase the efficiency and environmental performance of the power plant by lowering the operating Heat Rate. While the upgrade is under construction, we will provide capacity to PG&E from our Gilroy Cogeneration Plant. Upon completion of the upgrade, PG&E will purchase all of the capacity from our Los Esteros Critical Energy Facility for a term of ten years.

Turbine Upgrades — We are in the process of upgrading certain of our Siemens natural gas-fired turbines to increase our generation capacity by approximately 180 MW and operating efficiencies, which began in the fourth quarter of 2009 and are scheduled through 2014. We have also upgraded the steam turbines at our McCabe and Ridgeline geothermal power plants that improved the overall turbine efficiency. We have two additional steam turbine upgrades scheduled for 2011 and 2012, and are considering others.

ENVIRONMENTAL PROFILE

A founding principle of our Company at its inception in 1984 and continuing today is our commitment to the generation of power in a cost effective and environmentally responsible manner. To achieve this we have assembled the largest fleet of combined-cycle natural gas-fired power plants and the largest fleet of geothermal power plants in North America.

We are committed to maintaining our fleet of clean, cost-effective and efficient power plants and to reducing the environmental impact through water conservation and the reduction of CO2 emissions as well as emissions of other air pollutants. We are also committed to supporting policymakers on legislation to reduce CO2 emissions and other air emission policies, and have been actively involved in the discussions and debates within the industry and with policymakers as GHG policies are developed. We were involved in the development and enactment of Assembly Bill 32 in California, and we have publicly supported the Regional Greenhouse Gas Initiative (known as RGGI) in the northeast. In 2006, we were one of only two power generating companies to file a brief of amicus curiae in support of the petitioners in the landmark case of Commonwealth of Massachusetts, et al. v. U.S. Environmental Protection Agency, in which the U.S. Supreme Court held that CO2 was a pollutant potentially subject to the CAA. Our environmental record has been widely recognized: we are an EPA Climate Leaders Partner with a stated goal to reduce GHG emissions, 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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Natural Gas-Fired Generation — Our fleet consumes significantly less fuel to generate power than conventional boiler/steam turbine power plants and emits less air pollution into the environment per MWh of power produced as compared to coal-fired or oil-fired power plants. All of our natural gas-fired power plants have air emissions controls and most have selective catalytic reduction to further reduce emissions of nitrogen oxides, a precursor of atmospheric ozone. In addition, we have implemented a program of proprietary operating procedures to reduce natural gas consumption and lower air pollutant emissions per MWh of power generated. The table below summarizes approximate air pollutant emission rates from our natural gas-fired power plants compared to the average emission rates from U.S. coal-, oil- and gas-fired power plants as a group, based on the most recent statistics available to us.

 

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

Air Pollutants

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

Nitrogen Oxide, NOx

   2.54    0.13    94.9% less

Acid rain, smog and fine particulate formation

        

Sulfur Dioxide, SO2

   5.90    0.0047    99.9% less

Acid rain and fine particulate formation

        

Mercury Compounds(3)

   0.000030       100.0% less

Neurotoxin

        

Carbon Dioxide, CO2

   1,873    869    53.6% less

Principal GHG—contributor to climate change

        

 

(1) The average U.S. coal-, oil- and natural gas-fired power plant’s emission rates were obtained from the U.S. Department of Energy’s Electric Power Annual Report for 2008. Emission rates are based on 2008 emissions and net generation. The U.S. Department of Energy has not yet released 2009 information.

 

(2) Our natural gas-fired power plant estimated emission rates are based on our 2008 emissions and power generation data from our natural gas-fired combined-cycle power plants (excluding combined heat and power plants) as measured under the EPA reporting requirements.

 

(3) The U.S. coal-, oil- and natural gas-fired power plant air emissions of mercury compounds were obtained from the U.S. EPA Toxics Release Inventory for 2008. Emission rates are based on 2008 emissions and net generation from U.S. Department of Energy’s Electric Power Annual Report for 2008.

Geothermal Generation — Our 725 MW fleet of geothermal power plants utilizes a natural, clean and renewable energy source, steam from the Earth’s interior, to generate power. Since these power plants do not burn fossil fuel, they are able to produce power with negligible CO2 (the principal GHG), NOx and SO2 emissions. Compared to the average U.S. coal-, oil- and gas-fired power plant, our Geysers Assets emit 99.9% less NOx, 100% less SO2 and 94.8% less CO2.

There are 18 active geothermal power plants located in The Geysers region of northern California. We own and operate 15 of them. We recognize the importance of our Geysers Assets and we are committed to extending and 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 by the Earth’s heat into steam for power production.

Climate Change and CO2 Emissions — Our combined-cycle, natural gas-fired power plants emit less than half the CO2 per unit of power generated than a traditional coal-fired power plant. Although our Geysers Assets

 

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do produce some emissions due to a natural geological process, the compliance burden compared to both coal-fired and natural gas-fired generation is expected to be minimal. In 2008, our emissions of CO2 amounted to about 39 million tons. For a more complete discussion of federal, state and regional climate change legislative and regulatory initiatives and how they might affect us, see “— Governmental and Regulatory Matters — Climate Change and Related Legislation and Regulations.”

Water Conservation and Reclamation — We have also invested substantially in technologies and systems that reduce the impact of our operations on water as a natural resource:

 

   

We receive and inject an average of approximately 15 million gallons of reclaimed wastewater per day into the geothermal steam reservoir at The Geysers where the water is naturally heated by the Earth, creating additional steam to fuel our Geysers Assets. Approximately 11 million gallons is received from the Santa Rosa Geysers Recharge Project, developed by us and the City of Santa Rosa, which was previously being discharged into the Russian River and we receive, on average, approximately 4 million gallons a day from The Lake County Recharge Project from Lake County.

 

   

We use cooling towers, which utilize a closed-circuit water cooling system, or air cooled condensers to condense steam and do not employ once-through water cooling. Once-through water cooling, unlike our towers and condensers, uses large quantities of water from adjacent waterways, negatively impacting aquatic life.

 

   

Through separate agreements with several municipalities where we use cooling towers, we use treated wastewater for cooling at several of our power plants. This eliminates the need to consume valuable surface and/or groundwater supplies, in the amount of three to four million gallons per day for an average power plant.

GOVERNMENTAL AND REGULATORY MATTERS

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 plants. Federal and state legislative and regulatory actions continue to change how our business is regulated. Such changes could have positive or negative impacts on our existing business.

Climate Change and Related Legislation and Regulations

As a clean energy provider, we believe that we are well positioned on a net basis for potential regulation of GHG emissions. The federal government is expected to take action on climate change legislation, and many states and regions in the U.S. have implemented or are considering implementing regulations to reduce GHG emissions. Although we cannot predict the ultimate effect any future climate change legislation or regulations could have on our business, we believe we face a lower compliance burden than some of our competitors due to the relatively low GHG emission rates of our fleet.

Proposed Federal Climate Change Legislation

On June 26, 2009, the U.S. House of Representatives passed “The American Clean Energy and Security Act of 2009,” a climate change and clean energy bill. The legislation includes, among other provisions:

 

   

An economy-wide carbon cap-and-trade program that:

 

  i. sets reduction targets for carbon emissions from capped sources in several sectors of the economy, including the power sector, starting at a 3% reduction from 2005 levels by 2012, increasing to 17% by 2020, 42% by 2030 and 83% by 2050;

 

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  ii. starts in 2012 for the power sector and establishes the point of regulation at the power plant;

 

  iii. distributes 85% of emissions allowances for free, with 35.85% going to the power sector, including 1.5% to eligible generation facilities with qualifying long-term power and steam sales contracts;

 

  iv. requires an auction of the remaining 15% of emissions allowances with the proceeds of such auctions distributed to low- and moderate-income families; and

 

  v. delegates authority to FERC to regulate the cash market in emissions allowances and offsets and to the CFTC to regulate the associated derivatives market.

 

   

A federal energy efficiency and renewable electricity standard which requires retail electricity suppliers to meet the needs of a specific percentage of their load from renewable energy resources and electricity savings.

If this bill were to become law, we would have the obligation to obtain emissions allowances for the operation of our fossil-fuel power plants. While we expect the costs to acquire allowances to be a factor that will impact the market price of power, there can be no assurance that market price will fully reflect these costs. With respect to our existing long-term steam and power contracts under which we would not be able to recover costs to acquire allowances from our customers, the bill allocates a pool of free allowances to generators with qualifying contracts to mitigate such costs. However, there can be no assurance there will be a sufficient number of free allowances in the pool to fully cover emissions related to generation under such contracts.

On November 5, 2009, the Senate Environment and Public Works Committee passed climate change legislation entitled the Clean Energy Jobs and American Power Act. The legislation is similar to the legislation passed in the House of Representatives, though its focus is primarily on climate change, not energy. The legislation sets reduction targets for carbon emissions of 20% by 2020; distributes a substantial portion of emission allowances for free, though a lower amount than in The American Clean Energy and Security Act of 2009, with some emission allowances going to the power sector, including to eligible power plants with qualifying long-term power and steam sales contracts; requires an auction of 25% of emissions allowances with the proceeds dedicated for consumer protections and deficit reduction; states that there will be one regulatory body that has market oversight authority; directs the administrator of the EPA to establish an incentive payment program that promotes generation projects that have lower GHG emissions; and provides grants for research and development for advanced natural gas-fired generation technology.

The Senate is expected to continue considering legislation addressing climate change; however, it is becoming less likely that such legislation will be enacted in 2010. Although we cannot predict the effect and ultimate content of final climate change legislation and regulations, if any, on our business, we continue to monitor and actively participate in the process where we anticipate an impact on our business.

Federal Regulation of GHG under Existing Law

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, and due to this ruling, the EPA is moving forward to regulate GHG emissions pursuant to its existing authority under the CAA. On December 7, 2009, the EPA determined that current and projected concentrations of the six key GHG emissions endanger the public health and welfare of current and future generations. Additionally, on September 30, 2009, the EPA announced a proposal (the “Tailoring Rule”) to require facilities emitting over 25,000 tons per year of GHG emissions to undergo major new source review when such facilities make modifications that would increase their GHG emissions by an additional 10,000 to 25,000 tons. Such modifications, or new construction, would be subject to the EPA’s prevention of significant deterioration rules and subject to best available control technology for GHGs, as well as public review and notice. The EPA expects to finalize the proposed rule by the end of March 2010, and if finalized, these requirements would be applicable to power generators such as us.

 

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The federal courts have also been active on GHG emission issues. Recent federal court decisions are divided as to whether large emitters of GHGs may be sued under common law theories of nuisance and negligence.

On September 21, 2009, the Second Circuit issued a ruling in State of Connecticut, et al. v. American Electric Power Company Inc., et al., reversing a lower court’s dismissal of two public nuisance claims filed by various states, municipalities and private entities against operators of coal-fired power plants. Plaintiffs argued that the power plant defendants contribute to global warming by emitting 650 million tons per year of CO2 and these emissions are causing and will continue to cause serious harms affecting human health and natural resources. The lower court held that plaintiffs’ claims presented a non-legal political question and dismissed the complaints. The Second Circuit vacated the lower court’s ruling and remanded the cases to the lower court for further proceedings. On October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit made a similar ruling, finding that private property owners may bring claims of public and private nuisance against GHG-emitting oil and chemical companies.

Conversely, on September 30, 2009, in the case Native Village of Kivalina v. ExxonMobil, a federal district court in California sided with the defendants, 24 oil, energy and utility companies against the Village of Kivalina, a small, self-governing tribe of Inupiat people who reside north of the Arctic Circle. The residents of Kivalina had sued the defendants for damages under federal nuisance law arguing that, as a result of global warming, Kivalina is subject to coastal storm waves and surges. The court ruled in favor of the defendants finding that the plaintiff’s global warming claim was based upon the emission of GHGs from innumerable sources located throughout the world affecting the entire planet and its atmosphere and that no federal standards limit the discharge of GHGs.

We cannot predict the outcome of these cases or what impact the precedent of these cases could have on our business. However, these contrasting outcomes show that the federal courts are sharply divided over climate change litigation; thus, increasing the likelihood that Congress will take action on GHG regulations at some point in the future.

Regional and State Climate Change Activities

Several states and regional organizations are developing, or already have developed, state-specific or regional initiatives to reduce GHG emissions through mandatory programs. The most advanced programs include the RGGI in the northeast states and California’s implementation of its own GHG policy pursuant to Assembly Bill 32, as well as its RPS. The evolution of these programs could have a material impact on our business.

On January 1, 2009, ten northeast and mid-Atlantic states implemented a cap-and-trade program, RGGI, that affects our power plants in Maine, New York and New Jersey (together emitting about 1.8 million tons of CO2 annually). RGGI caps regional CO2 emissions and requires generators to acquire one allowance for every ton of CO2 emitted over a three-year compliance period. Apart from state-specific set-asides and other factors, the vast majority of the region’s CO2 allowances are distributed to the market via public auction. RGGI auctions have recently cleared at approximately $2.00 per ton. We are required to purchase allowances by buying them in RGGI public auctions or via the secondary market, or by investment in qualified offsets, to cover CO2 emissions from our power plants in the RGGI region. We received an allocation from New York’s long-term contract set-aside pool to cover some of the CO2 emissions attributable to our PPAs at both the Kennedy International Airport Power Plant and Stony Brook Power Plant. We do not anticipate any significant business impact from RGGI, given the efficiency of our power plants in RGGI states.

California’s 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 the state to return to 1990 emission levels by 2020. As part of Assembly Bill 32 implementation, California’s cap-and-trade program is slated to begin in 2012. Other GHG regulatory policies promulgated under Assembly Bill 32 are ongoing. California regulators and industry participants continue to work on the regulations to implement Assembly Bill 32. We are an active participant in the development of these regulations.

 

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California is in the process of determining how allowances will be allocated under its cap-and-trade program. A committee of outside academic advisors to the California Air and Resources Board, or CARB, has recommended that all allowances be auctioned. CARB will take the committee’s recommendation under advisement and will develop and approve its allowance allocation regulations over the course of 2010. Under a full auction methodology, certain of our contracts may not allow GHG costs to be passed through to the customers.

Our other power plants may also become subject to state or regional CO2 compliance requirements. The Western Climate Initiative, launched in February 2007, is a collaboration of seven U.S. Governors and four Canadian Premiers to reduce GHG emissions and could affect our power plants in California, Arizona, Oregon and Ontario. The Western Climate Initiative’s goal is to establish a multi-sector cap-and-trade program effective for most sectors of the economy by 2012 and regulation of the transportation sector by 2015. Some partner states, such as Arizona, have indicated their participation will be delayed or dependent on further economic analysis and recovery. To date, California is the only state that has reaffirmed its commitment to its participation and a 2012 start. In the Midwest, our power plants in Illinois, Wisconsin and Minnesota may become subject to CO2 compliance requirements depending on the ultimate outcome of the Midwestern Greenhouse Gas Reduction Accord. This regional planning effort is not expected to lead to binding regulations; however, compliance requirements will be subject to prospective individual regulatory and/or legislative action by the participating states.

Renewable Portfolio Standards

Policymakers have been considering RPS at the federal and state level. Generally, a RPS requires each retail seller of electricity to include in its resource portfolio (the resources procured by the retail seller to supply its retail customers) a certain amount of power generated from renewable energy resources by a certain date. Although there is currently no national RPS, President Obama has stated his goal is to have 10% of the nation’s electricity provided from renewable sources by 2012, and 25% by 2025, and U.S. Congressional leaders have committed to pass legislation to enact a national RPS in this Congress. It is too early to determine whether or not the enactment of a national RPS will have a positive or negative impact on us. Depending on the RPS structure, an RPS could enhance the value of our existing Geysers Assets. However, an RPS would likely initially drive up the number of wind and solar resources, which could negatively impact the dispatch of our natural gas assets, primarily in Texas and California. Conversely, our natural gas power plants could benefit by providing complementary/back-up service for these intermittent renewable resources.

California is currently considering a range of options for a new and higher RPS. California’s existing RPS requires certain retail power providers to generate or procure 20% of the power they sell to retail customers from renewable resources by 2010. At the end of the 2009 California legislative session, the California state legislature passed a bill to increase the state’s RPS to 33% by 2020. The governor of California vetoed the bill, but, in a separate move, the governor signed an executive order directing CARB under its authority granted by Assembly Bill 32 to adopt regulations consistent with a 33% RPS by 2020. Implementation details of the executive order are yet to be determined; however, it directs CARB to adopt regulations by July 31, 2010. The executive order directed CARB to develop implementation details by January 1, 2010, a deadline which was not met. CARB is now actively working to release the initial draft regulation in late February or early March.

Currently, California does not allow RECs and power to be sold separately. The role of tradable renewable energy credits, or TRECs, in California’s RPS remains uncertain. TRECs are claims to the renewable aspect of the energy that is produced by a renewable resource and are traded separately from the underlying generic energy. The CPUC is considering whether to allow retail power providers to use TRECs to meet RPS requirements and what types of limits to place on their use in the event that they are allowed. We cannot predict at this time whether the CPUC will allow the use of TRECs or what impact, if any, TRECs could have on our business.

A number of additional states have a RPS in place. These include Maine, Minnesota, New York, Texas and Wisconsin. Individual programs vary widely. Maine has the most stringent RPS, requiring retail providers to supply no less than 30% of their needs with qualified renewable resources. Other states, such as Texas, have a

 

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capacity-based standard that requires a specific amount of new renewable generation to be installed by certain dates. Existing state-specific RPS requirements may change due to regulatory and/or legislative initiatives, and other states may consider implementing enforceable RPS in the future.

Other Environmental Regulations

Our power plants and the 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 may also 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.

Clean Air Act

The CAA provides for the regulation of air quality and air emissions, largely through state implementation of federal requirements. We believe that all of our operating power plants comply with federal and state performance standards mandated under the CAA. Several CAA programs that affect our power plants and/or our competitors are discussed below.

Section 185 Fees — Section 185 of the CAA requires major stationary sources of NOx and volatile organic compounds, or VOC(s), such as power plants and refineries, in areas that fail to attain the National Ambient Air Quality Standards, or NAAQS, for ozone by the attainment date to pay a fee to the state or in the absence of state action, the EPA. The fee was set by Congress in the CAA at $5,000 per ton of NOx or VOC (adjusted for inflation or approximately $8,750 per ton in 2008) and is payable on emissions that exceed 80% of each individual power plant’s baseline emissions, which were established in the year before the attainment date; however, the EPA is considering alternative baseline calculations. The fee will remain in effect until the designated area achieves attainment. We operate 13 power plants that are located within designated nonattainment areas in Texas, New York and Louisiana, which are subject to this fee. On January 5, 2010, the EPA issued guidance on developing fee programs required under Section 185 of the CAA. Texas issued a draft rulemaking to collect the fees in late 2009 and we provided comments on the draft in January 2010. We estimate that compliance with this fee could result in additional costs of approximately $3 million to $5 million on an annual basis and our financial statements include accruals for our estimated Section 185 fees. Our estimate is dependent upon a number of factors that could change in the future dependent upon, among other things: implementation by the states of guidance from the EPA, state rulemakings, the designation of nonattainment status, our number of power plants located in these areas and our level of NOx emissions.

Hazardous Air Pollutants — On October 22, 2009, the EPA signed a consent decree that was lodged in the U. S. District Court for the District of Columbia by the EPA in settlement of a suit brought by several environmental groups alleging that the EPA failed to promulgate final maximum achievable control technology emissions standards for hazardous air pollutants from coal- and oil-fired power plants, pursuant to Section 112(d) of the CAA, by the statutorily-mandated deadline. The consent decree requires the EPA to promulgate final maximum achievable control technology standards by November 2011 that will likely require mercury and acid gas control retrofits on marginal coal-fired power plants to be operational by 2014.

On November 16, 2009, the EPA issued a proposal to increase the NAAQS for SO2. The proposal seeks to replace the current annual and 24-hour standards with a new 1-hour standard at a level between 50 and 100 parts per billion. Final ruling is expected in June of 2010. We emit little SO2 and do not expect to experience significant operating costs, or retrofit obligations, from the new standards. Should coal-fired power plants in our regional markets be forced to retrofit or retire, the new standards could benefit our competitive position.

 

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Houston/Galveston Nonattainment — Pursuant to authority granted under the CAA, regulations adopted by the Texas Commission on Environmental Quality, or TCEQ, to attain the one-hour and eight-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 power plants that participate in this program, all of which received free NOx allowances based on historical operating profiles. At this time, our Houston-area power plants have sufficient NOx allowances to meet forecasted obligations under the program. However, the EPA revised downward the eight-hour NAAQS for ozone in 2008 from 0.080 parts per million (ppm) to 0.075 ppm. The EPA subsequently announced on September 16, 2009, that the protectiveness of this standard would be reconsidered and a new standard was proposed in December 2009 leading to the implementation of control measures as early as 2014 for existing and newly designated areas under the revised ozone standard. The dynamic nature of the ozone standard creates further uncertainty in the timing and nature of future controls, but should allowance shortfalls occur, we would be required to purchase NOx allowances or install emissions control equipment on certain power plants.

Acid Rain Program — As a result of the 1990 CAA amendments, the EPA established a cap-and-trade program for SO2 emissions from power plants throughout the U.S. Starting with Phase II of the program in 2000, a permanent ceiling (or cap) was set at 10 million tons per year, declining to 8.95 million tons per year by 2010. The EPA allocated SO2 allowances to power plants. 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 power plants placed into service before 1990. None of our power plants receive free SO2 allowances. Accordingly, we must purchase allowances to cover all SO2 emissions from our affected power plants 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.

Multi-Pollutant Programs — Pursuant to authority granted under the CAA, the EPA promulgated the Clean Air Interstate Rule, or CAIR, regulations in March 2005, applicable to 28 eastern states and the District of Columbia, to facilitate attainment of its ozone and fine particulates standards issued in 1997. When fully implemented, CAIR’s goal is to reduce SO2 emissions in these states by over 70%, and NOx emissions by over 60% from 2003 levels by 2015. CAIR establishes annual cap-and-trade programs for SO2 and NOx as well as a seasonal program for NOx. On July 11, 2008, a panel of the U.S. Court of Appeals for the D.C. Circuit invalidated CAIR, stating that the “EPA’s approach – region-wide caps with no state specific quantitative contribution determinations or emission requirements – is fundamentally flawed.” The court did not overturn the existing cap-and-trade program for SO2 reductions under the Acid Rain Program or the existing ozone season cap-and-trade program under the NOx State Implementation Plan Call. On September 25, 2008, the EPA petitioned the court for rehearing. On December 23, 2008, the court remanded CAIR without vacatur for the EPA to conduct further proceedings consistent with the July 11, 2008 opinion. As a result of the court’s decision, CAIR was left intact and went into effect as planned on January 1, 2009, for many of our power plants located throughout the eastern and central U.S. Due to favorable allowance allocations, particularly in Texas, we have a net surplus of annual NOx allowances and the net financial impact of the program to our operations will be positive. The court did not set a definitive deadline for re-promulgation of a new rule, but the EPA has indicated that it will be issuing a CAIR replacement rule proposal in April 2010. At this time, we cannot predict what impact this proposal will have on us, if any.

On February 4, 2010, bipartisan multi-pollutant legislation, the Clean Air Act Amendments of 2010, was introduced in the Senate. The legislation, which replaces the Clean Air Interstate Rule and the Clean Air Mercury Rule, sets forth new regulations for SO2, NOx and Hg calling for: 80% reduction in SO2 emissions by 2018; 53% reduction in NOx emissions by 2015; and reductions in Hg emission of at least 90% by 2015. It establishes nationwide trading programs for SO2 and NOx, and requires maximum achievable control technology for Hg reductions. While sponsors of the legislation hope to move this bill with comprehensive climate change and energy legislation, they also plan to push it independently if such legislation does not move forward this year. At this time, we are unsure of the timing for movement of this bill.

 

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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, for certain of our power plants. We are required to maintain a spill prevention control and countermeasure plan with respect to certain of our natural gas power plants. 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 establishes the underground injection control program that regulates the disposal of wastes by means of deep well injection. Although geothermal production wells, which are wells that bring steam to the surface, are exempt under the Energy Policy Act of 2005, or EPAct 2005, we use geothermal re-injection wells to inject reclaimed wastewater back into the steam reservoir, which are subject to this regulation. We believe that we are in material compliance with Part C of this Act.

Resource Conservation and Recovery Act

The Resource Conservation and Recovery Act, or RCRA, regulates the management of solid and hazardous waste. With respect to our solid waste disposal practices at our power plants and steam fields located in The Geysers region of northern California, 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

The Comprehensive Environmental Response, Compensation and Liability Act, or 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 filing of this Report, 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 a liability under CERCLA in the future.

Federal Regulation of Power

FERC Jurisdiction

Electric utilities have been highly regulated by the federal government since the 1930s, principally under the Federal Power Act, or FPA, and PUHCA 1935. These statutes have been amended and supplemented by subsequent legislation, including PURPA 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 independent power producers, and vests its authority in FERC. Unless otherwise exempt, any person that owns or operates facilities used for the wholesale sale or transmission of power 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, the terms and conditions for the transmission or wholesale sale of power in interstate commerce, the interlocking directorates, and the uniform system of accounts and reporting requirements for public utilities.

 

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The majority of our power plants are subject to FERC’s jurisdiction; however, certain power plants qualify for available exemptions. FERC’s jurisdiction over EWGs under the FPA applies to the majority of our power plants because they are EWGs or are owned by EWGs, except our EWGs located in ERCOT. Power plants located in ERCOT are exempt from many FERC regulations under the FPA. Many of our power plants 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 power plants used for the generation of power 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 as we are a holding company due solely to our owning one or more QFs, EWGs and Foreign Utility Companies, or 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.

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 certain of those power plants that are QFs under PURPA or 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. If market-based rate authority were revoked or restricted, affected power plants could be required to make wholesale sales of power based on cost-of-service rates, which could negatively impact their revenues.

FERC’s regulations specifically prohibit the manipulation of the power markets by making it unlawful for any entity in connection with the purchase or sale of power, or the purchase or sale of power 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 Regional Transmission Organization or ISO market rules, communication of accurate information, price reporting to publishers of power 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.

 

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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 of the FPA 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, to acquire additional QFs, EWGs or FUCOs, or the securities of additional QFs, EWGs and FUCOs without prior FERC 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 power 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 are also exempt from FERC regulation of wholesale sales of the QFs’ power output. QFs are also exempt from most state laws and regulations. To be a QF, a Cogeneration power plant must produce power and useful thermal energy for an industrial or commercial process, or heating or cooling applications in certain proportions to the power plant’s total energy output, and must meet certain efficiency standards.

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 power market. Some entities maintain that the launch of CAISO’s Market Redesign and Technology Upgrade provides the access that should obviate the California utilities’ mandatory purchase obligation, and triggers changes in energy pricing for California QFs pursuant to existing QF contracts. These issues remain the topic of extensive stakeholder negotiation.

FERC 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. 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 Electric Reliability Organization to develop and oversee the enforcement of electric system reliability standards applicable throughout the U.S., which are subject to FERC review and approval. FERC approved reliability standards may be enforced by FERC independently, or, alternatively, by the Electric Reliability Organization 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 power (purchasing and selling entity) are effective and

 

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mandatory. In addition, the regional reliability organizations have the ability to formulate supplemental reliability standards to apply in their specific regions, which may be more stringent than the NERC reliability standards. We must comply with different reliability standards, requirements and procedural rules in each region in which we operate. It is expected that additional or modified NERC and regional reliability standards will be approved by FERC in the coming years, requiring us to take additional steps to remain fully compliant.

Regional and State Regulation of Power

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 power plants. While we provide a brief overview of the primary regional rules and regulations affecting our power plants 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 as significant. All power plant and MW data is reported as of December 31, 2009.

West

We have 27 natural gas-fired power plants, excluding one under advanced development, with the capacity to generate a total of 7,185 MW in the WECC NERC region, which extends from the Rocky Mountains westward. In addition, we own and operate 15 geothermal power plants located in northern California capable of producing a total of 725 MW. The majority of these power plants are located in California, in the CAISO region; however, we also own power plants 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 power, differentiated by time and type of electrical service, into which our subsidiaries may sell power 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 runs integrated day-ahead and real-time markets for energy and ancillary services. The energy markets include centralized, day-ahead and real-time markets for energy, a nodal transmission congestion management model that results in locational marginal pricing at each generation location, financial congestion hedging instruments, a centralized day-ahead commitment process and current bid caps of $500 per MWh, which are scheduled to increase to $750 per MWh on April 1, 2010. The locational marginal pricing market design is intended to reward and encourage generation resources on favorable grid locations, such as some of the locations of our power plants.

Our power 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

We have 12 natural gas-fired power plants in the TRE NERC region with the capacity to generate a total of 7,392 MW, all of which are physically located in the ERCOT market. ERCOT is the 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 power markets. FERC does not regulate wholesale sales of power in ERCOT. The PUCT exercises regulatory jurisdiction over the rates and services of any electric utility conducting business within Texas. Our subsidiaries that own power plants in Texas have power generation company status at the PUCT, and are either EWGs or QFs and are exempt from PUCT rate regulation. 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 methods. ERCOT ensures resource adequacy through an energy-only model rather than the capacity-based resource adequacy model that is more common among Regional Transmission Organizations or ISOs in the

 

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Eastern Interconnect. In ERCOT there is a market price cap for energy and capacity 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 power and capacity services to ERCOT.

ERCOT’s implementation of a nodal market structure was scheduled to have been implemented in late 2008. However, in 2008, ERCOT announced that it would delay implementation. The PUCT initiated an effort to refresh the original cost-benefit study analysis that had justified moving to a nodal design. Based on the refreshed analysis, ERCOT states that it intends to implement nodal design at the end of 2010, which ERCOT’s latest progress report on the nodal project indicates that it remains on schedule for a December 2010 implementation date. We anticipate a neutral business impact on us, but we are not able to rule out other impacts.

The Sunset Review Process, implemented by the Texas Legislature in 1977, is the regular assessment of the need for a state agency to exist and to consider new and innovative changes to improve each agency’s operations and activities. The Sunset Review Process works by setting a date on which an agency will be abolished unless legislation is passed to continue its functions. The Sunset Review Process began in September 2009 for the PUCT and ERCOT. It is expected to be concluded by April 2010. The Texas Commission on Environmental Quality, or TCEQ, review will begin in April 2010 and is scheduled to be completed by November 2010 when the compliance phase for all agencies will begin. We will monitor the Sunset Review Process of these entities and will seek to participate in these processes where we anticipate an impact on our business.

On July 17, 2008, the PUCT tentatively approved a transmission build plan, the Competitive Renewable Energy Zones, or CREZ, to expand the delivery of wind-generated power from western Texas to service approximately 18,500 MW of planned wind generation. Wind generation tends to supply more power during off-peak hours and shoulder months, and is unpredictable. The PUCT’s selection of transmission providers to build the transmission lines was challenged in Texas state court, and on January 15, 2010 the court reversed and remanded the PUCT’s order selecting certain companies to build the CREZ lines, finding that the PUCT erred in its selection process. As a consequence of the state court’s ruling, the PUCT established a new docket to reconsider its order selecting the transmission providers. We do not know what, if any, delay the court’s decision will have on any CREZ project. If completed as currently approved, the impact of the transmission upgrades and associated wind generation on our Texas plants is unknown.

Southeast

We have one operating natural gas-fired power plant with the capacity to generate 1,134 MW located in the SPP NERC region. SPP is a Regional Transmission Organization 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 stakeholders are considering the creation of a day-ahead market and ancillary service markets.

We have ten natural gas-fired power plants with the capacity to generate a total of 4,949 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 regions. 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 Independent Coordinator of Transmission. In this capacity, the Independent Coordinator of Transmission provides oversight of the Entergy transmission system.

North

We have a total of eight natural gas-fired power plants with the capacity to generate a total of 1,433 MW located in the NPCC NERC region. Five of these power plants are located in New York. NYISO manages the transmission system in New York and operates the state’s wholesale power markets. NYISO manages both day-ahead and real-time energy markets using a locationally based marginal pricing mechanism that pays each generator the zonal marginally accepted bid price for the energy it produces.

 

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Our remaining U.S.-based power plant in the NPCC NERC region is located in Maine. ISO NE is the Regional Transmission Organization 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 also have 50% ownership in two power plants, which includes a 50% interest and a 50% joint venture, with the total capacity to generate 1,088 MW, located in the NPCC NERC region in Ontario, Canada. The Independent Electricity System Operator, or IESO, of Ontario operates the Province’s wholesale power markets and directs the operation and ensures reliability of the IESO controlled grid. Hydro-One owns and operates the transmission system in Ontario, which is regulated by the Ontario Energy Board. Effective December 2009, the IESO implemented several rule changes that are expected to impact the financial performance in 2010 and beyond for Greenfield Energy Centre, our joint venture. Greenfield Energy Centre’s power supply contract with the Ontario Power Authority, or OPA, provides it with a right to recovery for financial consequences of market rule changes that negatively impact Greenfield Energy Centre. OPA has not yet agreed to accept responsibility for the changes and discussions continue between the parties.

We have one operating power plant, with the capacity to generate 503 MW, located in PJM, which is located in the RFC NERC region. However, it is partially committed to load in MISO. PJM operates wholesale power markets, a locationally based capacity market, a forward capacity market and ancillary service markets. PJM also performs transmission planning for the region.

We have three natural gas-fired power plants with the capacity to generate a total of 1,481 MW operating within the MRO NERC region. MISO manages competitive locationally based wholesale day-ahead, real-time energy and ancillary services markets. MISO’s Resource Adequacy model requires load serving entities to account for capacity obligations under Module E of the MISO tariff. MISO implemented a monthly voluntary capacity auction to help purchasers find suppliers with capacity to meet their incremental capacity needs.

Other State Regulation of Power

State Public Utility Commissions, or PUC(s), have historically had broad authority to regulate both the rates charged by, and the financial activities of, electric utilities operating in their states and to promulgate regulation for implementation of PURPA. Since 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 power 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 power plants “located in the state,” including EWGs but excluding QFs, for the purpose of ensuring their reliable operation. As the owner and operator of power plants in California, our subsidiaries are subject to the power plant maintenance and operation standards and the general duty standards that are enforced by the CPUC.

State PUCs also maintain extensive control over the procurement of wholesale power by the utilities that they regulate. Many of these utilities are our customers, and agreements between us and these counterparties often require approval by state PUCs. For example, in California, the CPUC determines how much new generation can be purchased by the California Investor Owned Utilities, or IOUs, and shapes the rules of the IOUs’ requests for offers. In addition, the CPUC determines the rules of California’s Resource Adequacy program. The Resource Adequacy program is currently based on a loosely structured year- and month-ahead bilateral capacity market. The CPUC is in the process of considering modifications to the Resource Adequacy program, including the potential introduction of a multi-year forward centralized capacity markets, similar to those that exist in ISO NE and PJM.

Regulation of Transportation and Sale of Natural Gas

Since the majority of our power generating capacity is derived from natural gas-fired power plants, we are broadly impacted by federal regulation of natural gas transportation and sales. Furthermore, our two natural gas

 

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transportation pipelines in Texas are subject to dual jurisdiction by FERC and the Texas Railroad Commission. These pipelines are intrastate pipelines within the meaning of Section 2(16) of the Natural Gas Policy Act, or NGPA. FERC regulates the rates charged by these pipelines for transportation services performed under Section 311 of the NGPA, and the Texas Railroad Commission regulates the rates and services provided by these pipelines as gas utilities in Texas. Additionally, under the Natural Gas Act, or NGA, the NGPA and the Outer Continental Shelf Lands Act, FERC is authorized to regulate pipeline, storage and liquefied natural gas, or LNG, 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 natural gas specifications are implemented, LNG supplies could impact in the future our power 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. FERC’s regulations specifically prohibit the manipulation of the natural gas markets by making it unlawful for any entity in connection with the purchase or sale of natural gas, or the purchase or sale of transportation service under FERC’s jurisdiction, to engage in fraudulent or deceptive practices. 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.

We also operate proprietary pipelines in California, which are regulated by the California Department of Transportation with regard to safety matters but are otherwise not regulated.

CFTC Regulation of Power and Natural Gas and Possible Derivatives Legislation

The CFTC has regulatory oversight of the futures markets, including trading on NYMEX for energy, and licensed futures professionals such as brokers, clearing members and large traders. In connection with its oversight of the futures markets and NYMEX, the CFTC regularly investigates market irregularities and potential manipulation of those markets. Recent laws also give the CFTC certain powers with respect to broker-type markets referred to as “exempt commercial markets” or ECMs, including the Intercontinental Exchange. The CFTC monitors activities in the OTC, ECM, and physical markets that may be undertaken for the purpose of influencing futures prices. With respect to ECMs, the CFTC exercises only light-handed regulation primarily related to price reporting and record retention. Thus, transactions executed on an ECM generally are not regulated directly by the CFTC. However, ECM transactions have come under the CFTC’s scrutiny during investigations of fraud and manipulation in which the CFTC has broadly applied its statutory authority to punish persons who are alleged to have manipulated, or attempted to manipulate, the price of any commodity in interstate commerce or for future delivery.

On December 11, 2009, the House of Representatives passed the Wall Street Financial Reform and Consumer Protection Act of 2009. The legislation includes provisions to regulate certain types of OTC derivatives that we use. Included in the bill is a provision which clarifies the definition of a “major swap participant” that would otherwise have left it to future CFTC interpretation and definition which could have put more end users, such as us, under mandatory clearing, position limits and margin despite an end user exemption in the underlying bill.

The Senate Banking Committee is attempting to work in a bipartisan manner to craft comprehensive financial reform legislation. The committee has organized bipartisan working groups to address various aspects of reform. The Senate Agriculture Committee also continues to work on drafting bipartisan legislation.

Geothermal Operations

In 2009, as part of a joint private and federally funded geothermal technology research project, a company unrelated to us commenced deepening an existing geothermal well on a property neighboring our

 

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Geysers Assets. The company was reportedly attempting to drill into the hot, low or non-permeable base rock that underlies the existing geothermal steam reservoir at The Geysers to engineer or create a “multilayered heat extraction system” below the reservoir by injecting water under very high pressure, fracturing the rock. This process has spawned public and political concern regarding increased seismicity risk. As a consequence, in July 2009, the Department of Energy halted funding of its portion of that research project pending further seismicity studies. In addition, the Department of Energy and residents located near our Geysers Assets have expressed concern regarding induced seismicity associated with geothermal operations. Also, we have become aware of a letter and petition to the Board of Supervisors County of Lake from a local community homeowners association located near our Geysers Assets entitled a “Complaint and Petition” and signed by “109 residents and property owners.” The letter asks for county intervention to abate alleged public nuisance arising from induced seismicity by governmental legal action, including litigation, regulation and ordinances to prevent induced seismicity; however, the letter also states it is not their intent to suspend our geothermal operations. In response to those concerns, it is possible that government entities or agencies will seek to more stringently regulate the exploration, development, and operation of geothermal power plants, including our Geysers Assets, in order to mitigate induced seismicity resulting from geothermal operations.

EMPLOYEES

As of December 31, 2009, we employed 2,046 full-time employees, of whom 46 were represented by collective bargaining agreements. We have never experienced a work stoppage or strike.

Item 1A. Risk Factors

Operations

A prolonged economic downturn could result in a reduction in our revenue, operating cash flows or result in our customers, counterparties, vendors or other service providers failing to perform under their contracts with us.

To the extent that the current economic downturn continues to affect the markets in which we operate, demand for power and power prices may remain depressed, our revenues and operating cash flows could be negatively impacted. In addition, challenges currently affecting the economy could cause our customers, counterparties, vendors and service providers to experience deteriorating credit and serious cash flow problems. As a result, these conditions could cause counterparties in the natural gas and power markets, particularly in the power derivative markets that we rely on for our hedging activities, to be unable to perform under existing contracts, or to withdraw from participation in those markets. If multiple parties withdraw from those markets, market liquidity may be threatened, which in turn could adversely impact our business. Additionally, these conditions may cause our counterparties to seek bankruptcy protection under Chapter 11 or liquidation under Chapter 7 of the Bankruptcy Code.

Our financial performance is impacted by price fluctuations in the wholesale power and natural gas markets and other market factors that are beyond our control.

Market prices for power, generation capacity, ancillary services and natural gas are unpredictable and fluctuate substantially. Unlike most other commodities, power can only be stored on a very limited basis and generally must be produced concurrently with its use. As a result, power prices are subject to significant volatility due to supply and demand imbalances, especially in the day-ahead and spot markets. Long- and short-term power and natural gas prices may also fluctuate substantially due to other factors outside of our control, including:

 

   

increases and decreases in generation capacity in our markets, including the addition of new supplies of power as a result of the development of new power plants, expansion of existing power plants or additional transmission capacity;

 

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changes in power transmission or fuel transportation capacity constraints or inefficiencies;

 

   

power supply disruptions, including power plant outages and transmission disruptions;

 

   

Heat Rate risk;

 

   

weather conditions;

 

   

changes in the demand for power or in patterns of power usage, including the potential development of demand-side management tools and practices;

 

   

development of new fuels or new technologies for the production of power;

 

   

regulations and actions of the ISOs; and

 

   

federal and state power market and environmental regulation and legislation, including mandating a RPS or creating financial incentives, each resulting in new renewable energy generation capacity creating oversupply.

These factors have caused our operating results to fluctuate in the past and will continue to cause them to do so in the future.

Our ability to manage our counterparty credit risk could adversely affect us.

Our customer and supplier counterparties may experience deteriorating credit. These conditions could cause counterparties in the natural gas and power markets, particularly in the power derivative markets that we rely on for our hedging activities, to withdraw from participation in those markets. If multiple parties withdraw from those markets, market liquidity may be threatened, which in turn could adversely impact our business. Additionally, these conditions may cause our counterparties to seek bankruptcy protection under Chapter 11 or liquidation under Chapter 7 of the Bankruptcy Code. Our credit risk may be exacerbated to the extent collateral held by us cannot be realized or is liquidated at prices not sufficient to recover the full amount of the derivative exposure due to us. There can be no assurance that any such losses or impairments to the carrying value of our financial assets would not materially and adversely affect our financial condition, results of operations and cash flows.

Accounting for our hedging activities may increase the volatility in our quarterly and annual financial results.

We engage in commodity-related marketing and price-risk management activities in order to economically hedge our exposure to market risk with respect to power sales from our power plants, fuel utilized by those assets and emission allowances. We generally attempt to balance our fixed-price physical and financial purchases, and sales commitments in terms of contract volumes and the timing of performance and delivery obligations through the use of financial and physical derivative contracts. These derivatives are accounted for in accordance with GAAP, which requires us to record all derivatives on the balance sheet at fair value unless they qualify for the normal purchase normal sale exemption. Changes in the fair value resulting from fluctuations in the underlying commodity prices are immediately recognized in earnings, unless the derivative qualifies for, and is designated as, cash flow hedge accounting treatment. Sudden commodity price movements could create financial losses. Whether a derivative qualifies for cash flow hedge accounting treatment depends upon it meeting specific criteria used to determine if the cash flow hedge is and will remain effective for the term of the derivative. Economic hedges will not necessarily qualify for cash flow hedge accounting treatment, or for economic hedges that currently qualify for cash flow hedge accounting treatment; we may lose cash flow hedge accounting treatment in the future if the forecasted transactions are no longer considered probable of occurring. As a result, we may be unable to accurately predict the impact that our risk management decisions may have on our quarterly and annual financial results.

 

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The use of hedging agreements may not work as planned or fully protect us and could result in financial losses.

We typically enter into hedging agreements, including contracts to purchase or sell commodities at future dates and at fixed prices, in order to manage our commodity price risks. These activities, although intended to mitigate price volatility, expose us to other risks. When we sell power forward, we may be required to post significant amounts of cash collateral or other credit support to our counterparties and we give up the opportunity to sell power at higher prices if spot prices are higher in the future. Further, if the values of the financial contracts change in a manner that we do not anticipate, or if a counterparty fails to perform under a contract, it could harm our financial condition, results of operations and cash flows.

We do not typically hedge the entire exposure of our operations against commodity price volatility. To the extent we do not hedge against commodity price volatility, our financial condition, results of operations and cash flows may be diminished based upon adverse movement in commodity prices.

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 19 of the Notes to Consolidated Financial Statements for our 2009 and 2008 quarterly operating results), including:

 

   

seasonal variations in power and natural gas prices and capacity payments;

 

   

seasonal fluctuations in weather, in particular unseasonable weather conditions;

 

   

production levels of hydroelectric power in the West;

 

   

variations in levels of production, including from both planned and unplanned 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 power in our markets peaks in our third fiscal quarter. If our total revenue were below seasonal expectations during that quarter, by reason of power plant operational performance issues, cool summers, or other factors, it could have a disproportionate effect on our annual operating results.

We rely on power 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 power produced by our power plants and the distribution of natural gas fuel to our power plants. If these transmission and distribution systems are disrupted or capacity on those systems is inadequate, our ability to sell and deliver power 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.

 

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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 natural 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 power plants 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 natural gas transportation.

While adequate supplies of natural gas are currently available to us at prices we believe are reasonable for each of our power plants, 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 the use of natural gas by our power plants 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 natural gas supply;

 

   

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

 

   

market liquidity for physical natural gas or availability of natural 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 power plant operations; and

 

   

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

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, Regional Transmission Organizations and other market regulators that may impair our ability to recover our costs and limit our return on our capital investments; and

 

   

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 power at economical rates.

Our power generating operations performance involves significant risks and hazards and may be below expected levels of output or efficiency.

The operation of power plants involves 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 plants have experienced unplanned outages, including extensions of scheduled outages due to equipment breakdowns, failures or other problems and are an inherent risk of our business. Unplanned outages typically can result in lost revenues, increase our maintenance expenses and may reduce our profitability, which could have a material adverse effect on our financial condition, results of operations and cash flows.

 

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In addition, an unplanned outage may prevent the affected power plant 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 power plant, which could result in losing our interest in the affected power plant or, possibly, one or more other power plants.

Our power generating operations are inherently hazardous and may lead to catastrophic events, including loss of life, personal injury and destruction of property, and subject us to litigation.

Natural gas is highly explosive and power generation involves hazardous activities, including acquiring, transporting and delivering fuel, operating large pieces of rotating equipment and delivering power to transmission and distribution systems. These and other hazards can cause severe damage to and destruction of property, plant and equipment and suspension of operations. In the worst circumstances, catastrophic events can cause significant personal injury or loss of life. Further, the occurrence of any one of these events may result in us being named as a defendant in lawsuits asserting claims for substantial damages. We maintain an amount of insurance protection that we consider adequate; however, we cannot provide any assurance that the insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we are subject. A successful claim against us that is not fully insured could have a material adverse effect on our financial condition, results of operations and cash flows.

Our power plants and development projects are subject to impairments.

If we were to experience a significant reduction in our expected revenues and operating cash flows for an extended period of time from a prolonged economic downturn or from advances or changes in technologies, we could experience future impairments of our power plant assets as a result. There can be no assurance that any such losses or impairments to the carrying value of our financial assets would not materially and adversely affect our financial condition, results of operations and cash flows.

Our power project development and construction activities involve risk and may not be successful.

The development and construction of power plants is subject to substantial risks. In connection with the development of a power plant, we must generally obtain:

 

   

necessary power generation equipment;

 

   

governmental permits and approvals including environmental permits and approvals;

 

   

fuel supply and transportation agreements;

 

   

sufficient equity capital and debt financing;

 

   

power transmission agreements;

 

   

water supply and wastewater discharge agreements or permits; and

 

   

site agreements and construction contracts.

To the extent that our development and construction activities continue or expand, we may be unsuccessful on a timely and profitable basis. Although we may attempt to minimize the financial risks of these activities by securing a favorable PPA and arranging adequate financing prior to the commencement of

 

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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. The process for obtaining governmental permits and approvals is complicated and lengthy, often taking more than one year, and is subject to significant uncertainties. We may be unable to obtain all necessary licenses, permits, approvals and certificates for proposed projects, and completed power plants may not comply with all applicable permit conditions, statutes or regulations. In addition, regulatory compliance for the construction and operation of our power plants 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 resulting in potential impairments.

Our geothermal power 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 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 power resources are subject to substantial risks and uncertainties. The successful exploitation of a geothermal power 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.

Claims that some geothermal power plants cause increased risk of seismic activity could impact our operating procedures and increase our operating costs or, delay or increase the cost of further development at The Geysers.

In 2009, as part of a joint private and federally-funded geothermal technology research project, a company unrelated to us commenced deepening an existing geothermal well on a property neighboring our Geysers Assets. The company was reportedly attempting to drill into the hot, low or non-permeable base rock that underlies the existing geothermal steam reservoir at The Geysers to engineer or create a “multilayered heat extraction system” below the reservoir by injecting water under very high pressure, fracturing the rock. This process has spawned public and political concern regarding increased seismicity risk. As a consequence, in July 2009, the Department of Energy temporarily halted funding of its portion of that research project pending further seismicity studies. Although our geothermal operations do not include attempts to engineer or create new reservoirs from hot, low or non-permeable rock, the concerns regarding induced seismicity from geothermal operations could delay or otherwise adversely impact our Department of Energy grant applications. Also, we have become aware of a letter and petition to the Board of Supervisors County of Lake from a local community homeowners association located near our Geysers Assets entitled a “Complaint and Petition” and signed by “109

 

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residents and property owners.” The letter asks for county intervention to abate alleged public nuisance arising from induced seismicity by governmental legal action, including litigation, regulation and ordinances to prevent induced seismicity; however, the letter also states it is not their intent to suspend our geothermal operations. It is possible that government entities or agencies will seek to more stringently regulate the exploration, development and operation of geothermal power plants, including operations of our Geysers Assets, in order to mitigate induced seismicity resulting from geothermal operations, or that operators of geothermal power plants could be subject to property damage claims resulting from increased seismic activity. Any of these events could increase the cost of operating the existing Geysers Assets and may delay or increase further exploration and any further development of our Geysers Assets.

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 independent power producers. 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 power utilities to lower their costs, including the cost of purchased power, and increasing competition in the supply of power 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 power trading markets, putting downward pressure on prices.

Significant events beyond our control, such as natural disasters or acts of terrorism, could damage our power plants or our corporate offices and may impact us in unpredictable ways.

Certain of our geothermal and natural gas-fired power plants, 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. Similarly, operations at our corporate offices in Houston, Texas could be substantially affected by a hurricane. Such events could damage or shut down our power plants, power transmission or the fuel supply facilities upon which our generation business is dependent. Our existing power plants 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 power plants or our operations due to natural disasters.

In addition to physical damage to our power plants, the risk of future terrorist activity could result in adverse changes in the insurance markets and disruptions in the power and fuel markets. These events could also adversely affect the U.S. economy, create instability in the financial markets and, as a result, have an adverse effect on our ability to access capital on terms and conditions acceptable to us.

We depend on our management and employees.

Our success is largely dependent on the skills, experience and efforts of our people. 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 were unable to replace them. In addition, approximately 46 employees are represented by collective bargaining agreements.

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 counterparty to terminate the contract and/or seek liquidated damages include:

 

   

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

 

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

 

   

failure of a power plant to achieve certain output or efficiency minimums;

 

   

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

 

   

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

 

   

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

 

   

events of liquidation, dissolution, insolvency or bankruptcy.

Revenue may be reduced significantly upon expiration or termination of our PPAs.

Some of the power 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 day to five years) PPAs. Our uncontracted capacity is generally sold on the spot market at current market prices as merchant energy. When the terms of each of our various PPAs expire, it is possible that the price paid to us for the generation of power under subsequent arrangements or on the spot market may be significantly less than the price that had been paid to us under the PPA. Power plants without long-term PPAs involve risk and uncertainty in forecasting future demand load for merchant sales because they are exposed to market fluctuations for some or all of their generating capacity and output. A significant under- or over-estimation of load requirements may increase our operating costs. Without the benefit of long-term PPAs, we may not be able to sell any or all of the power generated by these power plants at commercially attractive rates and these power plants may not be able to operate profitably.

Certain of our PPAs have values in excess of current market prices (measured over the next five years). The aggregate notional value of these PPAs is approximately $3.2 billion at December 31, 2009. 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. Additionally, our PPAs contain termination provisions standard to contracts in our industry such as negligence, performance default or prolonged events of force majeure.

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

On December 20, 2005 (the Petition Date), Calpine Corporation and 274 of its wholly owned U.S. subsidiaries filed for voluntary petitions of relief under Chapter 11 of the Bankruptcy Code. From the Petition Date through our emergence from Chapter 11 on the Effective Date (January 31, 2008), we operated as a debtor-in-possession under the protection of the U.S. Bankruptcy Court. In general, all claims that arose prior to the Petition Date and before confirmation of our Plan of Reorganization were discharged in accordance with the Bankruptcy Code and the terms of our Plan of Reorganization; however, there are certain exceptions. 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 or where we have agreed to preserve a claimant’s claims or a claimant has received court approval to proceed with their claim such as the settlement of the CalGen Third Lien Debt claims. The ultimate resolution of such claims and other obligations may have a material adverse effect on our results of operations and profitability.

 

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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 power plants. 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.

Capital Resources; Liquidity

We have substantial liquidity needs and could face liquidity pressure.

As of December 31, 2009, our consolidated debt outstanding was $9.5 billion, of which approximately $4.7 billion was outstanding under our First Lien Credit Facility and $1.2 billion was outstanding under our First Lien Notes. In addition we had $412 million issued in letters of credit and our pro rata share of unconsolidated subsidiary debt was approximately $624 million. 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 substantial liquidity needs in the operation of our business. Our ability to make payments on our indebtedness, to meet margin requirements and to fund planned capital expenditures and development efforts will depend on our ability to generate cash in the future from our operations and our ability to access the capital markets. This, to a certain extent, is dependent upon industry conditions, as well as general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control, as discussed further in “— Operations” above. Our borrowing capacity under our existing credit facilities remains limited. Although we are permitted to enter into new project financing credit facilities to fund our development and construction activities and we are allowed to offer first lien notes in exchange for term loans under our First Lien Credit Facility under certain circumstances, there can be no assurance that we will not face liquidity pressure in the future. 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 flows in other areas of our business because we must dedicate a substantial portion of these funds to service our 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 or to repurchase equity issued by certain of our subsidiaries to third parties; and

 

   

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

The soundness of financial institutions could adversely affect us.

We have exposure to many different financial institutions and counterparties including those under our First Lien Credit Facility and other credit and financing arrangements as we routinely execute transactions in

 

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connection with our hedging and optimization activities, including brokers and dealers, commercial banks, investment banks and other institutions and industry participants. Many of these transactions expose us to credit risk in the event that any of our lenders or counterparties are unable to honor their commitments or otherwise defaults under a financing agreement.

We may be unable to obtain additional financing or access the credit and capital markets in the future at prices that are beneficial to us or at all.

If our available cash, including future cash flows generated from operations, is not sufficient in the near term to finance our operations, post collateral or satisfy or refinance our obligations as they become due, we may need to access the capital and credit markets. Our ability to arrange financing (including any extension or refinancing) and the cost of the financing are dependent upon numerous factors, including general economic and capital market conditions. Market disruptions such as those experienced in the U.S. and abroad in 2008 and 2009, may increase our cost of borrowing or adversely affect our ability to access capital. In addition, we believe these conditions have and may continue to have an adverse effect on the price of our common stock, which in turn may also reduce our ability to access capital or credit markets. These disruptions may continue throughout 2010 or longer. Other factors include:

 

   

low credit ratings may prevent us from obtaining any material amount of additional debt financing;

 

   

our restrictions against additional borrowing in our First Lien Credit Facility may limit additional indebtedness other than through refinancing outstanding debt, or through project financings where we are able to pledge the project assets as security;

 

   

conditions in power markets;

 

   

regulatory developments;

 

   

credit availability from banks or other lenders for us and our industry peers;

 

   

investor confidence in the industry and in us;

 

   

the continued reliable operation of our current power plants; and

 

   

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

While we have utilized non-recourse or lease financing when appropriate, market conditions and other factors may prevent us from completing similar financings in the future. It is possible that we may be unable to obtain the financing required to develop, construct, acquire or expand power plants on terms satisfactory to us. We have financed our existing power plants using a variety of leveraged financing structures, including senior secured and unsecured indebtedness, construction financing, project financing, term loans and lease obligations. 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 power plant and any related assets. In the event of foreclosure after a default, we may not be able to retain any interest in the power plant or other collateral supporting such financing. In addition, any such default or foreclosure may trigger cross default provisions in our other financing agreements.

Our First Lien Credit Facility, First Lien Notes and our other debt instruments impose significant restrictions on us and any failure to comply with these restrictions could have a material adverse effect on our liquidity and our operations.

The restrictions under our First Lien Credit Facility and First Lien Notes could adversely affect us by limiting our ability to plan for or react to market conditions or to meet our capital needs and, if we were unable to comply with these restrictions, could result in an event of default under our First Lien Credit Facility. These

 

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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 issue certain stock;

 

   

make prepayments on or purchase certain 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 our First Lien Credit Facility for non-guarantors (including foreign subsidiaries);

 

   

make certain investments;

 

   

create or incur liens;

 

   

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;

 

   

pay dividends or make other distributions from certain subsidiaries up to Calpine Corporation;

 

   

make capital expenditures beyond specified limits;

 

   

engage in certain business activities;

 

   

enter into certain transactions with our affiliates; and

 

   

acquire power plants or other businesses.

Our First Lien Credit Facility, First Lien Notes and our other debt instruments contain events of default customary for financings of their type, including a cross default to debt other than non-recourse project financing debt, a cross-acceleration to non-recourse project financing debt and certain change of control events. If we fail to comply with the covenants and are unable to obtain a waiver or amendment, or a default exists and is continuing under such debt, the lenders could give notice and declare outstanding borrowings and other obligations under such debt 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 obtainable, it could be on terms that are not acceptable to us. If we are unable to comply with the terms of our First Lien Credit Facility, First Lien Notes and our other debt instruments, or if we fail to generate sufficient cash flows from operations, or if it becomes necessary to obtain such waivers, amendments or alternative financing, it could adversely impact our financial condition, results of operations and cash flows.

A significant portion of our indebtedness contains floating rate interest provisions, which could impact our financial health if interest rates were to rise significantly.

A significant portion of our indebtedness contains floating rate interest, which we pay on a current basis. If we are unable to satisfy our obligations under our floating rate debt, particularly on our First Lien Credit

 

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Facility, it could result in defaults under our First Lien Credit Facility 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 — Risk Management and Commodity Accounting — Interest Rate Risk.”

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 or may increase the cost of any available financing. Our current credit rating 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 financial position and results of operations.

Certain of our obligations are required to be secured by letters of credit or cash, which increase our costs; if we are unable to provide such security it may restrict our ability to conduct our business.

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 activities. 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. Certain of our financing arrangements for our power plants have required us to post letters of credit which are at risk of being drawn down in the event we, or the applicable subsidiary, default on our obligations.

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 was 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. As of December 31, 2009, we had $412 million issued in letters of credit under our First Lien Credit Facility and other facilities, with $794 million remaining available for borrowing or for letter of credit support under our First Lien Credit Facility. In addition, we have ratably secured our obligations under certain of our power and natural gas agreements that qualify as eligible commodity hedge agreements under our First Lien Credit Facility with the assets currently subject to liens under our First Lien Credit Facility.

We may not have sufficient liquidity to hedge market risks effectively.

We are exposed to market risks through our sale of power, capacity and related products and the purchase and sale of fuel, transmission services and emission allowances. These market risks include, among other risks, volatility arising from location and timing differences that may be associated with buying and transporting fuel, converting fuel into power and delivering the power to a buyer.

We undertake these activities through agreements with various counterparties, many of which require us to provide guarantees, offset or netting arrangements, letters of credit, a second lien on assets and/or cash collateral to protect the counterparties against the risk of our default or insolvency. The amount of such credit support that must be provided typically is based on the difference between the price of the commodity in a given contract and the market price of the commodity. Significant movements in market prices can result in our being required to provide cash collateral and letters of credit in very large amounts. The effectiveness of our strategy may be dependent on the amount of collateral available to enter into or maintain these contracts, and liquidity requirements may be greater than we anticipate or will be able to meet. Without a sufficient amount of working capital to post as collateral in support of performance guarantees or as a cash margin, we may not be able to

 

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manage price volatility effectively or to implement our strategy. An increase in the amount of letters of credit or cash collateral required to be provided to our counterparties may negatively affect our liquidity and financial condition.

Further, if any of our power plants experience unplanned outages, we may be required to procure replacement power at spot market prices in order to fulfill contractual commitments. Without adequate liquidity to meet margin and collateral requirements, we may be exposed to significant losses, may miss significant opportunities and may have increased exposure to the volatility of spot markets.

Our ability to receive future cash flows generated from the operation of our subsidiaries may be limited.

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 flows to service our indebtedness, post collateral and finance our ongoing operations. Certain of our project debt and other agreements 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 certain 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, which could increase our debt and may be structurally senior to other debt such as our First Lien Credit Facility and our First Lien Notes.

Our ability and the ability of our subsidiaries to incur additional indebtedness are limited in some cases by existing indentures, debt instruments or other agreements. Our subsidiaries may incur additional construction/project financing indebtedness, issue preferred equity to finance the acquisition and development of new power plants 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 preferred equity would be added to our current consolidated debt levels and would likely be structurally senior to our debt, which could also intensify the risks associated with our already substantial leverage.

Our First Lien Credit Facility, First Lien Notes and other parent-company debt is effectively subordinated to certain project indebtedness.

Certain of 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. As a result, holders of our indebtedness will be effectively subordinated to all present and future debts and other liabilities (including trade payables) of certain of our subsidiaries. As of December 31, 2009, our subsidiaries had approximately $1.6 billion of secured project financing and approximately $1.0 billion in debt from our CCFC subsidiary, which are effectively senior to our First Lien Credit Facility, First Lien Notes and other parent-company debt. We may incur additional project financing indebtedness in the future, which will be effectively senior to our other secured and unsecured debt.

 

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Governmental Regulation

Existing and future anticipated GHG/Carbon legislation could adversely affect our operations.

Environmental laws and regulations have generally become more stringent over time, and this trend is likely to continue. In particular, there is growing likelihood that carbon tax or limits on carbon, CO2 and other GHG emissions will be implemented at the federal or expanded at the state or regional levels.

In 2009, ten states in the northeast began the compliance period of a cap-and-trade program, RGGI, to regulate CO2 emissions from power plants. California is in the process of creating implementation plans for Assembly Bill 32 which places a statewide cap on GHG emissions and requires the state to return to 1990 emission levels by 2020.

In 2008, there were several bills introduced in the U.S. Congress concerning climate change. On June 26, 2009, the House of Representatives passed The American Clean Energy and Security Act of 2009, a climate change and clean energy bill, which, among other provisions, would establish an economy-wide carbon cap-and-trade program and set carbon emission reduction targets in several sectors of the economy, including the power sector. For the power sector, 2012 is set as the initial year for compliance. On October 23, 2009, draft climate change legislation entitled the Clean Energy Jobs and American Power Act, was released in the Senate. The legislation is similar to The American Clean Energy and Security Act of 2009 in that it also includes, among other provisions, an economy-wide carbon cap-and-trade program.

If either bill were to become law, we would have the obligation to obtain emissions allowances for the operation of our fossil-fuel power plants. While we expect the costs to acquire allowances to be a factor that will impact market price, there can be no assurance that market price will fully reflect these costs which could adversely affect our Commodity Margin. With respect to our existing long-term steam and power contracts under which we would not be able to recover costs to acquire allowances from our customers, the bill allocates a pool of free allowances to generators with qualifying contracts to mitigate such costs. However, there can be no assurance there will be a sufficient number of free allowances in the pool to fully cover emissions related to generation under such contracts which could adversely impact our Commodity Margin.

Although we cannot predict the effect and ultimate content of final climate change legislation and regulations, if any, on our business, we continue to expect climate change legislation efforts to proceed at the federal level, and that proposed legislation will take the form of a cap-and-trade program, although it is possible that legislation may take other forms, such as a carbon tax on each unit of CO2 or GHG emitted in excess of mandated limits. As a result of requirements for GHG emissions reduction, we could be required under any climate change legislation or related regulations ultimately enacted to purchase allowances or offsets to emit GHGs or other regulated pollutants or to pay taxes on such emissions. These requirements, as well as the possibility that market or contract prices will not fully reflect costs of compliance, or that we may not be able to obtain free allowances or recoup our costs to obtain allowances or to reduce emissions, could have a material impact on our financial condition, results of operations and cash flows.

Existing and proposed federal and state RPS and energy efficiency, as well as economic support for renewable sources of power under the U.S economic stimulus legislation could adversely impact our operations.

Federal policymakers have been considering imposing a national RPS on retail power providers. California already has an RPS in effect and is currently considering new and higher RPS. A number of additional states, including Maine, Minnesota, New York, Texas and Wisconsin, have an array of different RPS in place. Existing state-specific RPS requirements may change due to regulatory and/or legislative initiatives, and other states may consider implementing enforceable RPS in the future. A national RPS or more robust RPS in states in which we are active, coupled with economic incentives provided under the federal stimulus package, would

 

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likely initially drive up the number of wind and solar resources, increasing power supply to various markets which could negatively impact the dispatch of our natural gas assets, primarily in Texas and California.

Similarly, federal legislators are considering national energy efficiency initiatives. Several states already have energy efficiency initiatives in place while others are considering imposing them. Improved energy efficiency when mandated by law or promoted by government sponsored incentives can decrease demand for power which could negatively impact the dispatch of our gas assets, primarily in Texas and California.

Proposed financial reform relating to derivative transactions, as well as certain financial institutions, could have an adverse impact on our ability to hedge risks associated with our business.

The CFTC has regulatory oversight of the futures markets, including trading on NYMEX for energy, and licensed futures professionals such as brokers, clearing members and large traders. In connection with its oversight of the futures markets and NYMEX, the CFTC regularly investigates market irregularities and potential manipulation of those markets. Recent laws also give the CFTC certain powers with respect to broker-type markets referred to as “exempt commercial markets” or ECMs, including the Intercontinental Exchange. The CFTC monitors activities in the OTC, ECM, and physical markets that may be undertaken for the purpose of influencing futures prices. With respect to ECMs, the CFTC exercises only light-handed regulation primarily related to price reporting and record retention. Thus, transactions executed on an ECM generally are not regulated directly by the CFTC. However, ECM transactions have come under the CFTC’s scrutiny during investigations of fraud and manipulation in which the CFTC has broadly applied its statutory authority to punish persons who are alleged to have manipulated, or attempted to manipulate, the price of any commodity in interstate commerce or for future delivery.

On December 11, 2009, the House of Representatives passed the Wall Street Financial Reform and Consumer Protection Act of 2009. The legislation includes provisions to regulate certain types of OTC derivatives that we use. Included in the bill is a provision which clarifies the definition of a “major swap participant” that would otherwise have left it to future CFTC interpretation and definition which could have put more end users, such as us, under mandatory clearing, position limits and margin despite an end user exemption in the underlying bill.

The Senate Banking Committee is attempting to work in a bipartisan manner to craft comprehensive financial reform legislation. The committee has organized bipartisan working groups to address various aspects of reform. The Senate Agriculture Committee also continues to work on drafting bipartisan legislation.

In January 2010, the Obama Administration requested Congress to place new restrictions on financial institutions as part of comprehensive financial reform legislation. Specifically, the Obama Administration is requesting that “no bank or financial institution that contains a bank will own, invest in or sponsor a hedge fund or a private equity fund, or proprietary trading operations unrelated to serving customers for its own profit.” If enacted into law, banks would be banned from owning trading operations that trade in physical and financial derivative energy products. As several major financial institutions own such trading operations and provide significant liquidity to the energy markets in which we participate, if this or similar legislation is enacted the pricing and availability of derivative transactions related to our hedging activity could be adversely impacted.

Changes in the regulation of the power markets in which we operate could negatively impact us.

We have a significant presence in the major competitive power markets for California and Texas. While these markets are largely de-regulated, these markets continue to evolve. In 2009, implementation of CAISO’s Market Redesign and Technology Upgrade in California had a neutral to slightly positive impact on our operations. Existing regulations within the markets in which we operate may be revised or reinterpreted and new laws or regulations may be issued. We cannot predict the future development of regulation or legislation nor the ultimate effect such changes in these markets could have on our business; however, we could be negatively impacted.

 

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We are subject to other complex governmental regulation which could adversely affect our operations.

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 power plants. 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.

The construction and operation of power plants require numerous permits, approvals and certificates from the appropriate foreign, federal, state and local governmental agencies, as well as compliance with numerous environmental laws and regulations of federal, state and local authorities. Should we fail to comply with any environmental requirements that apply to power plant construction or operations, we could be subject to administrative, civil and/or criminal liability and fines, and regulatory agencies could take other actions to curtail our operations.

Furthermore, certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. We are generally responsible for all liabilities associated with the environmental condition of our power plants, including any soil or groundwater contamination that may be present, regardless of when the liabilities arose and whether the liabilities are known or unknown, or arose from the activities of predecessors or third parties.

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.

Certain of our significant shareholder groups own power generating assets, or own significant equity interests in entities with power generating assets, in markets where we currently own power plants. FERC has ruled that we do not have market power as a consequence of their ownership of our common stock. However, we could be determined to have market power if these existing significant shareholders acquire additional significant ownership or equity interest in other entities with power generating assets in the same markets where we generate and sell power.

If FERC makes the determination that we have market power, FERC could, 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 negatively impact their revenues. If we are required to mitigate market power, we could be required to sell certain power plants in regions where we are determined to have market power. A loss of our market-based rate authority or required sales of power plants, particularly if it affected several of our power plants or was in a significant market such as California, could have a material negative impact on our financial condition, results of operations and cash flows.

Risks Relating to Our Common Stock

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

Four holders (or related groups of holders) of our common stock have made filings with the SEC reporting beneficial ownership, directly or indirectly, individually or as members of a group, of 5% or more of the shares of our common stock. These shareholders, who together beneficially owned approximately 53% of our common stock at December 31, 2009, may be able to exercise substantial influence over all matters requiring

 

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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 significant influence over the election of our entire Board of Directors and significant influence over 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. Additionally, we have filed a registration statement on Form S-3 registering the resale of the common stock held by certain members of two of the four groups of these shareholders, which permits them to sell a large portion of their shares of common stock without being subject to the “trickle out” or other restrictions of Rule 144 under the Securities Act. During 2009, one of these shareholders, who had reported holdings of greater than 10% of our securities as of January 1, 2009, elected to sell approximately 67 million shares in a series of offerings and market transactions during 2009, bringing its shareholdings below 10% of our common stock. These sales, and additional sales by the other three shareholders of all or a substantial portion of their shares within a short period of time, could adversely affect the market price of our common stock or could further concentrate holdings of our common stock in the remaining three shareholders who hold more than 5% of our common stock.

Transfers of our equity, or issuances of equity, may impair our ability to utilize our federal income tax NOL carryforwards in the future.

Under federal income tax law, our NOL carryforwards can be utilized to reduce future taxable income subject to certain limitations, including if we were to undergo an ownership change as defined by Section 382 of the IRC. We experienced an ownership change on the Effective Date as a result of the cancellation of our old common stock and the distribution of our new common stock pursuant to our Plan of Reorganization. However, this ownership change and resulting annual limitations are not expected to result in the expiration of our 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 our market value immediately prior to the ownership change, our ability to utilize the NOL carryforwards may be significantly limited.

To manage the risk of significant limitations on our ability to utilize our tax NOL carryforwards, our amended and restated certificate of incorporation permits our Board of Directors to meet to determine whether to impose certain transfer restrictions on our common stock in the following circumstances: if, prior to February 1, 2013, our Market Capitalization declines by at least 35% from our Emergence Date Market Capitalization of approximately $8.6 billion (in each case, as defined in and calculated pursuant to our amended and restated certificate of incorporation) and at least 25 percentage points of shift in ownership has occurred with respect to our equity for purposes of Section 382 of the IRC. We believe, as of the filing of this Report, we have experienced declines in our stock price of more than 35% from our Emergence Date Market Capitalization. While we don’t believe an ownership change of 25 percentage points has occurred, the change in ownership is only slighty less than 25%. Accordingly, the transfer restrictions have not been put in place by our Board of Directors; however, if both of the foregoing events were to occur together and our Board of Directors were to elect to impose them, they could become operative in the future. There can be no assurance that the circumstances will not be met in the future, or in the event that they are met, that our Board of Directors would choose to impose these restrictions or that, if imposed, such restrictions would prevent an ownership change from occurring.

 

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Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Our principal executive offices are located in Houston, Texas. This facility is leased until 2013. We also have a regional office in Dublin, California, an engineering office in La Porte, Texas and representative offices in Washington D.C., Sacramento, California and Austin, Texas.

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

Item 3. Legal Proceedings

See Note 17 of the Notes to Consolidated Financial Statements for a description of our legal proceedings.

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

None.

 

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PART II

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

Market Information and Stockholder Matters

On January 31, 2008, pursuant to our Plan of Reorganization, our previously outstanding common stock was canceled and we authorized and began issuance of 485 million shares of reorganized Calpine Corporation common stock to settle unsecured claims pursuant to our 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 common stock for each quarter of the calendar years 2009 and 2008, as reported on the NYSE.

 

     High    Low

2009

     

First Quarter

   $             9.34    $             4.76

Second Quarter

     14.95      6.64

Third Quarter

     13.75      10.10

Fourth Quarter

     12.25      10.14

2008

     

First Quarter

   $ 19.51    $ 15.00

Second Quarter

     23.36      17.77

Third Quarter

     22.83      12.08

Fourth Quarter

     13.48      6.35

As of December 31, 2009, there were 114 stockholders on record of our common stock. See Note 16 of the Notes to Consolidated Financial Statements for a discussion of the effects of emergence from Chapter 11 on our capital structure.

To manage the risk of significant limitations on our ability to utilize our tax NOL carryforwards, our amended and restated certificate of incorporation permits our Board of Directors to meet to determine whether to impose certain transfer restrictions on our common stock in the following circumstances: if, prior to February 1, 2013, our Market Capitalization declines by at least 35% from our Emergence Date Market Capitalization of approximately $8.6 billion (in each case as defined and calculated pursuant to our amended and restated certificate of incorporation) and at least 25 percentage points of shift in ownership has occurred with respect to our equity for purposes of Section 382 of the IRC. We believe, as of the filing of this Report, we have experienced declines in our stock price of more than 35% from our Emergence Date Market Capitalization. While we don’t believe an ownership change of 25 percentage points has occurred, the change in ownership is only slightly less than 25%. Accordingly, the transfer restrictions have not been put in place by our Board of Directors; however, if both of the foregoing events were to occur together and our Board of Directors were to elect to impose them, they could become operative in the future. There can be no assurance that the circumstances will not be met in the future, or in the event that they are met, that our Board of Directors would choose to impose these restrictions or that, if imposed, such restrictions would prevent an ownership change from occurring.

Should our Board of Directors elect to impose these restrictions, they shall have the authority and discretion to determine and establish the definitive terms of the transfer restrictions provided that they apply to purchases by owners of 5% or more of our common stock including any owners who would become owners of 5% or more of our common stock via such purchase. The transfer restrictions will not apply to the disposition of

 

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shares provided they are not purchased by a 5% or more owner. If these transfer restrictions are imposed, any increase in the value of our common stock shall not result in the lapse of the transfer restrictions unless the increase in value of our common stock (determined on a weighted average 30-day trading period) shall be at least 10% greater than the trigger price. Our Board of Directors’ ability to impose transfer restrictions will terminate on the fifth anniversary of our Emergence Date; however, any transfer restrictions imposed prior to such fifth anniversary will remain in effect until one of the trigger provisions is no longer satisfied.

We have never paid cash dividends on our common stock. As our ability to pay cash dividends on our common stock is restricted under our First Lien Credit Facility and certain of our other debt agreements, 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 and financing restrictions and such other factors as our Board of Directors may deem relevant. See Item 1A. “Risk Factors,” including “— Risks Relating to Our Common Stock” for a discussion of additional risks related to an investment in our common stock.

Repurchase of Equity Securities — Upon vesting of restricted stock awarded by us to employees, we withhold shares to cover employees’ tax withholding obligations, other than for employees who have chosen to make tax withholding payments in cash. We withheld a total of 262,540 shares during 2009 that are included in treasury stock. We do not have a stock repurchase program. As set forth in the table below, we withheld 240 shares during the fourth quarter of 2009.

 

Period

   (a)
Total Number of
Shares Purchased
   (b)
Average Price
Paid Per Share
   (c)
Total Number of
Shares Purchased
as Part of
Publicly Announced
Plans or Programs
   (d)
Maximum Number
of Shares That May
Yet Be Purchased
Under the

Plans or Programs

November

   100    $             10.97       n/a

December

   140    $ 11.23       n/a
               

Total

   240    $ 11.12       n/a
               

 

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Stock Performance Graph

The performance graph below compares cumulative return on our common stock for the period February 7, 2008 through December 31, 2009, with the cumulative return of Standard & Poor’s 500 Index (S&P 500) and the S&P 500 Utility Index. Since the reorganized Calpine Corporation common stock began “regular way” trading on the NYSE on February 7, 2008, stock performance prior to February 7, 2008 does not provide meaningful comparison and has not been provided.

The graph below compares each period assuming that $100 was invested on February 7, 2008 in our common stock and each of above indices and that all dividends are reinvested. The returns shown below may not be indicative of future performance.

LOGO

 

Company / Index

   February 7, 2008    December 31, 2008    December 31, 2009

Calpine Corporation

   $ 100    $ 43.86    $ 66.27

S&P 500 Index

     100      67.56      83.41

S&P Utility Index

     100      74.38      79.44

Copyright© 2010 Standard & Poor’s, Inc., Zacks Investments Research, Inc., All rights reserved

 

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Item 6. Selected Financial Data

SELECTED CONSOLIDATED FINANCIAL DATA

 

    Years Ended December 31,  
    2009   2008     2007   2006     2005  
    (in millions, except earnings (loss) per share)  

Statement of Operations data:

         

Operating revenues

  $       6,564   $       9,937      $       7,970   $       6,937      $       10,302   
                                   

Income (loss) before discontinued operations attributable to Calpine(1)

  $ 149   $ (13   $ 2,693   $ (1,765   $ (9,881

Discontinued operations, net of tax, attributable to Calpine

        23                   (58
                                   

Net income (loss) attributable to Calpine(1)

  $ 149   $ 10      $ 2,693   $ (1,765   $ (9,939
                                   

Basic earnings (loss) per common share(2):

         

Income (loss) before discontinued operations attributable to Calpine (1)

  $ 0.31   $ (0.03   $ 5.62   $ (3.68   $ (21.32

Discontinued operations, net of tax, attributable to Calpine

        0.05                   (0.12
                                   

Net income (loss) per common share attributable to Calpine(1)

  $ 0.31   $ 0.02      $ 5.62   $ (3.68   $ (21.44
                                   

Diluted earnings (loss) per common share(2):

         

Income (loss) before discontinued operations attributable to Calpine (1)

  $ 0.31   $ (0.03   $ 5.62   $ (3.68   $ (21.32

Discontinued operations, net of tax, attributable to Calpine

        0.05                   (0.12
                                   

Net income (loss) per common share attributable to Calpine(1)

  $ 0.31   $ 0.02      $ 5.62   $ (3.68   $ (21.44
                                   

Balance Sheet data(3):

         

Total assets

  $ 16,650   $ 20,738      $ 19,050   $ 18,590      $ 20,545   

Short-term debt and capital lease obligations(4)

    463     716        1,710     4,569        5,414   

Long-term debt and capital lease obligations(4)(5)

    8,996     9,756        9,946     3,352        2,462   

Liabilities subject to compromise(5)

               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 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) Although earnings (loss) per share information for the years ended December 31, 2007, 2006 and 2005 is presented, it is not comparable to the information presented for the years ended December 31, 2009 and 2008, due to the changes in our capital structure on the Effective Date, which also included termination of all outstanding convertible securities.

 

(3) See Note 16 of the Notes to Consolidated Financial Statements regarding certain “plan effect” adjustments to our Consolidated Balance Sheet as of the Effective Date.

 

(4)

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 our Chapter 11 filings constituted

 

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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 First Lien Facilities.

 

(5) LSTC included unsecured and under secured liabilities incurred prior to the Petition Date and excluded liabilities that are fully secured or liabilities of our subsidiaries or affiliates that did not make 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 subsequently reclassified $3.7 billion from LSTC back to long-term debt based upon the terms of our Plan of Reorganization at December 31, 2007. See Note 16 of the Notes to Consolidated Financial Statements for more information.

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

Forward-Looking Information

This Management’s 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.”

INTRODUCTION AND OVERVIEW

Our Business

We are the largest independent wholesale power company in the U.S. measured by power produced. We own and operate natural gas-fired and geothermal power plants in North America and have a significant presence in major competitive power markets in the U.S., including California and Texas, and to a lesser extent, in the competitive PJM, ISO NE and NYISO markets. We sell wholesale power, steam, capacity, renewable energy credits and ancillary services to our customers, including utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities, power marketers and others. We purchase natural gas as fuel for our power plants, engage in related natural gas transportation and storage transactions and we purchase electric transmission rights to deliver power to our customers. We also enter into natural gas and power-related commodity and derivative transactions to financially hedge certain business risks and optimize our portfolio of power plants. Our goal is to be recognized as the premier independent power company in the U.S. as measured by our customers, regulators, shareholders and communities in which our power plants reside. We seek to achieve sustainable growth through financially disciplined power plant development, construction, operations and ownership.

Our portfolio, including partnership interests, consists of 77 operating power plants, located throughout 16 states and Canada, with an aggregate generation capacity of approximately 24,802 MW. It is comprised of two types of power generation technologies: natural gas-fired combustion turbines, which are primarily combined-cycle plants, and renewable geothermal conventional steam turbines. We are among the world’s largest owners and operators of industrial gas turbines as well as cogeneration power plants. Our Geysers Assets located in northern California represent the largest geothermal power generation portfolio in the U.S. and produced approximately 21% of all renewable energy produced in the state of California during 2008. Geothermal energy is one of the only baseload renewable energy supplies that exists today.

We assess our business 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. Our reportable segments are West (including geothermal), Texas, Southeast and North (including Canada). In these segments we have an aggregate generation capacity of 7,910 MW in the West, 7,392 MW in Texas, 6,083 MW in the Southeast and 3,417 MW in the North. Our Geysers Assets, included in our West segment, have generation capacity of approximately 725 MW from 15 operating power plants.

 

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We remain focused on increasing our earnings and generating cash flow sufficient to maintain adequate levels of liquidity in order to service our debt, meet our collateral needs and fund our operations and growth. 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.

Our Regulatory and Environmental Profile

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 plants. Federal and state legislative and regulatory actions continue to change how our business is regulated. The federal government is expected to take action on climate change legislation, as well as other air pollutant emissions, and many states and regions in the U.S. have implemented or are considering implementing regulations to reduce GHG emissions. We are actively participating in these debates at the federal, regional and state levels. For a further discussion of the environmental and other governmental regulations that affect us, see “— Governmental and Regulatory Matters” in Item 1. of this Report. Although we cannot predict the ultimate effect future climate change legislation or regulations could have on our business, we believe that we will be less adversely impacted by potential cap-and-trade limits, carbon taxes or required environmental upgrades as a result of future potential regulation or legislation addressing GHG, other air emissions, as well as water use or emissions, than compared to our competitors who use other fossil fuels or steam condensation technologies.

Since our inception in 1984, we have been a leader in environmental stewardship and have invested exclusively in clean power generation to become a recognized leader in developing, constructing, owning and operating an environmentally responsible portfolio of power plants. The combination of our Geysers Assets and our high efficiency portfolio of natural gas-fired power plants results in substantially lower emissions of these gases compared to our competitors’ power plants using other fossil fuels, such as coal. Consequently, our power generation portfolio has the lowest GHG footprint per MWh of any major independent power producer in the U.S. In addition, we strive to preserve our nation’s valuable water and land resources. To condense steam, we use cooling towers with a closed water cooling system, or air cooled condensers and do not employ “once-through” water cooling, which uses large quantities of water from adjacent waterways negatively impacting aquatic life. Since our plants are modern and efficient and utilize clean burning natural gas, we do not require large areas of land for our power plants nor do we require large specialized landfills for the disposal of coal ash or nuclear plant waste.

Our Market and Our Key Financial Performance Drivers

The market spark spread, sales of RECs, revenues from our steam sales and the results from our marketing, hedging and optimization activities are the primary components of our Commodity Margin and contribute significantly to our financial results. The market spark spread is primarily impacted by natural gas prices, weather and reserve margins, which impact both our supply and demand fundamentals. Those factors, plus the relationship between our operating Heat Rate compared to the Market Heat Rate, our power plant operating performance and availability are key to our financial performance.

Depending upon our hedge levels and holding other factors constant, increases in natural gas prices tend to increase our Commodity Margin and decreases in natural gas prices tend to decrease our Commodity Margin because we generally have lower Heat Rates and are more efficient than our competitors. 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 that 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 power generated, the lower our Heat Rate. The lower our operating Heat Rate compared to the Market Heat Rate, the more favorable the impact on our Commodity Margin. Holding all other factors constant, our Commodity Margin increases when we are able to lower our operating Heat Rate compared

 

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to the Market Heat Rate and conversely decreases when our operating Heat Rate increases compared to the Market Heat Rate. See also “— The Market for Power — Our Power Market Economics” in Item 1. of this Report for additional information on how these factors impact our Commodity Margin.

Current Year Operational Developments

During 2009, we have continued to implement our strategy to become the premier independent power company in the U.S. and achieve sustainable growth through financially disciplined power plant development, construction, operations and ownership. We have made some notable achievements that are listed below:

 

   

On February 4, 2010, we received the Prevention of Significant Deterioration, or PSD, air permit, the final permit necessary, to begin construction of our Russell City Energy Center. We hope to complete financing and break ground for this new state-of-the-art power plant during 2010 with commercial operations scheduled to begin in 2013. Russell City Energy Center is intended to become the first power plant in the U.S. with a federal limit on GHG emissions, and will be designed to operate in a way that produces 25% fewer GHG emissions than the CPUC standard.

 

   

Throughout 2009, our plant operating personnel exceeded the first quartile performance for employee lost time incident rate for fossil fuel electric power generation companies with 1,000 or more employees.

 

   

Our Geysers Assets generated approximately 6 million MWh and achieved an exceptional equivalent availability factor of over 97%. Our natural gas-fired fleet achieved exceptional performance during 2009, with an equivalent forced outage factor of 2.7%, an improvement of 35% over full year 2008.

 

   

We completed 14 major inspections and 13 hot gas path inspections on schedule and on budget during 2009 and completed one of several planned natural gas-fired turbine upgrades and two steam turbine upgrades, which not only added incremental capacity but improved the efficiency of the entire turbines.

 

   

OMEC, located in San Diego, California, achieved commercial operations on October 3, 2009, adding 608 MW of capacity to our fleet.

 

   

Under one of our new PPAs, we will modernize and upgrade our Los Esteros Critical Energy Facility to add 120 MW by converting it from simple-cycle (peaking) to combined-cycle technology, increasing the efficiency and environmental performance of the power plant.

 

   

We successfully restructured and streamlined our power and commercial operations, as well as our corporate functions, to more effectively manage our business and reduce expenses.

Customer-Oriented Origination Business

During 2009, we reorganized our customer origination function to allow our dedicated group of professionals to more effectively help manage this function. This effort is beginning to deliver real, tangible results and we, through certain of our wholly owned subsidiaries, entered into new PPAs and amended certain PPAs, which are all on mutually beneficial terms and many are subject to regulatory approvals. They include the following:

 

   

We and PG&E have agreed to an extension of the term and an increase in the volume under the existing contracts for delivery of power from our Geysers Assets. Our Geysers Assets currently provide PG&E 375 MW of power under two contracts. We have agreed to increase the volume to 425 MW through 2017, and from 2018 through the end of 2021, our Geysers Assets will supply PG&E 250 MW of renewable energy.

 

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Our wholly owned subsidiaries, Gilroy Energy Center, LLC, Creed and Goose Haven, have entered into a replacement contract with PG&E, whereby PG&E will have greater dispatch flexibility for all 11 of our peaking units in California through 2017 and for seven of our peaking units through 2021.

 

   

We and PG&E negotiated a new agreement to replace the existing CDWR contract and facilitate the upgrade of our Los Esteros Critical Energy Facility from a 188 MW simple-cycle generation power plant to a 308 MW combined-cycle generation power plant. In addition to the increase in capacity, the upgrade will increase the efficiency and environmental performance of the power plant by lowering the Heat Rate. While the upgrade is under construction, we will provide capacity to PG&E from our Gilroy Cogeneration Plant. Upon completion of the upgrade, PG&E will purchase all of the capacity from our Los Esteros Critical Energy Facility for a term of ten years.

 

   

We have entered into a new tolling arrangement with PG&E for all of the capacity from our Delta Energy Center from 2011 through 2013.

 

   

We executed a resource adequacy agreement for all of the capacity from our Pastoria Energy Center with Southern California Edison for 2012 and 2013.

 

   

We executed a contract for 500 MW of capacity from our Morgan Energy Center with the Tennessee Valley Authority through 2011.

 

   

We executed a contract for 485 MW of capacity from our Carville Energy Center with Entergy Corporation through May 2012.

 

   

We executed a contract for 200 MW of capacity from our Oneta Energy Center with American Electric Power through 2010.

 

   

In addition to the suite of products we plan to supply through the agreements described above, our commercial operations team is also identifying creative opportunities to match our capabilities with the needs of our customers. During 2009, we entered into a PPA with the Los Angeles Department of Water and Power to provide integration services of up to 270 MW, leveraging our quick-responding natural gas-fired Hermiston Power Project located in Hermiston, Oregon, as well as its contracted transmission resources in the northwest as back up for wind generated power.

The last transaction is an indication of the need our customers and more generally the market will have to utilize flexible natural gas-fired generation to assure reliability of supply while integrating intermittent and variable renewable resources, such as wind and solar power, that they are required to procure as part of a renewable energy portfolio.

Capital Management

We have opportunistically completed several financing transactions for a total of approximately $3.0 billion to improve our flexibility and management of our balance sheet. Significant transactions in 2009 include, but are not limited to, the following:

 

   

On November 24, 2009, we amended and extended our Steamboat project debt which extended the maturity date from December 2011 to November 24, 2017.

 

   

On December 11, 2009, we amended the letter of credit facility related to our subsidiary, Calpine Development Holdings, Inc., to extend the maturity from January 31, 2010 to December 11, 2012, with an option to increase the letters of credit available from $150 million to $200 million by satisfying certain conditions.

 

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On August 20, 2009, we amended our First Lien Credit Facility and related collateral agency and intercreditor agreement in several respects to give us greater flexibility, including allowing us to exchange First Lien Credit Facility term loans for First Lien Notes.

 

   

On October 21, 2009, we issued approximately $1.2 billion aggregate principal amount of First Lien Notes in a private placement as a permitted debt exchange pursuant to our First Lien Credit Facility, which retired an aggregate principal amount of term loans under our First Lien Credit Facility equal to the aggregate principal amount of First Lien Notes issued. As a result of the issuance of the First Lien Notes, we were able to extend the maturities of approximately $1.2 billion in debt to 2017, at the same time converting it from a variable to a fixed interest rate.

 

   

On May 19, 2009, our wholly owned subsidiaries, CCFC and CCFC Finance, issued approximately $1.0 billion aggregate principal amount of CCFC New Notes in a private placement. The net proceeds were used to repay the CCFC Term Loans, CCFC Old Notes and CCFCP Preferred Shares. As a result of the CCFC Refinancing transactions, we were able to extend the maturities of approximately $1.0 billion of debt by several years, at the same time converting it from a variable to a fixed interest rate and lowering our effective interest rates.

 

   

On January 21, 2009, we closed on our Deer Park $156 million senior secured credit facilities, which included a $150 million term facility and a $6 million letter of credit facility. Proceeds received were used to settle an existing commodity contract of approximately $79 million, pay financing and legal fees, fund additional restricted cash and for general corporate purposes.

For a further discussion of our 2009 significant financing transactions, see “— Liquidity and Capital Resources.”

 

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RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2009 AND 2008

Below are our results of operations for the year ended December 31, 2009, as compared to the same period in 2008 (in millions, except for percentages and operating performance metrics). We have modified our presentation of commodity revenue and commodity expense to include cash settlements from our commodity marketing, hedging and optimization activities that were previously included in mark-to-market activity. Our 2008 commodity revenue and commodity expense information has been reclassified to conform to the current year presentation. 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.

 

     2009     2008     Change     % Change  

Operating revenues:

        

Commodity revenue

   $       6,463        9,876      $       (3,413)      (35 )% 

Mark-to-market activity(1)

     80        4        76      #   

Other revenue

     21        57        (36   (63
                          

Operating revenues

     6,564        9,937        (3,373   (34
                          

Cost of revenue:

        

Fuel and purchased energy expense:

        

Commodity expense

     3,896        7,352        3,456      47   

Mark-to-market activity(1)

     1        (71     (72   #   
                          

Fuel and purchased energy expense

     3,897        7,281        3,384      46   
                          

Plant operating expense

     897        918        21      2   

Depreciation and amortization expense

     467        433        (34   (8

Operating asset impairments

     4        33        29      88   

Other cost of revenue(2)

     84        114        30      26   
                          

Total cost of revenue

     5,349        8,779        3,430      39   
                          

Gross profit

     1,215        1,158        57      5   

Sales, general and other administrative expense

     183        215        32      15   

(Income) loss from unconsolidated investments in power plants

     (50     229        279      #   

Other operating expense

     18        26        8      31   
                          

Income from operations

     1,064        688        376      55   

Interest expense

     829        1,071        242      23   

Interest (income)

     (16     (47     (31   (66

Debt extinguishment costs

     76        13        (63   #   

Other (income) expense, net

     16        14        (2   (14
                          

Income (loss) before reorganization items, income taxes and discontinued operations

     159        (363     522      #   

Reorganization items

     (1     (302     (301   #   
                          

Income (loss) before income taxes and discontinued operations

     160        (61     221      #   

Income tax expense (benefit)

     15        (47     (62   #   
                          

Income (loss) before discontinued operations

     145        (14     159      #   

Discontinued operations, net of tax expense of $14 in 2008

            23        (23   #   
                          

Net income

     145        9        136      #   

Net loss attributable to the noncontrolling interest

     4        1        3      #   
                          

Net income attributable to Calpine

   $ 149      $ 10      $ 139      #   
                          
     2009     2008     Change     % Change  

Operating Performance Metrics:

        

MWh generated (in thousands)(3)

     88,339        87,762        577      1

Average availability

     92.1     90.5     1.6      2   

Average total MW in operation

     23,414        23,037        377      2   

Average capacity factor, excluding peakers

     48.7     47.9     0.8      2   

Steam Adjusted Heat Rate

     7,263        7,231        (32     

 

  # Variance of 100% or greater

 

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(1) Amount represents the unrealized portion of our commodity mark-to-market activity as well as a non-cash gain from amortization of prepaid power sales agreements.

 

(2) Includes $5 million and nil of RGGI compliance costs for the years ended December 31, 2009 and 2008, respectively, which is a component of Commodity Margin.

 

(3) Represents generation from power plants that we both consolidate and operate.

Commodity revenue and commodity expense decreased for the year ended December 31, 2009 compared to 2008, largely due to lower natural gas prices which decreased 53% in 2009 compared to 2008; however, commodity revenue, net of commodity expense, increased $43 million for the year ended December 31, 2009 compared to 2008, primarily due to:

 

   

higher average hedge margins in 2009 compared to 2008;

 

   

average annual Market Heat Rates were relatively unchanged for the year ended December 31, 2009 compared to 2008, with the exception of our Southeast segment which experienced a 35% increase in generation in 2009 compared to 2008 largely due to higher natural gas generation displacement of coal generation in certain sub-markets in our Southeast segment caused by lower natural gas prices resulting in higher Market Heat Rates; partially offset by

 

   

lower natural gas prices in 2009 compared to 2008 and the resulting negative impact on our open positions.

These factors were also positively impacted by our operational performance where we experienced a 1% increase in generation as well as a 2% increase in both our average availability and average capacity factor, excluding peakers, for the year ended December 31, 2009 compared to 2008.

Revenues from mark-to-market activity increased for the year ended December 31, 2009 compared to 2008, which is consistent with a falling commodity price environment. Expenses from mark-to-market activity increased for the year ended December 31, 2009 compared to 2008, due to the impact of natural gas market price volatility on our natural gas hedge position for our generation portfolio.

Other revenue decreased for the year ended December 31, 2009 compared to 2008, primarily related to a $14 million decrease in revenue from operation and maintenance contracts and a $7 million decrease in revenue from construction management projects completed in 2008. Also contributing to the decrease was an $11 million decrease in other revenue related to royalty income on oil and gas producing properties.

Normal, recurring plant operating expenses decreased by $24 million for the year ended December 31, 2009 compared to 2008, after accounting for $29 million in reimbursements for insurance claims from prior periods that reduced our 2008 and, to a much lesser extent, 2009 expenses. Additionally, major maintenance costs resulting from our plant outage schedule decreased $16 million and plant personnel costs related to stock-based compensation expense decreased $9 million for the year ended December 31, 2009 compared to 2008.

Depreciation and amortization expense increased for the year ended December 31, 2009 compared to 2008, primarily resulting from an increase of $25 million in the fourth quarter of 2009 related to a revision in the estimated useful lives and salvage values of our power plants and related equipment and changing our Geysers Assets depreciation from the units of production method to the straight line method as well as a $9 million increase resulting from an upward revision in the rate used to depreciate our Geysers Assets due to changes in our estimate of our future development costs for the first nine months of 2009. See Note 3 of the Notes to Consolidated Financial Statements for further information regarding our change in useful lives and salvage values as well as our change from the units of production method to the straight line depreciation method for our Geysers Assets.

 

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Our operating asset impairments decreased for the year ended December 31, 2009 compared to 2008, primarily from a $33 million impairment recorded in 2008 relating to our Auburndale Peaking Energy Center resulting from lower forecasted future cash flows.

Other cost of revenue decreased for the year ended December 31, 2009 compared to 2008, as a result of a decrease of $17 million related to the discontinuation of the amortization of other assets associated with the deconsolidation and subsequent sale of Auburndale in 2008 as well as an $11 million decrease in royalty expense due to lower revenues from our Geysers Assets resulting from lower spot market power prices in the year ended December 31, 2009 compared to 2008. The decrease was partially offset by an increase of $5 million in expenses related to RGGI compliance costs in the Northeast which was initiated in 2009.

Sales, general and other administrative expense decreased for the year ended December 31, 2009 compared to 2008, due to a $10 million decrease in personnel costs and stock-based compensation expense resulting primarily from a lower headcount in 2009 as well as a $13 million decrease in legal and consulting expenses. In addition, we experienced a $5 million favorable year over year change in our bad debt expense.

Our (income) loss from unconsolidated investments in power plants increased for the year ended December 31, 2009 compared to 2008, primarily due to an impairment loss of $180 million related to our equity interest in Auburndale recorded during the year ended December 31, 2008. Also contributing to the increase was income from our investment in Greenfield LP of $16 million for the year ended December 31, 2009 compared to a loss of $5 million for the year ended December 31, 2008, which is due to Greenfield LP achieving commercial operations in October 2008. We also had income of $32 million related to our investment of OMEC, of which, $4 million related to OMEC achieving commercial operation in October 2009 and a $28 million gain related to mark-to-market activities from interest rate swap contracts compared to a loss of $55 million incurred for the year ended December 31, 2008, related to unrealized mark-to-market losses from interest rate swap contracts. See Note 4 of the Notes to Consolidated Financial Statements for further information regarding our unconsolidated investments.

Other operating expense decreased for the year ended December 31, 2009 compared to 2008, due to impairments of $13 million related to development projects recorded in 2008 which was partially offset by an increase of $6 million in project development expense for the year ended December 31, 2009 compared to 2008, related to Russell City Energy Center which is under advanced development.

Due to the changes in our capital structure on the Effective Date, our interest expense for the years ended December 31, 2009 and 2008, is not directly comparable. Interest expense decreased primarily due to $135 million in post-petition interest related to pre-emergence debt recorded in the first quarter of 2008 and $27 million for settlement obligations related to the Canadian Debtors and other deconsolidated foreign entities recorded prior to their reconsolidation in February 2008. In addition, interest expense decreased for the year ended December 31, 2009 compared to 2008, due to lower average interest rates on our variable rate debt resulting from a decrease in LIBOR over the same periods. The annualized effective interest rates on our consolidated debt, excluding the impacts of capitalized interest and unrealized mark-to-market gains (losses) on interest rate swaps, after amortization of deferred financing costs and debt discounts, were 8.0% and 8.8% for the year ended December 31, 2009 and 2008, respectively. The decrease in interest expense was partially offset by the negative period over period impact of $153 million related to interest rate swap settlements resulting from a decrease in LIBOR.

Interest income decreased for the year ended December 31, 2009 compared to 2008, largely resulting from lower average interest rates earned on our cash balances which were primarily invested in U.S. Treasury securities or government-backed securities for the year ended December 31, 2009 compared to primarily invested in institutional-backed money market accounts for the year ended December 31, 2008.

 

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Debt extinguishment costs increased for the year ended December 31, 2009 compared to 2008, primarily due to $76 million in debt extinguishment costs associated with the retirement of the term loans under the First Lien Credit Facility in October 2009, the refinancing of our CCFC Old Notes and CCFC Term Loans in May and June 2009 and the CCFCP Preferred Shares that were redeemed on or before July 1, 2009. This increase was partially offset by $13 million in debt extinguishment costs for the write-off of unamortized deferred financing costs and other costs associated with the refinancing of all outstanding indebtedness under the existing Blue Spruce term loan facility in February 2008 as well as the refinancing of our Metcalf term loan facility and preferred interests in June 2008.

During the year ended December 31, 2009, reorganization items primarily consisted of settlements of various disputed claims. During the year ended December 31, 2008, reorganization items primarily consisted of $206 million in gains on asset sales, a $71 million gain on the reconsolidation of the Canadian Debtors and other deconsolidated foreign entities, a $62 million credit related to the settlement of claims with the Canadian Debtors and other deconsolidated foreign entities, a $34 million credit for RockGen related to a prior period which we determined was not material to any period, a $12 million credit related to the settlement with Rosetta of our fraudulent conveyance claim and $85 million in professional and trustee fees related to activity managed by our third party advisors for our Chapter 11 and CCAA cases.

For the year ended December 31, 2009, we recorded tax expense of $15 million before discontinued operations compared to a benefit of $47 million for the year ended December 31, 2008. Due to the valuation allowances recorded against certain deferred tax assets, our effective tax rate differs considerably from the federal statutory rate. Our tax structure is comprised primarily of two taxable groups, CCFC and its subsidiaries and Calpine Corporation and its subsidiaries other than CCFC. CCFC and its subsidiaries no longer have a valuation allowance recorded against its deferred tax assets due to its ability to generate sufficient income to utilize its NOLs. Our 2009 income tax expense primarily relates to a foreign tax expense of $2 million and $43 million expense relating to the reversal of prior years intraperiod tax allocation due to OCI gains partially offset by a $30 million tax benefit from the CCFC group. Our 2008 benefit for income taxes before discontinued operations primarily relates to a foreign tax benefit of $70 million recorded as a result of the Canadian Settlement Agreement, and intraperiod tax allocation benefit of $90 million, which was comprised of a $76 million tax benefit to continuing operations due to current OCI gains and a $14 million tax benefit in income from discontinued operations, offset by tax expense of approximately $100 million on CCFC’s income. See Note 11 of the Notes to Consolidated Financial Statements for further information.

During the year ended December 31, 2008, we recorded $23 million in discontinued operations, net of taxes of $14 million, related to the settlement with Rosetta of all of our outstanding claims related to our domestic oil and gas assets we sold to Rosetta for $1.1 billion in 2005. See Note 6 of the Notes to Consolidated Financial Statements for further information.

 

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RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2008 AND 2007

Below are our results of operations for the year ended December 31, 2008, as compared to the same period in 2007 (in millions, except for percentages and operating performance metrics). We have modified our presentation of commodity revenue and commodity expense to include cash settlements from our commodity marketing, hedging and optimization activities that were previously included in mark-to-market activity. Our 2008 and 2007 commodity revenue and commodity expense information has been reclassified to conform to the current year presentation. 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.

 

     2008     2007     Change     % Change  

Operating revenues:

        

Commodity revenue

   $       9,876        7,903      $       1,973      25

Mark-to-market activity(1)

     4        10        (6   (60

Other revenue

     57        57               
                          

Operating revenues

     9,937        7,970        1,967      25   
                          

Cost of revenue:

        

Fuel and purchased energy expense:

        

Commodity expense

     7,352        5,692        (1,660   (29

Mark-to-market activity(1)

     (71     (9     62      #   
                          

Fuel and purchased energy expense

     7,281        5,683        (1,598   (28
                          

Plant operating expense

     918        749        (169   (23

Depreciation and amortization expense

     433        463        30      6   

Operating asset impairments

     33        44        11      25   

Other cost of revenue

     114        136        22      16   
                          

Total cost of revenue

     8,779        7,075        (1,704   (24
                          

Gross profit

     1,158        895        263      29   

Sales, general and other administrative expense

     215        146        (69   (47

Loss from unconsolidated investments in power plants

     229        21        (208   #   

Other operating expense

     26        23        (3   (13
                          

Income from operations

     688        705        (17   (2

Interest expense

     1,071        2,019        948      47   

Interest (income)

     (47     (64     (17   (27

Debt extinguishment costs

     13        (1     (14   #   

Other (income) expense, net

     14        (138     (152   #   
                          

Loss before reorganization items, income taxes and discontinued operations

     (363     (1,111     748      67   

Reorganization items

     (302     (3,258     (2,956   (91
                          

Income (loss) before income taxes and discontinued operations

     (61     2,147        (2,208   #   

Income tax benefit

     (47     (546     (499   (91
                          

Income (loss) before discontinued operations

     (14     2,693        (2,707   #   

Discontinued operations, net of tax expense of $14 in 2008

     23               23        
                          

Net income

     9        2,693        (2,684   #   

Net loss attributable to the noncontrolling interest

     1               1        
                          

Net income attributable to Calpine

   $ 10      $ 2,693      $ (2,683   #   
                          
     2008     2007     Change     % Change  

Operating Performance Metrics:

        

MWh generated (in thousands)(2)

     87,762        90,811        (3,049   (3 )% 

Average availability

     90.5     90.8     (0.3     

Average total MW in operation

     23,037        24,679        (1,642   (7

Average capacity factor, excluding peakers

     47.9     46.9     1.0      2   

Steam Adjusted Heat Rate

     7,231        7,190        (41   (1

 

  # Variance of 100% or greater

 

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(1) Amount represents the unrealized portion of our mark-to-market activity as well as a non-cash gain from amortization of prepaid power sales agreements.

 

(2) Represents generation from power plants that we both consolidate and operate.

Commodity revenue and commodity expense increased for the year ended December 31, 2008 compared to 2007, largely due to higher natural gas prices which increased 25% in 2008 compared to 2007. In addition, commodity revenue, net of commodity expense, increased $313 million for the year ended December 31, 2008, compared to 2007 primarily due to:

 

   

higher market spark spreads on open positions due to higher natural gas prices throughout the first three quarters of 2008 in our key Texas and West markets which benefited our power plants in these regions as they operated more efficiently against corresponding Market Heat Rates;

 

   

higher Market Heat Rates in the second quarter of 2008, particularly in Texas which resulted from higher temperatures and transmission congestion in the South and Houston zones;

 

   

higher realized spark spreads for our generally higher levels of hedging in all regions; and

 

   

earnings from settlement of dedesignated hedges, the value for which was previously reflected in OCI.

Generation decreased 3% despite a 2% increase in our average capacity factor, excluding peakers, due to a 7%, or 1,642 MW, decrease in our average total MW in operation for the year ended December 31, 2008, compared to 2007. The generation decrease primarily resulted from power plant sales in 2007, the deconsolidation and subsequent sale of Auburndale in 2008 and an increase in the number of unscheduled outages in 2008 compared to 2007.

Results of net unrealized mark-to-market activity are driven primarily from our commodity hedging activities that do not qualify for hedge accounting. The $56 million increase for the year ended December 31, 2008 compared to 2007, is largely due to a decrease in expenses from mark-to-market activity primarily driven by the impact of natural gas market price volatility on our natural gas hedge position for our generation portfolio.

Plant operating expense increased during the year ended December 31, 2008, compared to the year ended December 31, 2007, primarily as a result of a $92 million increase in expense for major maintenance for scheduled outages related to the life cycle of our power plant fleet and an increase of $25 million in plant personnel costs related to stock-based compensation expense for equity awards issued in 2008. The increase in major maintenance is driven by the fact that we placed 23 power plants in service in the 2001-2002 time frame and many have reached their 24,000 or 48,000 hour major inspection operating intervals. Routine operating and repair costs also contributed $31 million to the increase in plant operating expense which related to increases in chemical costs and other consumables, and increases in routine repairs. A $16 million increase in expense for outages, many of which occurred in 2007 and equipment repairs made in 2008, caused by equipment failures, net of insurance recoveries, also contributed to the increase in plant operating expense for the year ended December 31, 2008, compared to 2007.

Depreciation and amortization expense decreased for the year ended December 31, 2008, compared to the year ended December 31, 2007, primarily due to an upward revision in the estimated useful life of our Geysers Assets as well as the sale of Acadia PP in September 2007. The upward revision in the estimated useful life of our Geysers Assets relates to our reservoir replenishment activities which extends the estimated economic life of our Geysers Assets from 2034 to 2050.

 

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Our operating asset impairments for the year ended December 31, 2008, consisted of a $33 million impairment relating to our Auburndale Peaking Energy Center resulting from lower forecasted future cash flows. Operating asset 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 power pricing of new power transmission capacity from the PJM market into Long Island.

Other cost of revenue decreased for the year ended December 31, 2008, compared to the year ended December 31, 2007, as a result of an $8 million decrease for the sale of PSM in March 2007, a $10 million decrease in operating lease expense due to the termination of the lease associated with our purchase of the RockGen Energy Center in January 2008 and a decrease of $8 million related to the discontinuation of the amortization of other assets associated with the deconsolidation and subsequent sale of Auburndale in 2008. These decreases were partially offset by a $5 million increase in royalty expense due to higher spot market power prices in 2008 compared to 2007.

Sales, general and other administrative expense was higher for the year ended December 31, 2008, compared to the same period in 2007 due to a $42 million increase in personnel costs resulting primarily from higher stock-based compensation expense arising from the grant of equity awards during the first quarter of 2008 and a $15 million increase in legal and consulting expenses.

Our loss from unconsolidated investments in power plants increased in 2008 compared to 2007 primarily due to an impairment loss of $180 million related to our equity interest in Auburndale during the year ended December 31, 2008. We also incurred an increase of $47 million in unrealized mark-to-market losses from interest rate swap contracts related to our investment in OMEC. The increase was partially offset by $9 million in income from our investment in RockGen and an $8 million reduction in losses related to our investment in Greenfield LP for the year ended December 31, 2008, compared to 2007. See Note 4 of the Notes to Consolidated Financial Statements for further information regarding our unconsolidated investments.

Due to the changes in our capital structure on the Effective Date, our interest expense for the years ended December 31, 2008 and 2007, is not directly comparable. Interest expense decreased primarily due to $376 million in post-petition interest related to pre-emergence debt recorded in 2007, resulting from the Canadian Settlement Agreement as well as $347 million in post-petition interest related to other pre-petition obligations recorded during the year ended December 31, 2007, which was partially offset by $135 million in post-petition interest recorded during the year ended December 31, 2008. In addition, interest expense decreased for the year ended December 31, 2008, compared to the year ended December 31, 2007, due to lower average debt balances and lower average interest rates. During the first quarter of 2008, we settled a portion of our debt through payment of cash and issuance of reorganized Calpine Corporation common stock pursuant to our Plan of Reorganization. Additionally, interest rates on our variable rate debt were lower for the year ended December 31, 2008, compared to 2007, due to a decrease in LIBOR over the same periods. The annualized effective interest rates on our consolidated debt, excluding the impacts of items not directly attributed to the cost of the debt instruments, after amortization of deferred financing costs and debt discounts, were 8.8% and 11.0% for the years ended December 31, 2008 and 2007, respectively. The decrease was partially offset by the negative period over period impact of $89 million related to interest rate swap settlements resulting from a decrease in LIBOR as well as $27 million for settlement obligations related to our Canadian subsidiaries recorded prior to their reconsolidation in February 2008.

Interest income decreased primarily due to lower average cash balances for the year ended December 31, 2008, compared to the same period in 2007 resulting from the distribution of cash pursuant to our Plan of Reorganization in the first quarter of 2008, and due to lower average interest rates.

Other (income) expense, net had an unfavorable variance primarily as a result of the non-recurrence of $135 million in income pertaining to a claim settlement with a customer which received court approval and was recorded during the third quarter of 2007. The claim related to the customer’s rejection of our energy services

 

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agreement following the customer’s bankruptcy filing and was unrelated to our Chapter 11 cases. Also contributing to the decrease was a loss of $13 million incurred during 2008 related to our settlement with Panda.

Debt extinguishment costs increased for the year ended December 31, 2008 compared to 2007, primarily due to $13 million in debt extinguishment costs for the write-off of unamortized deferred financing costs and other costs associated with the refinancing of all outstanding indebtedness under the existing Blue Spruce term loan facility in February 2008 as well as the refinancing of our Metcalf term loan facility and preferred interests in June 2008.

The table below lists the significant components of reorganization items for the years ended December 31, 2008 and 2007 (in millions):

 

     2008     2007     Change     % Change  

Provision for expected allowed claims

   $ (95   $ (3,687   $ (3,592   (97 )% 

Professional and trustee fees

               85                  217                  132      61   

Gains on asset sales

     (206)        (285     (79   (28

Asset impairments

            120        120      #   

Gain on reconsolidation of Canadian Debtors and other deconsolidated foreign entities

     (71)               71        

DIP Facility and First Lien Facilities financing and CalGen Secured Debt repayment costs

     (4)        202        206      #   

Interest (income) on accumulated cash

     (7)        (59     (52   (88

Other

     (4)        234        238      #   
                          

Total reorganization items

   $ (302)      $ (3,258   $ (2,956   (91
                          

 

 

# Variance of 100% or greater

Provision for Expected Allowed Claims — During the year ended December 31, 2008, our provision for expected allowed claims consisted primarily of a $62 million credit related to the settlement of claims with the Canadian Debtors and other deconsolidated foreign entities, a $12 million credit related to the settlement with Rosetta of our fraudulent conveyance claim and a $34 million credit for RockGen related to a prior period which we determined was not material to any period. During the year ended December 31, 2007, our provision for expected allowed claims consisted primarily of 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, accruals totaling $275 million for make whole premiums and/or damages related to the First Priority Notes, Second Priority Debt and Unsecured Notes settlements, $141 million resulting from the termination of the RockGen operating lease agreement and write-off of the related prepaid lease expense, $98 million resulting from settlements and repudiation of certain natural gas transportation and PPA contracts, and 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.

Professional and Trustee Fees — The decrease in professional fees for the year ended December 31, 2008, over the comparable period in 2007 resulted primarily from a decrease in activity managed by our third party advisors related to our Chapter 11 and CCAA cases.

Gains on Asset Sales — During the year ended December 31, 2008, gains on asset sales primarily resulted from the sales of the Hillabee and Fremont development project assets. During the year ended December 31, 2007, gains on asset sales primarily resulted from the sale of the Aries Power Plant, Goldendale Energy Center, PSM and Parlin Power Plant during 2007. See Note 6 of the Notes to Consolidated Financial Statements for further information.

 

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Asset Impairments — During the year ended December 31, 2007, asset impairment charges were primarily due to a pre-tax impairment charge of approximately $89 million to record our interest in Acadia PP at fair value less cost to sell.

Gain on Reconsolidation of Canadian Debtors and Other Deconsolidated Foreign Entities — During the year ended December 31, 2008, we recorded a gain of $71 million related to the reconsolidation of our Canadian subsidiaries. See Note 2 of the Notes to Consolidated Financial Statements for further information.

DIP Facility and First Lien Facilities Financing and CalGen Secured Debt Repayment Costs — During the year ended December 31, 2008, we recorded a $4 million credit related to a valuation revision for secured shortfall claims related to our Second Priority Debt. 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 $52 million of DIP Facility transaction costs, the write-off of $32 million in unamortized discount and deferred financing costs related to the CalGen Secured Debt, and $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. We also recorded transaction costs of $22 million related to the execution of a commitment letter to fund our First Lien Facilities as well as $13 million for secured shortfall claims relating to settlements for the First Priority Notes and the CalGen First Lien Debt during the year ended December 31, 2007.

Interest (Income) on Accumulated Cash — The decrease in interest income on accumulated cash for the year ended December 31, 2008, over the comparable period in 2007 related to our emergence from Chapter 11 at which time we ceased allocating a portion of interest income to reorganization items.

Other — Other reorganization items decreased primarily due to recording a gain of $4 million during the year ended December 31, 2008, versus a loss of $164 million in the year ended December 31, 2007, related to foreign exchange movements on LSTC denominated in a foreign currency and the non-recurrence of a charge of $14 million during the year ended December 31, 2007, resulting from debt pre-payment and make whole premium fees to the project lenders related to the sale of the Aries Power Plant. Also contributing to the decrease was $53 million in emergence incentive cost accruals related to our emergence from Chapter 11 recorded during the year ended December 31, 2007, while no such accruals were recorded in 2008.

For the year ended December 31, 2008, we recorded a tax benefit of $47 million before discontinued operations compared to a benefit of $546 million for the year ended December 31, 2007. Due to the valuation allowances recorded against certain deferred tax assets, our effective tax rate differs considerably from the federal statutory rate. Our tax structure is comprised primarily of two taxable groups, CCFC and its subsidiaries and Calpine Corporation and its subsidiaries other than CCFC. CCFC and its subsidiaries no longer have a valuation allowance recorded against its deferred tax assets due to its ability to generate sufficient income to utilize its NOLs. Our 2008 benefit for income taxes before discontinued operations primarily relates to a foreign tax benefit of $70 million recorded as a result of the Canadian Settlement Agreement, and intraperiod tax allocation benefit of $90 million, which was comprised of a $76 million tax benefit to continuing operations due to current OCI gains and a $14 million tax benefit in income from discontinued operations, offset by tax expense of approximately $100 million on CCFC’s income. Our 2007 benefit for income taxes consisting primarily of $485 million related to the release of valuation allowance in 2007. See Note 11 of the Notes to Consolidated Financial Statements for further information.

During the year ended December 31, 2008, we recorded $23 million in discontinued operations, net of taxes of $14 million, related to the settlement with Rosetta of all of our outstanding claims related to our domestic oil and gas assets we sold to Rosetta for $1.1 billion in 2005. See Note 6 of the Notes to Consolidated Financial Statements for further information.

 

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COMMODITY MARGIN AND ADJUSTED EBITDA

Management’s Discussion and Analysis of Financial Condition and Results of Operations includes financial information prepared in accordance with GAAP, as well as the non-GAAP financial measures, Commodity Margin and Adjusted EBITDA, discussed below, which we use as a measure of our performance. Generally, a non-GAAP financial measure is a numerical measure of financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP.

Commodity Margin by Segment for the Years Ended December 31, 2009 and 2008

We use the non-GAAP financial measure “Commodity Margin” to assess our performance by our reportable segments. Commodity Margin includes our power and steam revenues, sales of purchased power and natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, RGGI compliance costs, and cash settlements from our marketing, hedging and optimization activities that are included in mark-to-market activity, but excludes the unrealized portion of our mark-to-market activity and other 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 intend to represent gross profit (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 Note 18 of the Notes to Consolidated Financial Statements for a reconciliation of Commodity Margin to income (loss) from operations by segment.

The following tables show our Commodity Margin and related operating performance metrics by segment for the years ended December 31, 2009 and 2008. During the first quarter of 2009, we began assessing the performance of our regional segments to include the allocation (based upon each regional segment’s MWh) of revenues and expenses from our fuel management, Turbine Maintenance Group and certain non-region specific natural gas marketing and optimization and other corporate activities, which had formerly been separately reported as our “Other” segment. Additionally, we have modified our definition of Commodity Margin to include cash settlements from our marketing, hedging and optimization activities that were previously included in mark-to-market activity. Our 2008 Commodity Margin by segment information has been recast to conform to the current year presentation. In the “Change” and “% Change” columns below, favorable variances are shown without brackets while unfavorable variances are shown with brackets. The MWh generated by segment below represents generation from power plants that we both consolidated and operate.

 

West:    2009     2008     Change    % Change  

Commodity Margin (in millions)

   $             1,346      $             1,255      $             91    7

Commodity Margin per MWh generated

   $ 37.35      $ 33.79      $ 3.56    11   

MWh generated (in thousands)

     36,033        37,137        (1,104)    (3)   

Average availability

     92.3     89.1     3.2    4   

Average total MW in operation

     7,302        7,295        7      

Average capacity factor, excluding peakers

     64.1     65.9     (1.8)    (3)   

Steam Adjusted Heat Rate

     7,304        7,267        (37)    (1)   

West — Commodity Margin in our West segment increased by $91 million, or 7%, for the year ended December 31, 2009 compared to the year ended December 31, 2008. The increase was primarily a result of higher hedge levels and prices, sales of surplus emission allowances in the first quarter of 2009 and higher resource adequacy and REC revenues in 2009 compared to 2008. Market Heat Rates remained relatively

 

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unchanged across periods, and lower natural gas prices resulted in lower market spark spreads for the year ended December 31, 2009 compared to 2008. In addition, the current period benefited from the non-recurrence in 2009 of an unfavorable natural gas storage inventory price adjustment in September 2008. Consistent with the weaker price conditions, generation decreased 3% for the year ended December 31, 2009 compared to 2008, despite a 4% increase in our average availability. Commodity Margin per MWh generated increased 11% due in part to the effect of our positive portfolio hedge value being allocated across a reduced number of generated MWh for the year ended December 31, 2009 as compared to 2008.

 

Texas:    2009     2008     Change     % Change  

Commodity Margin (in millions)

   $             644      $             726      $ (82   (11 )% 

Commodity Margin per MWh generated

   $ 21.69      $ 22.40      $ (0.71   (3

MWh generated (in thousands)

     29,687        32,408        (2,721   (8

Average availability

     90.0     88.8                 1.2      1   

Average total MW in operation

     7,156        7,147        9        

Average capacity factor, excluding peakers

     47.4     51.6     (4.2   (8

Steam Adjusted Heat Rate

     7,142        7,082        (60   (1

Texas — Commodity Margin in our Texas segment decreased by $82 million, or 11%, for the year ended December 31, 2009 compared to 2008. This decrease is primarily attributable to weaker natural gas prices that were 56% lower in 2009 compared to 2008. Overall, Market Heat Rates were relatively unchanged in 2009 compared to 2008; however, Market Heat Rates were higher in the third quarter of 2009 compared to the same period in 2008 due to warmer than average weather and lower in the second quarter of 2009 compared to the same period in 2008 due to the congestion-driven pricing environment of the second quarter of 2008. Also contributing to the overall decrease in Commodity Margin was lower steam sales resulting from weaker industrial demand in 2009 compared to 2008. Despite a 1% increase in average availability, generation decreased 8% on softer demand in the first half of 2009 and weaker Market Heat Rates in the second quarter of 2009. We experienced a 1% increase in our Steam Adjusted Heat Rate for the year ended December 31, 2009 compared to 2008, resulting from lower steam sales in 2009 compared to 2008.

 

Southeast:    2009     2008     Change     % Change  

Commodity Margin (in millions)

   $             304      $             264      $             40      15

Commodity Margin per MWh generated

   $ 17.50      $ 20.59      $ (3.09   (15

MWh generated (in thousands)

     17,370        12,820        4,550      35   

Average availability

     93.2     93.6     (0.4     

Average total MW in operation

     6,083        6,183        (100   (2

Average capacity factor, excluding peakers

     37.9     26.6     11.3      42   

Steam Adjusted Heat Rate

     7,299        7,388        89      1   

Southeast — Commodity Margin in our Southeast segment increased by $40 million, or 15%, for the year ended December 31, 2009 compared to 2008. The increase was driven by a 35% increase in generation which resulted from higher natural gas generation displacement of coal generation in certain sub-markets in our Southeast segment primarily caused by lower natural gas prices resulting in higher Market Heat Rates in 2009 compared to 2008. Commodity Margin in the Southeast was also positively affected in 2009 compared to 2008, by the favorable impact of an off-take agreement at one of our power plants and incremental natural gas hedges. The benefit from these positive performance factors was partially offset by the negative impact from the settlement of a disputed steam contract, which adversely impacted operating revenues in 2009. In addition, a gain of $21 million related to the temporary assignment of a transmission capacity contract in the second quarter of 2008 led to a reduction in relative year over year performance. We experienced a 1% decrease in our Steam Adjusted Heat Rate in 2009 compared to 2008, resulting from increased generation. The 100 MW, or 2%, decrease in our average total MW in operation for the year ended December 31, 2009 compared to 2008, was due to the deconsolidation of Auburndale in the third quarter of 2008.

 

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North:    2009     2008     Change     % Change  

Commodity Margin (in millions)

   $             268      $             279      $             (11   (4 )% 

Commodity Margin per MWh generated

   $ 51.06      $ 51.70      $ (0.64   (1

MWh generated (in thousands)

     5,249        5,397        (148   (3

Average availability

     94.7     92.6     2.1      2   

Average total MW in operation

     2,873        2,412        461      19   

Average capacity factor, excluding peakers

     31.1     32.8     (1.7   (5

Steam Adjusted Heat Rate

     7,614        7,584        (30     

North — Commodity Margin in our North segment decreased by $11 million, or 4%, for the year ended December 31, 2009 compared to 2008. Although market spark spreads were lower in 2009 compared to 2008, the impact was largely mitigated by our hedge position as well as the favorable impact of the reconsolidation of RockGen in December 2008. In addition, despite a 2% increase in our average availability, generation decreased 3% due primarily to lower Market Heat Rates in certain sub-markets in our North segment for the year ended December 31, 2009 compared to 2008. The 461 MW, or 19%, increase in our average total MW in operation for the year ended December 31, 2009 compared to 2008, was due to the reconsolidation of RockGen in December 2008.

Commodity Margin by Segment for the Years Ended December 31, 2008 and 2007

The following tables show our Commodity Margin and related operating performance metrics by segment for the years ended December 31, 2008 and 2007. Our 2008 and 2007 Commodity Margin by segment information has been recast to conform to the current year presentation. In the “Change” and “% Change” columns below, favorable variances are shown without brackets while unfavorable variances are shown with brackets. The MWh generated by segment below represents generation from power plants that we both consolidated and operate.

 

West:    2008     2007     Change     % Change  

Commodity Margin (in millions)

   $ 1,255      $ 1,172      $ 83      7

Commodity Margin per MWh generated

   $ 33.79      $ 31.82      $ 1.97      6   

MWh generated (in thousands)

     37,137        36,837        300      1   

Average availability

     89.1     90.8     (1.7   (2

Average total MW in operation

     7,295        7,320        (25     

Average capacity factor, excluding peakers

     65.9     65.2     0.7      1   

Steam Adjusted Heat Rate

     7,267        7,336        69      1   

West — Commodity Margin in our West segment increased by $83 million, or 7%, for the year ended December 31, 2008, compared to the year ended December 31, 2007. The increase resulted primarily from higher on-peak market spark spreads driven by higher natural gas prices and the favorable impact of new and renegotiated power contracts for 2008. The Commodity Margin increase associated with the much stronger commodity price environment was largely reflected in an $88 million year over year increase in the realized value of non-region specific gas hedges and the settlement of commodity derivative instruments. The increase in Commodity Margin was partially offset by lower realized margins in the fourth quarter of 2008 as compared to the same period in 2007, and a negative year on year variance associated with natural gas storage inventory. In 2008, we recorded a loss on natural gas storage resulting from the decrease in market natural gas prices in late summer through the fourth quarter of 2008, while in the fourth quarter of 2007 we recognized a positive impact from sales of natural gas storage inventory.

 

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Texas:    2008     2007     Change     % Change  

Commodity Margin (in millions)

   $             726      $             505      $             221      44

Commodity Margin per MWh generated

   $ 22.40      $ 15.23      $ 7.17      47   

MWh generated (in thousands)

     32,408        33,154        (746   (2

Average availability

     88.8     90.8     (2.0   (2

Average total MW in operation

     7,147        7,146        1        

Average capacity factor, excluding peakers

     51.6     53.0     (1.4   (3

Steam Adjusted Heat Rate

     7,082        6,830        (252   (4

Texas — Commodity Margin in our Texas segment increased by $221 million, or 44%, for the year ended December 31, 2008, compared to 2007, due primarily to higher market spark spreads driven by higher natural gas prices during the second and third quarters of 2008 and congestion pricing in the South and Houston zones in the second quarter of 2008. Commodity Margin was also improved by higher realized spark spreads on hedged positions in the fourth quarter of 2008 despite lower market spark spreads during the same period. Market spark spreads decreased in September 2008 as compared to the same period in 2007 due to the impact of Hurricane Ike; however, we were able to purchase replacement power at prices below our generation cost and hedged prices during the same period, which had a favorable impact in September 2008. Included in the favorable year on year comparison is a decrease in Commodity Margin as a result of an unfavorable year over year impact of $94 million from the allocation of non-region specific natural gas hedges and the settlement of commodity derivative instruments. Generation in our Texas segment decreased by 2% due to an increase in planned outages for major maintenance for the year ended December 31, 2008 compared to 2007. We experienced a 4% increase in our Steam Adjusted Heat Rate for the year ended December 31, 2008 compared to 2007, resulting from the loss of steam load due to the impact of Hurricane Ike, an extended outage at our Baytown power plant in the first and second quarters of 2008 and lower steam demand from our customers during the second half of 2008.

 

Southeast:    2008     2007     Change     % Change  

Commodity Margin (in millions)

   $             264      $             256      $             8      3

Commodity Margin per MWh generated

   $ 20.59      $ 17.30      $ 3.29      19   

MWh generated (in thousands)

     12,820