10-K 1 cpn_10kx12312012.htm 10-K CPN_10K_12.31.2012


 
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, 2012
 
 
[    ]
 
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) 830-2000
Not Applicable
(Former Address)
Securities registered pursuant to Section 12(b) of the Act:
Calpine Corporation Common Stock, $0.001 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 [X]     No [    ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.     [    ]
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, 2012, the last business day of the registrant’s most recently completed second fiscal quarter: approximately $5,484 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: 456,236,512 shares of common stock, par value $0.001, were outstanding as of February 11, 2013.
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 2013 Annual Meeting of Shareholders are incorporated by reference into Part III (Items 11, 12, 13, 14 and portions of Item 10)
 





CALPINE CORPORATION AND SUBSIDIARIES
FORM 10-K
ANNUAL REPORT
For the Year Ended December 31, 2012
TABLE OF CONTENTS
 
 
 
 
 
 
Page
 
 
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
 
 
 
 
 
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
 
 
 
 
 
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
 
 
 
 
 
Item 15.
 

i



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. 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
2017 First Lien Notes
 
The $1.2 billion aggregate principal amount of 7.25% senior secured notes due 2017, issued October 21, 2009, of which 10% of the aggregate principal amount was redeemed on November 7, 2012 in connection with the issuance of the 2019 First Lien Term Loan
 
 
 
2018 First Lien Term Loans
 
Collectively, the $1.3 billion first lien senior secured term loan dated March 9, 2011 and the $360 million first lien senior secured term loan dated June 17, 2011
 
 
 
2019 First Lien Notes
 
The $400 million aggregate principal amount of 8.0% senior secured notes due 2019, issued May 25, 2010, of which 10% of the aggregate principal amount was redeemed on November 7, 2012 in connection with the issuance of the 2019 First Lien Term Loan

 
 
 
2019 First Lien Term Loan
 
The $835 million first lien senior secured term loan, dated October 9, 2012, among Calpine Corporation, as borrower, and the lenders party hereto, and Morgan Stanley Senior Funding, Inc., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent
 
 
 
2020 First Lien Notes
 
The $1.1 billion aggregate principal amount of 7.875% senior secured notes due 2020, issued July 23, 2010, of which 10% of the aggregate principal amount was redeemed on November 7, 2012 in connection with the issuance of the 2019 First Lien Term Loan
 
 
 
2021 First Lien Notes
 
The $2.0 billion aggregate principal amount of 7.50% senior secured notes due 2021, issued October 22, 2010, of which 10% of the aggregate principal amount was redeemed on November 7, 2012 in connection with the issuance of the 2019 First Lien Term Loan
 
 
 
2023 First Lien Notes
 
The $1.2 billion aggregate principal amount of 7.875% senior secured notes due 2023, issued January 14, 2011, of which 10% of the aggregate principal amount was redeemed on November 7, 2012 in connection with the issuance of the 2019 First Lien Term Loan
 
 
 
AB 32
 
California Assembly Bill 32
 
 
 
Adjusted EBITDA
 
EBITDA as adjusted for the effects of (a) impairment charges, (b) major maintenance expense, (c) operating lease expense, (d) unrealized gains or losses on commodity derivative mark-to-market activity, (e) adjustments to reflect only the Adjusted EBITDA from our unconsolidated investments, (f) stock-based compensation expense, (g) gains or losses on sales, dispositions or retirements of assets, (h) non-cash gains and losses from foreign currency translations, (i) gains or losses on the repurchase or extinguishment of debt, (j) Conectiv Acquisition-related costs, (k) Adjusted EBITDA from our discontinued operations and (l) extraordinary, unusual or non-recurring items
 
 
 
AOCI
 
Accumulated Other Comprehensive Income
 
 
 
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
 
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, excluding peakers, during the period by (ii) the total hours in the period
 
 
 
Bankruptcy Code
 
U.S. Bankruptcy Code
 
 
 
Bcf
 
Billion cubic feet
 
 
 

ii




ABBREVIATION
 
DEFINITION
Blue Spruce
 
Blue Spruce Energy Center, LLC, formerly an indirect, wholly-owned subsidiary of Calpine that owned Blue Spruce Energy Center, a 310 MW natural gas-fired, peaking power plant located in Aurora, Colorado, which was sold on December 6, 2010

 
 
 
Broad River
 
Broad River Energy LLC, formerly an indirect, wholly-owned subsidiary of Calpine that leases the Broad River Energy Center, an 847 MW natural gas-fired, peaking power plant located in Gaffney, South Carolina, from the BR Owner Lessors
 
 
 
Broad River Entities
 
Collectively, Broad River and the BR Owner Lessors
 
 
 
BR Owner Lessors
 
Broad River OL-1, LLC, a Delaware limited liability company, Broad River OL-2, LLC, a Delaware limited liability company, Broad River OL-3, LLC, a Delaware limited liability company, and Broad River OL-4, LLC, a Delaware limited liability company, each of which is an indirect, wholly-owned subsidiary of Calpine, which lease the Broad River Energy Center (i) from Cherokee County, South Carolina and (ii) to Broad River
 
 
 
Btu
 
British thermal unit(s), a measure of heat content
 
 
 
CAA
 
Federal Clean Air Act, U.S. Code Title 42, Chapter 85
 
 
 
CAIR
 
Clean Air Interstate Rule
 
 
 
CAISO
 
California Independent System Operator

 
 
 
Calpine BRSP
 
Calpine BRSP, LLC
 
 
 
Calpine Equity Incentive Plans
 
Collectively, the Director Plan and the Equity Plan, which provide for grants of equity awards to Calpine non-union employees and non-employee members of Calpine’s Board of Directors
 
 
 
Cap-and-trade
 
A government imposed emissions reduction program that would place a cap on the amount of 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 emissions during each applicable period. After allowances have been distributed or auctioned, they can be transferred or traded
 
 
 
CARB
 
California Air Resources Board
 
 
 
CCFC
 
Calpine Construction Finance Company, L.P., an indirect, wholly-owned subsidiary of Calpine
 
 
 
CCFC Finance
 
CCFC Finance Corp.
 
 
 
CCFC Guarantors
 
Hermiston Power LLC and Brazos Valley Energy LLC, wholly-owned subsidiaries of CCFC
 
 
 
CCFC 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

 
 
 
CDHI
 
Calpine Development Holdings, Inc., an indirect, wholly-owned subsidiary of Calpine
 
 
 
CEHC
 
Conectiv Energy Holding Company, LLC, a wholly-owned subsidiary of Conectiv
 
 
 
CES
 
Calpine Energy Services, L.P.
 
 
 

iii



ABBREVIATION
 
DEFINITION
CFTC
 
U.S. Commodities Futures Trading Commission
 
 
 
Chapter 11
 
Chapter 11 of the U.S. Bankruptcy Code
 
 
 
CO2
 
Carbon dioxide
 
 
 
COD
 
Commercial operations date
 
 
 
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 expense
 
The sum of our expenses from fuel and purchased energy expense, fuel transportation expense, transmission expense, RGGI compliance and other environmental costs and realized settlements from our marketing, hedging and optimization activities including natural gas transactions hedging future power sales, but excludes the unrealized portion of our mark-to-market activity
 
 
 
Commodity Margin
 
Non-GAAP financial measure that includes power and steam revenues, sales of purchased power and physical natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, RGGI compliance and other environmental costs, and realized settlements from our marketing, hedging and optimization activities including natural gas transactions hedging future power sales, 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 physical natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue and realized settlements from our marketing, hedging and optimization activities, but excludes the unrealized portion of our mark-to-market activity
 
 
 
Company
 
Calpine Corporation, a Delaware corporation, and its subsidiaries

 
 
 
Conectiv
 
Conectiv, LLC, a wholly-owned subsidiary of PHI
 
 
 
Conectiv Acquisition
 
The acquisition of all of the membership interests in CEHC pursuant to the Conectiv Purchase Agreement on July 1, 2010, whereby we acquired all of the power generation assets of Conectiv from PHI, which included 18 operating power plants and York Energy Center that was under construction and achieved COD on March 2, 2011, with 4,491 MW of capacity

 
 
 
Conectiv Purchase Agreement
 
Purchase Agreement by and among PHI, Conectiv, CEHC and NDH dated as of April 20, 2010
 
 
 
Corporate Revolving Facility
 
The $1.0 billion aggregate amount revolving credit facility credit agreement, dated as of December 10, 2010, among Calpine Corporation, Goldman Sachs Bank USA, as administrative agent, Goldman Sachs Credit Partners L.P., as collateral agent, the lenders party thereto and the other parties thereto
 
 
 
CPUC
 
California Public Utilities Commission
 
 
 
Creed
 
Creed Energy Center, LLC
 
 
 
Director Plan
 
The Amended and Restated Calpine Corporation 2008 Director Incentive Plan
 
 
 
Dodd-Frank Act
 
The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
 
 
 
EBITDA
 
Net income (loss) attributable to Calpine before net (income) loss attributable to the noncontrolling interest, 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


iv



ABBREVIATION
 
DEFINITION
EIA
 
Energy Information Administration of the U.S. Department of Energy
 
 
 
EPA
 
U.S. Environmental Protection Agency
 
 
 
Equity Plan
 
The Amended and Restated Calpine Corporation 2008 Equity Incentive Plan
 
 
 
ERCOT
 
Electric Reliability Council of Texas
 
 
 
EWG(s)
 
Exempt wholesale generator(s)
 
 
 
Exchange Act
 
U.S. Securities Exchange Act of 1934, as amended
 
 
 
FASB
 
Financial Accounting Standards Board
 
 
 
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 Notes
 
Collectively, the 2017 First Lien Notes, the 2019 First Lien Notes, the 2020 First Lien Notes, the 2021 First Lien Notes and the 2023 First Lien Notes

 
 
 
First Lien Term Loans
 
Collectively, the 2018 First Lien Term Loans and the 2019 First Lien Term Loan
 
 
 
FRCC
 
Florida Reliability Coordinating Council
 
 
 
Freestone
 
Freestone Energy Center, a 994 MW natural gas-fired, combined-cycle power plant located near Fairfield, Texas
 
 
 
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 carbon dioxide (CO2), and including methane (CH4), nitrous oxide (N2O), sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs) and perfluorocarbons (PFCs)
 
 
 
Goose Haven
 
Goose Haven Energy Center, LLC
 
 
 
Greenfield LP
 
Greenfield Energy Centre LP, a 50% partnership interest between certain of our subsidiaries and a third party which operates the Greenfield Energy Centre, a 1,038 MW natural gas-fired, combined-cycle power plant in Ontario, Canada
 
 
 
Heat Rate(s)
 
A measure of the amount of fuel required to produce a unit of power
 
 
 


v



ABBREVIATION
 
DEFINITION
Hg
 
Mercury
 
 
 
IOUs
 
Investor Owned Utilities
 
 
 
IRC
 
Internal Revenue Code
 
 
 
IRS
 
U.S. Internal Revenue Service
 
 
 
ISO(s)
 
Independent System Operator(s)
 
 
 
ISO-NE
 
ISO New England
 
 
 
ISRA
 
Industrial Site Recovery Act
 
 
 
KIAC
 
KIAC Partners, an indirect, wholly-owned subsidiary of Calpine that leases our Kennedy International Airport Power Plant, a 121 MW natural gas-fired, combined-cycle power plant located at John F. Kennedy International Airport in New York
 
 
 
KWh
 
Kilowatt hour(s), a measure of power produced, purchased or sold
 
 
 
LIBOR
 
London Inter-Bank Offered Rate
 
 
 
Los Esteros Project Debt
 
Credit Agreement dated August 23, 2011, between Los Esteros Critical Energy Facility, LLC, as borrower, and the lenders named therein

 
 
 
LTSA(s)
 
Long-Term Service Agreement(s)
 
 
 
Market Heat Rate(s)
 
The regional power price divided by the corresponding regional natural gas price
 
 
 
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, purchased or sold
 
 
 
NAAQS
 
National Ambient Air Quality Standards
 
 
 
NDH
 
New Development Holdings, LLC, an indirect, wholly-owned subsidiary
 
 
 
NDH Project Debt
 
The $1.3 billion senior secured term loan facility and the $100 million revolving credit facility issued on July 1, 2010, under the credit agreement, dated as of June 8, 2010, among NDH, as borrower, Credit Suisse AG, as administrative agent, collateral agent, issuing bank and syndication agent, Credit Suisse Securities (USA) LLC, Citigroup Global Markets Inc. and Deutsche Bank Securities Inc., as joint book-runners and joint lead arrangers, Credit Suisse AG, Citibank, N.A., and Deutsche Bank Trust Company Americas, as co-documentation agents and the lenders party thereto repaid on March 9, 2011

 
 
 
NERC
 
North American Electric Reliability Council
 
 
 
NOL(s)
 
Net operating loss(es)
 
 
 
NOX
 
Nitrogen oxides
 
 
 
NPCC
 
Northeast Power Coordinating Council
 
 
 
NYISO
 
New York ISO


vi



ABBREVIATION
 
DEFINITION
NYMEX
 
New York Mercantile Exchange
 
 
 
NYSE
 
New York Stock Exchange
 
 
 
OCI
 
Other Comprehensive Income
 
 
 
OMEC
 
Otay Mesa Energy Center, LLC, an indirect, wholly-owned subsidiary that owns the Otay Mesa Energy Center, a 608 MW natural gas-fired, combined-cycle power plant located in San Diego county, California

 
 
 
OTC
 
Over-the-Counter
 
 
 
PG&E
 
Pacific Gas & Electric Company
 
 
 
PHI
 
Pepco Holdings, Inc.
 
 
 
PJM
 
PJM Interconnection is a RTO that coordinates the movement of wholesale electricity in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia
 
 
 
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
 
 
 
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
 
 
 
PUCT
 
Public Utility Commission of Texas
 
 
 
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 the books and records requirement of PUHCA 2005 and grants certain other benefits to the QF
 
 
 
REC(s)
 
Renewable energy credit(s)
 
 
 
Report
 
This Annual Report on Form 10-K for the year ended December 31, 2012, filed with the SEC on February 12, 2013
 
 
 
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
 
Reliability First Corporation
 
 
 
RGGI
 
Regional Greenhouse Gas Initiative
 
 
 
Risk Management Policy
 
Calpine's policy applicable to all employees, contractors, representatives and agents which defines the risk management framework and corporate governance structure for commodity risk, interest rate risk, currency risk and other risks


vii



ABBREVIATION
 
DEFINITION
RMR Contract(s)
 
Reliability Must Run contract(s)
 
 
 
Rocky Mountain
 
Rocky Mountain Energy Center, LLC, formerly an indirect, wholly-owned subsidiary of Calpine that owned Rocky Mountain Energy Center, a 621 MW natural gas-fired, combined-cycle power plant located in Keenesburg, Colorado, which was sold on December 6, 2010
 
 
 
RPS
 
Renewable Portfolio Standards
 
 
 
RTO(s)
 
Regional Transmission Organization(s)
 
 
 
Russell City Project Debt
 
Credit Agreement dated June 24, 2011, between Russell City Energy Company, LLC, as borrower, and the lenders named therein

 
 
 
SEC
 
U.S. Securities and Exchange Commission
 
 
 
Securities Act
 
U.S. Securities Act of 1933, as amended
 
 
 
SERC
 
Southeastern Electric Reliability Council
 
 
 
SO2
 
Sulfur dioxide
 
 
 
South Point
 
South Point Energy Center, a 530 MW natural gas-fired, combined-cycle power plant located in Mohave Valley, Arizona
 
 
 
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
 
 
 
TCEQ
 
Texas Commission on Environmental Quality
 
 
 
TRE
 
Texas Reliability Entity, Inc.
 
 
 
U.S. Bankruptcy Court
 
U.S. Bankruptcy Court for the Southern District of New York
 
 
 
U.S. Debtor(s)
 
Calpine Corporation and each of its subsidiaries and affiliates that filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court, which matter was jointly administered in the U.S. Bankruptcy Court under the caption In re Calpine Corporation, et al., Case No. 05-60200 (BRL) and was dismissed on December 19, 2011
 
 
 
U.S. GAAP
 
Generally accepted accounting principles in the U.S.
 
 
 
VAR
 
Value-at-risk
 
 
 
VIE(s)
 
Variable interest entity(ies)
 
 
 
WECC
 
Western Electricity Coordinating Council
 
 
 
Whitby
 
Whitby Cogeneration Limited Partnership, a 50% partnership interest between certain of our subsidiaries and a third party which operates the Whitby 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada

 
 
 


viii



ABBREVIATION
 
DEFINITION
WP&L
 
Wisconsin Power & Light Company
 
 
 
York Energy Center
 
565 MW dual fuel, combined-cycle generation power plant (formerly known as the Delta Project) located in Peach Bottom Township, Pennsylvania which achieved COD on March 2, 2011

 

ix



Forward-Looking Statements

In addition to historical information, this Report contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act, and Section 21E of the Exchange Act. Forward-looking statements may appear throughout this Report, including without limitation, the “Management's Discussion and Analysis” section. 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:
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, changes in U.S. macroeconomic conditions, fluctuations in liquidity and volatility in the energy commodities markets and our ability to hedge risks;
Laws, regulation and market rules in the markets in which we participate and our ability to effectively respond to changes in laws, regulations or market rules or the interpretation thereof including those related to the environment, derivative transactions and market design in the regions in which we operate;
Our ability to manage our liquidity needs and to comply with covenants under our First Lien Notes, Corporate Revolving Facility, First Lien Term Loans, CCFC Notes and other existing financing obligations;
Risks associated with the operation, construction and development of power plants including unscheduled outages or delays and plant efficiencies;
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;
The unknown future impact on our business from the Dodd-Frank Act and the rules to be promulgated thereunder;
Competition, including risks associated with marketing and selling power in the evolving energy markets;
The expiration or early termination of our PPAs and the related results on revenues;
Future capacity revenues may not occur at expected levels;
Natural disasters, such as hurricanes, earthquakes and floods, acts of terrorism or cyber attacks that may impact our power plants or the markets our power plants serve and our corporate headquarters;
Disruptions in or limitations on the transportation of natural gas, fuel oil and transmission of power;
Our ability to manage our customer and counterparty exposure and credit risk, including our commodity positions;
Our ability to attract, motivate and retain key employees;
Present and possible future claims, litigation and enforcement actions; 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 with 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. You may obtain information on the

1



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.

2



PART I

Item 1.
Business
BUSINESS AND STRATEGY
Business
We are a premier wholesale power producer with operations throughout the U.S. We measure our success by delivering long-term shareholder value. We accomplish this through our focus on operational excellence, effectively executing our hedging strategy, our customer origination program and completing our growth capital projects on schedule and on budget. We are one of the largest power generators in the U.S. measured by power produced. We own and operate primarily natural gas-fired and geothermal power plants in North America and have a significant presence in major competitive wholesale power markets in California, Texas and the Mid-Atlantic region of the U.S. Since our inception in 1984, we have been a leader in environmental stewardship. We have invested 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 primarily comprised of two types of power generation technologies: natural gas-fired combustion turbines, which are primarily efficient 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 18% of all renewable energy in the state of California during 2011. We sell wholesale power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities, power marketers and others. We purchase natural gas and fuel oil as fuel for our power plants and engage in related natural gas transportation and storage transactions. We also purchase electric transmission rights to deliver power to our customers. Additionally, consistent with our Risk Management Policy, we enter into natural gas and power physical and financial contracts to hedge certain business risks and optimize our portfolio of power plants.
Our portfolio, including partnership interests, consists of 92 power plants, including 4 under construction (1 new power plant and 3 expansions of existing power plants), located throughout 20 states in the U.S. and Canada, with an aggregate generation capacity of 27,321 MW and 1,163 MW under construction. Our fleet, including projects under construction, consists of 74 combustion turbine-based plants, 2 fossil steam-based plants, 15 geothermal turbine-based plants and 1 photovoltaic solar plant. In 2012, our fleet of power plants produced approximately 116 billion KWh of electric power for our customers. In addition, we are one of the largest consumers of natural gas in North America. In 2012, we consumed 867 Bcf or approximately 9% of the total estimated natural gas consumed for power generation in the U.S. We believe that having scale and geographic diversity is important in our business. Scale provides us the opportunity to have meaningful regulatory input, an ability to leverage our procurement efforts for better pricing, terms and conditions on our goods and services, and allows us to develop and offer a wide array of products and services to our customers. Geographic diversity helps us manage weather, regulatory and regional economic differences across our markets.
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 substantially lower air pollutant emissions 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, our combined-cycle power plants 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 pollutant emissions such as mercury, as well as water use or emissions, compared to our competitors who use other fossil fuels or older, less efficient technologies.
Our principal offices are located in Houston, Texas with regional offices in Dublin, California and Wilmington, Delaware, an engineering, construction and maintenance services office in Pasadena, Texas and government affairs 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 wholesale power company in the U.S. as measured by our employees, shareholders, customers and regulators as well as the communities in which our facilities are located. We seek to achieve sustainable

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growth through financially disciplined power plant development, construction, acquisition, operation and ownership. Our strategy to achieve this is reflected in the four major initiatives described below:
1.
Focus on Becoming the 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 cost management.
We produced approximately 116 billion KWh of electricity in 2012, 23% more than the same period in 2011 (includes generation from power plants owned but not operated by us and our share of generation from our unconsolidated power plants).
Our entire fleet achieved a forced outage factor of 1.6% in 2012, our lowest on record and an improvement of 36% from 2011.
Our entire fleet achieved an impressive starting reliability of 98.3% in 2012.
During 2012, our outage services subsidiary completed 11 major inspections and 19 hot gas path inspections.
For the past twelve consecutive years, our Geysers Assets have reliably generated approximately 6 million MWh per year and, in 2012, achieved an exceptional availability factor of approximately 97%.
2.
Focus on Enhancing Shareholder Value — We continue to make significant progress to deliver financially disciplined growth, to enhance shareholder value through our capital allocation and share repurchases and to set the foundation for continued growth and success. Given our strong cash flow from operations, we are committed to remaining financially disciplined in our capital allocation decisions. The year ended December 31, 2012 was marked by the following accomplishments:
As of the filing of this Report, we have completed our previously announced $600 million share repurchase program, having repurchased a total of 35,568,833 shares of our outstanding common stock at an average price paid of $16.87 per share. In February 2013, our Board of Directors authorized the repurchase of an additional $400 million in shares of our common stock, bringing the cumulative authorization total to $1.0 billion.
During the first quarter of 2012, we terminated our legacy interest rate swaps formerly hedging our First Lien Credit Facility for a payment of approximately $156 million which eliminated our exposure from these instruments to further declines in interest rates.
On October 9, 2012, we issued our 2019 First Lien Term Loan and used the proceeds to reduce our overall cost of debt and simplify our capital structure by redeeming a portion of our First Lien Notes and repaying project debt.
On November 7, 2012, we completed the purchase of a modern, natural gas-fired, combined-cycle power plant with a nameplate capacity of 800 MW located in Bosque County, Texas for approximately $432 million which increased capacity in our Texas segment.
On December 27, 2012, we, through our indirect, wholly-owned subsidiary Calpine Power Company, completed the sale of 100% of our ownership interest in each of the Broad River Entities for approximately $423 million. This transaction resulted in the disposition of our Broad River power plant, an 847 MW natural gas-fired, peaking power plant located in Gaffney, South Carolina, and includes a five year consulting agreement with the buyer. We expect to use the sale proceeds for our capital allocation activities and for general corporate purposes.
On December 31, 2012, we completed the sale of Riverside Energy Center, LLC to WP&L for approximately $402 million. We expect to use the sale proceeds for our capital allocation activities and for general corporate purposes.
3.
Focus on Leveraging our Three Scale Regions — Our goal is to continue to grow our generation presence in core markets with an emphasis on expansions or modernizations of existing power plants. We intend to take advantage of favorable opportunities to continue to design, develop, acquire, construct and operate the next generation of highly efficient, operationally flexible and environmentally responsible power plants where such investment meets our rigorous financial hurdles, particularly if power contracts and financing are available and attractive returns are expected. Likewise, we will actively seek divestiture opportunities on our non-core assets if those opportunities meet our financial expectations. In addition, we believe that modernizations and expansions to our current assets offer proven and financially disciplined opportunities to improve our operations, capacity and efficiencies. Our significant projects under construction, organic growth initiatives and modernization activities are discussed below.
West:
Russell City Energy Center — Construction at our Russell City Energy Center continues to move forward. Upon completion, this project will bring on line approximately 429 MW of net interest baseload capacity (464 MW with peaking capacity) representing our 75% share. Construction is ongoing and COD is expected in the summer of 2013. Upon completion, the Russell City Energy Center is contracted to deliver its full output to PG&E under a ten-year PPA.

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Los Esteros Critical Energy Facility — During 2009, we and PG&E negotiated a new PPA to replace the existing California Department of Water Resources contract and facilitate the modernization of our Los Esteros Critical Energy Facility from a 188 MW simple-cycle generation power plant to a 309 MW combined-cycle generation power plant, which will also increase the efficiency and environmental performance of the power plant by lowering the Heat Rate. Construction is ongoing and COD is expected in the summer of 2013.
Texas:
Channel and Deer Park Expansions — In September and November 2011, we filed air permit applications with the TCEQ and the EPA to expand the baseload capacity of the Deer Park and Channel Energy Centers by approximately 260 MW each. We received air permit approvals from the TCEQ for our Deer Park and Channel expansion projects in September and October 2012, respectively, and from the EPA in November 2012. Construction on these expansion projects commenced in the fourth quarter of 2012. We expect COD during the summer of 2014 for these expansions and are currently evaluating funding sources including, but not limited to, nonrecourse financing, corporate financing or internally generated funds.
North:
Garrison Energy Center — We are actively permitting 618 MW of new combined-cycle capacity at a development site secured by a long-term lease with the City of Dover. For the first phase (309 MW), we have executed the Interconnection Services Agreement and the Interconnection Construction Services Agreement with PJM. For the second phase (309 MW), we have completed a feasibility study and are currently conducting a system impact study. Environmental permitting, site development planning and development engineering are underway and the first phase’s capacity cleared PJM’s 2015/2016 base residual auction. We received the air permit and executed a preliminary notice to proceed for the engineering, procurement and construction agreement during the first quarter of 2013. We expect COD for the first phase by the summer of 2015 and are currently evaluating funding sources including, but not limited to, nonrecourse financing, corporate financing or internally generated funds.
All Segments:
Turbine Modernization — We continue to move forward with our turbine modernization program. Through December 31, 2012, we have completed the upgrade of eleven Siemens and eight GE turbines totaling over 200 MW and have committed to upgrade approximately three additional turbines.
4.
Focus on Customer-Oriented Origination Business — We continue to focus on providing products and services that are beneficial to our customers. A summary of certain significant contracts entered into or approved in 2012 is as follows:
We entered into a new twenty-year PPA with Western Farmers Electric Cooperative to provide 160 MW of power generated by our Oneta Energy Center, commencing in June 2014. The capacity under contract will increase in increments, up to a maximum of 280 MW in years 2019 through 2035.
We entered into a new five-year PPA with Southwestern Public Service Company, a subsidiary of Xcel Energy, to provide an additional 200 MW of power generated by our Oneta Energy Center commencing on June 1, 2014.
We entered into a new five-year resource adequacy contract with PG&E for approximately 280 MW of combined heat and power capacity from our Los Medanos Energy Center commencing in the summer 2013.
We entered into a new seven-year resource adequacy contract with Southern California Edison Company (“SCE”) for approximately 280 MW of combined heat and power capacity from our Los Medanos Energy Center and a new five-year resource adequacy contract with SCE for approximately 120 MW of combined heat and power capacity from our Gilroy Cogeneration Plant, both commencing in January 2014.
We amended an existing PPA with Dow Chemical Company for an incremental energy sale of up to approximately 158,000 MWh per year of energy from our Los Medanos Energy Center which runs through February 2025.
We entered into a new fifteen-year PPA with American Electric Power Service Corporation, as agent for Public Service Company of Oklahoma, to provide 260 MW of energy, capacity and ancillary services from our Oneta Energy Center commencing in June 2016.
We entered into a new ten-year PPA with the Tennessee Valley Authority to provide the full output of power generated by our Decatur Energy Center, a natural gas-fired, combined-cycle power plant that can generate up to 795 MW, commencing in January 2013.

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THE MARKET FOR POWER
Our Power Markets and Market Fundamentals
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 approximately $364 billion in power sales in 2012 according to the EIA. Historically, vertically integrated power utilities with monopolies 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 wholesale power producers to compete to provide power. Although different regions of the country have very different models and rules for competition, the markets in which we operate have some form of wholesale market competition. California (included in our West segment), Texas and the Mid-Atlantic (included in our North segment), which are the markets in which we have our largest presence, have emerged as among the most competitive wholesale power markets in the U.S. We also operate, to a lesser extent, in the competitive ISO-NE, NYISO and MISO markets. We produce several products for sale to our customers.
First, we are a wholesale provider of power to utilities, independent electric system operators, industrial or agricultural companies, retail power providers, municipalities, and power marketers. Our power sales occur in several different product categories including baseload (around the clock generation), intermediate (generation typically more expensive than baseload and utilized during higher demand periods to meet shifting demand needs), and peaking capacity (most expensive variable cost and utilized during the highest demand periods), for which the latter is provided by some of our stand-alone peaking power plants/units and from our combined-cycle power plants by using technologies such as steam injection or duct firing additional burners in the heat recovery steam generators. Many of our units have operated more frequently as baseload units at times when low natural gas prices have driven their production costs below those of some competing coal-fired units.
Second, we provide capacity for sale to retail power providers. In various 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 from power plant owners or resellers. Most electricity market administrators have acknowledged that an energy only market does not provide sufficient revenues to enable existing merchant generators to recover all of their costs or to encourage the construction of new power plants. Capacity auctions have been implemented in the northeast, the Mid-Atlantic and some midwest regional markets to address this issue. California has a bilateral capacity program. Texas does not presently have a capacity market, nor a requirement for retailers to ensure adequate resources.
Third, we sell RECs from our Geysers Assets in northern California, as well as from our small solar power plant in New Jersey. 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. New Jersey has a solar specific RPS which enables us to sell RECs from our Vineland Solar Energy Center.
Fourth, our cogeneration power plants produce steam for sale to customers for use in industrial or heating, ventilation and air conditioning operations.
Fifth, we provide ancillary service products to wholesale power markets. These products include the right for the purchaser to call on our generation to provide flexibility to the market and support operation of the electric grid. As an example, we are sometimes paid to reserve a portion of capacity at some of our power plants that could be deployed quickly should there be an unexpected increase in load or to assure reliability due to fluctuations in the supply of power from variable renewable resources such as wind and solar generation. These ramping characteristics are becoming increasingly necessary in markets where intermittent renewables have large penetrations.
In addition to the five products above, we are buyers and sellers of environmental allowances and credits, including those under RGGI, the federal Acid Rain and CAIR programs and emission reduction credits under the federal Nonattainment New Source Review program. We also participate in CO2 emissions credit markets related to California’s AB 32 GHG reduction program.
Although all of the products mentioned above contribute to our financial performance and are the primary components of our Commodity Margin, the most important is our sale of wholesale power. We utilize long-term customer contracts for our power and steam sales where possible. For power that is not sold under customer contracts, we use our hedging program throughout the markets in which we participate.

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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 lower cost units 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. The market factors that most significantly impact our operations are reserve margins, the price and supply of natural gas and competing fuels such as coal and oil, weather patterns and natural events, our operating Heat Rate, availability factors, and regulatory and environmental pressures as further discussed below.
Reserve Margins
Reserve margin, a measure of excess generation capacity 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 under normal weather conditions. Holding other factors constant, lower reserve margins typically lead to higher power prices because the less efficient capacity in the region is needed more often to satisfy power demand or voluntary or involuntary load shedding measures are taken. Markets with tight demand and supply conditions often display price spikes and improved bilateral contracting 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.
During the last decade, the supply and demand fundamentals in many regional markets have been negatively impacted by the combination of new generation coming on line and a general decline in weather normalized load growth rates due to the economic recession. Although uncertainty exists and there are key regional differences at a macro level, continued economic recovery and thus, corresponding load recovery, with the lack of broad new power plant investments in our key markets should lead to lower reserve margins and higher Market Heat Rates. Reserve margins by NERC regional assessment area for each of our segments are listed below:
 
 
 
2012(1)
West:
 
 
WECC
 
19.7
%
Texas:
 
 
TRE
 
13.5
%
North:
 
 
NPCC
 
21.5
%
MISO
 
28.7
%
PJM
 
30.6
%
Southeast:
 
 
SERC
 
32.2
%
SPP
 
22.7
%
FRCC
 
27.8
%
___________
(1)
Data source is NERC weather-normalized estimates for 2012
The Price and Supply of Natural Gas
Approximately 95% of our generating capability’s fuel requirements are met with natural gas. We have approximately 725 MW of baseload capacity from our Geysers Assets and our expectation is that the steam reservoir at our Geysers Assets will be able to supply economic quantities of steam for the foreseeable future as our steam flow decline rates have become very small over the past several years. We also have approximately 596 MW of capacity from power plants where we purchase fuel oil to meet these generation requirements, but do not expect fuel oil requirements to be material to our portfolio of power plant assets. Additionally, we have 4 MW of capacity from solar power generation technology with no fuel requirement.
We procure natural gas from multiple suppliers and transportation and storage sources. Although availability is generally not an issue, localized shortages (especially in extreme weather conditions in and around the population centers), transportation availability and supplier financial stability issues can and do occur.
Lower gas prices over the past four years have had a significant impact on power markets. Beginning in 2009, there was a significant decrease in NYMEX Henry Hub natural gas prices from a range of $6/MMBtu — $13/MMBtu during 2008 to an

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average natural gas price of $4.38/MMBtu, $4.03/MMBtu, and $2.83/MMBtu during 2010, 2011 and 2012, respectively. Natural gas prices in some parts of the country for parts of 2010, 2011 and 2012 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, the effects of which can be seen in our increased generation volumes in 2012.
The availability of non-conventional natural gas supplies, in particular shale natural gas, has been the primary driver of reduced natural gas prices in the last few years. Access to significant deposits of shale natural gas has altered the natural gas supply landscape in the U.S. and could have a longer-term and profound impact on both the outright price of natural gas and the historical regional natural gas price relationships (basis differentials). The U.S. Department of Energy estimates that shale natural 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 to supply the U.S. for the next 90 years. Accordingly, there is an emerging view that lower priced natural gas will be available for the medium to long-term future.
The price of natural gas, economic growth and environmental regulations affect our Commodity Margin and liquidity. The impact of changes in natural gas prices differs according to the time horizon and regional market conditions and depends on our hedge levels and other factors discussed below.
Much of our generating capacity is located in California (included in our West segment), Texas and the Mid-Atlantic (included in our North segment) where natural gas-fired units set power prices during many hours. When natural gas is the price-setting fuel, increases in natural gas prices may increase our unhedged Commodity Margin because our combined-cycle power plants in those markets are more fuel-efficient than conventional natural gas-fired technologies and peaking power plants. Conversely, decreases in natural gas prices may decrease our unhedged Commodity Margin. In these instances, our cost of production advantage relative to less efficient natural gas-fired generation is diminished on an absolute basis.
In 2012, given very low natural gas prices, natural gas-fired, combined-cycle units in many markets were frequently cheaper to dispatch than coal-fired power plants. When coal-fired electricity production costs exceed natural gas-fired production costs, coal-fired units tend to set power prices. In these hours, lower natural gas prices tend to increase our Commodity Margin, since our production costs fall while power prices remain constant (depending on our hedge levels and holding other factors constant).
Where we operate under long-term contracts, changes in natural gas prices can have a neutral impact on us in the short-term. This tends to be the case where we have entered into tolling agreements under which the customer provides the natural gas and 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 or power prices may also affect our liquidity. During periods of high or volatile natural gas prices, we could be required to post additional cash collateral or letters of credit.
Despite these short-term dynamics, over the long-term, we expect lower natural gas prices to encourage new combined-cycle gas turbine power plant investment, thus enhancing 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 generally has 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 unhedged 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 the summer months of our third fiscal quarter. 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
Our fleet is modern and more efficient than the average generation fleet; accordingly, we run more and earn incremental margin in markets where less efficient natural gas units frequently set the power price. In such cases, our unhedged Commodity Margin is positively correlated with how much more efficient our fleet is than our competitors’ fleets and with higher natural gas prices. Efficient operation of our fleet creates the opportunity to capture Commodity Margin. However, unplanned outages during periods when Commodity Margin is positive can result in a loss of that opportunity. We 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 lower our operating Heat Rate compared to the Market Heat Rate, the more favorable the impact on our Commodity Margin.

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Regulatory and Environmental Pressures
We believe that, on a net basis, we will be favorably impacted by current regulatory and environmental trends, including those described below, given the characteristics of our power plant portfolio:
Environmental pressures continue to increase for coal-fired power generation as state and federal agencies enact rules to reduce air emissions of certain pollutants such as SO2, NOX, GHG, Hg and acid gases, restrict the use of once-through cooling, and provide for stricter standards for managing coal combustion residuals. Some of the regions in which we operate include older, less efficient fossil-fuel power plants that emit much higher amounts of GHG, SO2, NOX, Hg and acid gases, which we anticipate will be negatively impacted by current and future air emissions, water and waste regulations and legislation both at the state and federal levels. The estimated capacity for fossil-fueled plants which are older than 50 years and the total estimated capacity for fossil-fueled plants by NERC region are as follows:
 
 
Generating Capacity Older Than 50 years
 
Total Generating Capacity
West:
 
 
 
 
 
 
WECC
 
8,450

MW
 
132,258

MW
Texas:
 
 
 
 
 
 
TRE
 
2,801

MW
 
82,552

MW
North:
 
 
 
 
 
 
NPCC
 
6,445

MW
 
57,559

MW
MRO
 
4,489

MW
 
45,869

MW
RFC
 
25,034

MW
 
197,354

MW
Southeast:
 
 
 
 
 
 
SERC
 
27,935

MW
 
235,483

MW
SPP
 
4,811

MW
 
59,961

MW
FRCC
 
1,233

MW
 
59,569

MW
Total
 
81,198

MW

870,605

MW
An increase in power generated from renewable sources could lead to an increased need for flexible power that many of our power plants provide to protect the reliability of the grid and premium compensation for that flexibility; however, risks also exist that renewables have the ability to lower overall wholesale prices which could negatively impact us. Significant economic and reliability concerns for renewable generation have been raised, but we expect that renewable market penetration will continue to be assisted by state-level renewable portfolio standards and federal tax incentives.
The regulators in our core markets remain committed to the competitive wholesale power model, particularly in Texas and PJM where they continue to focus on market design and rules to assure the long-term viability of competition and the benefits to customers that justify competition.
Utilities are increasingly focused on demand side management – managing the level and timing of power usage through load curtailment, dispatching generators located at commercial or industrial sites, and “smart grid” technologies that may improve the efficiencies, dispatch usage and reliability of electric grids. Scrutiny of demand side resources has increased in recent months as system operators evaluate their reliability (especially at high levels of penetration) and environmental authorities deal with the implications of relying on smaller, less environmentally efficient generation sources during periods of peak demand when air quality is already challenged.
Environmental permitting requirements for new power plants and transmission lines are becoming increasingly onerous.
We believe these trends are positive for our fleet. For a discussion of federal, state and regional legislative and regulatory initiatives and how they might affect us, see “— Governmental and Regulatory Matters.”
It is very difficult to predict the continued evolution of our markets due to the uncertainty of the following:
number of market participants, both in terms of physical presence as well as contribution toward financial market liquidity;
amount of power available in the market;

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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, 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, permitting and constructing new power plants;
availability and cost of power transmission;
potential growth of demand side management;
creditworthiness and other risks associated with counterparties;
bidding behavior of market participants;
regulatory and ISO guidelines and rules;
structure of commercial products; and
ability to optimize the market’s mix of alternative sources of power such as renewable and hydroelectric power.
Competition
Wholesale power generation is a capital-intensive, commodity-driven business with numerous industry participants. We compete against other independent power producers, power marketers and 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. and Canada. In addition, in some markets, we compete against some of our customers.
In markets with centralized ISOs, such as California, Texas and the Mid-Atlantic, our natural gas-fired power plants compete directly with all other sources of power. The EIA estimates that in 2012, 30% of the power generated in the U.S. was fueled by natural gas and that approximately 56% of power generated in the U.S. was produced by coal and nuclear facilities, which generated approximately 37% and 19%, respectively. The EIA estimates that the remaining 14% 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. The federal government is continuing to take further action on many air pollutant emissions such as NOX, SO2, Hg and acid gases as well as on once-through cooling and coal ash disposal. Although we cannot predict the ultimate effect any future environmental legislation or regulations will have on our business, as a clean energy provider, we believe that we are well positioned for almost any increase in environmental rule stringency. 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.”
With new environmental regulations, the proportion of power generated by natural gas and other low emissions resources is expected to increase because older coal-fired power plants will be required to install costly emissions control devices, limit their operations or be retired. 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.
Competition from other sources of power, such as nuclear energy and renewables, could increase in the future, but likely at a lower rate than had been previously expected. The nuclear incident in March 2011 at the Fukushima Daiichi nuclear power plant introduced substantial uncertainties around new nuclear power plant development in the U.S. In addition, the combination of emerging air emissions regulations, federal and state financial incentives and RPS requirements for renewables and their impact of expected increased investment in cleaner sources of generation will be somewhat counteracted by a lower natural gas price environment, which, should it persist, makes new investment in these types of power generation generally uneconomical. Thus, it is doubtful that generation from new nuclear power plants and renewable sources will be available in the quantities needed to meet future energy demand. Beyond economic issues, 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, long-term, natural gas units are likely still needed as baseload and “back-up” generation.
We believe our ability to compete will be driven by the extent to which we are able to accomplish the following:
provide affordable, reliable services to our customers;
maintain excellence in operations;
achieve and maintain a lower cost of production, primarily by maintaining unit availability and efficiency;

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accurately assess and effectively manage our risks; and
benefit from future environmental regulation and legislation.
MARKETING, HEDGING AND OPTIMIZATION ACTIVITIES
Our commercial hedging and optimization strategies are designed to maximize our risk-adjusted Commodity Margin by leveraging our knowledge, experience and fundamental views on natural gas and power. Additionally, we seek strong bilateral relationships with load serving entities that can benefit us and our customers.
The majority of our risk exposures arise from our ownership and operation of power plants. Our primary risk exposures are Spark Spread, power prices, natural gas prices, capacity prices, locational price differences in both power and natural gas, natural gas transportation, electric transmission, REC prices, carbon prices in California and other emissions credit prices. In addition to the direct risk exposure to commodity prices, we also have general market risks such as risk related to performance of our counterparties and customers and plant operating performance risk. We also have a small exposure to Canadian exchange rates due to our partial ownership of Greenfield LP and Whitby located in Canada, which are under long term contracts, and minimal fuel oil exposure which are not currently material to our operations. As such, we have currently elected not to hedge our Canadian exchange rate or fuel oil exposure.
We produced approximately 116 billion KWh of electricity in 2012 across North America (primarily in the U.S.). We are one of the largest consumers of natural gas in North America having consumed approximately 867 Bcf during 2012. The four primary power markets in which we conduct our operations are Texas, California, PJM and the Southeast. The Texas, California and PJM markets have a centralized market for which power demand and prices are determined on a spot basis (day ahead and real time), and the Southeast market is a bilateral market. Most of the power generated by our power plants is sold to entities such as independent electric system operators, 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 actively manage our risk exposures with a variety of physical and financial instruments with varying time horizons. These instruments include PPAs, tolling arrangements, Heat Rate swaps and options, load sales, steam sales, buying and selling standard physical products, buying and selling exchange traded instruments, gas transportation and storage arrangements, electric transmission service and other contracts for the sale and purchase of power products. We utilize these instruments to maximize the risk-adjusted returns for our Commodity Margin.
At any point in time, the relative quantity of our products hedged or sold under longer-term contracts is determined by the availability of forward product sales opportunities and our view of the attractiveness of the pricing available for forward sales. Historically, we have economically hedged a portion of our expected generation and natural gas portfolio mostly through power and natural gas forward physical and financial transactions; however, we currently remain susceptible to significant price movements for 2013 and beyond. When we elect to enter into these transactions, we are able to economically hedge a portion of our Spark Spread at pre-determined generation and price levels.
We conduct our 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 and 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. 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. Our future hedged status and marketing and optimization activities are subject to change as determined by our commercial operations group, Chief Risk Officer, senior management and Board of Directors. For control purposes, 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 Risk Management Policy which is approved by our Board of Directors and by a committee comprised of members of our senior management and administered by our Chief Risk Officer's organization. The Chief Risk Officer's organization is segregated from the commercial operations unit and reports directly to our Audit Committee and Chief Financial Officer. Our Risk Management Policy is primarily designed to provide us with a degree of protection from significant downside commodity price risk exposure to our cash flows.
In order to simplify our reporting, we elected to discontinue the application of hedge accounting treatment during the first quarter of 2012 for all commodity derivatives, including the remaining commodity derivatives previously accounted for as cash flow hedges. Accordingly, prospective changes in fair value from the date of this election are reflected in unrealized mark-to-market activity on our Consolidated Statements of Operations and could create more volatility in our earnings. The fair value of our commodity derivative instruments residing in AOCI during the previous application of hedge accounting was reclassified

11



to earnings during 2012 as the related economic transactions affected earnings or the forecasted transaction became probable of not occurring.
We have historically used interest rate swaps to adjust the mix between our fixed and variable rate debt. To the extent eligible, our interest rate swaps have been designated as cash flow hedges, and changes in fair value are recorded in OCI to the extent they are effective with gains and losses reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The reclassification of unrealized losses from AOCI into earnings and the changes in fair value and settlements subsequent to the reclassification date of the interest rate swaps formerly hedging our First Lien Credit Facility is presented separately from interest expense as loss on interest rate derivatives on our Consolidated Statements of Operations. See Note 8 of the Notes to Consolidated Financial Statements for further discussion of our derivative instruments.
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 coincides with our third fiscal 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 16 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.
 

12



DESCRIPTION OF OUR POWER PLANTS


Geographic Diversity                     Dispatch Technology
            

13



Power Plants in Operation at December 31, 2012
We own 92 power plants, including 4 under construction (1 new power plant and 3 expansions of existing power plants), with an aggregate generation capacity of approximately 27,321 MW and 1,163 MW under construction.
Natural Gas-Fired Fleet
Our natural gas-fired power plants primarily utilize two types of designs: 2,465 MW of simple-cycle combustion turbines and 23,244 MW of combined-cycle combustion turbines and a small portion from conventional natural gas/oil-fired boilers with steam turbines. Simple-cycle combustion turbines burn natural gas or oil to spin an electric generator to produce power. A combined-cycle unit combusts fuel like a simple-cycle combustion turbine and the exhaust heat is captured by a heat recovery boiler to 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 2012 for the power plants we operate was 7,361 Btu/KWh which results in a power conversion efficiency of approximately 46%. The power conversion efficiency is a measure of how efficiently a fossil fuel power plant converts thermal energy to electrical energy. Our “all in” Steam Adjusted 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 combined heat and 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 28% to 36%.
Each of our power plants currently in operation is capable of producing power for sale to a utility, another third-party end user or an intermediary such as a marketing company. At 19 of our power plants we also produce thermal energy (primarily steam and chilled water), which can be sold to industrial and governmental users. These plants are called combined heat and power facilities.
Our natural gas fleet is relatively young with a weighted average age, based upon MW capacities in operation, of approximately thirteen 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 wholesale power sector.
The majority of the combustion turbines in our fleet are one of four technologies: GE 7FA, GE LM6000, Siemens 501FD or Siemens V84.2 turbines. We maintain our fleet through a regular and rigorous maintenance program. As units reach certain operating targets, which are typically based upon service hours or number of starts, we perform the maintenance that is required for that unit at that stage in its life cycle. Our large fleet of similar technologies has enabled us to build significant technical and engineering experience with these units and minimize the number of replacement parts in inventory. We leverage this experience by performing much of our major maintenance ourselves with our outage services subsidiary.
Geothermal Fleet
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 twelve 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 approximately 97% in 2012.
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 water. We receive and inject an average of approximately 16 million gallons of reclaimed water 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 12 million gallons per day are received from the Santa Rosa Geysers Recharge Project, which we developed jointly with the City of Santa Rosa, and we receive, on average, approximately 4 million gallons a day from The Lake County Recharge Project from Lake County. As a result of these recharge projects, MWh production has been relatively constant. 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.

14



We periodically review our geothermal studies to help us assess the economic life of our geothermal reserves. Our most recent geothermal reserve study was conducted in 2011. Our evaluation of our geothermal reserves, including our review of any applicable independent studies conducted, indicates that our Geysers Assets should continue to supply sufficient steam to generate positive cash flows at least through 2068. In reaching this conclusion, our evaluation, consistent with the due diligence study of 2011, 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 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 2012 is:
29% related to leases with the federal government via the Office of Natural Resources Revenue (formerly, the Minerals Management Service),
28% related to leases with the California State Lands Commission, and
43% 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.
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.
Other Power Generation Technologies
Across the fleet, we also have a variety of older, less efficient technologies including approximately 883 MW of capacity from power plants which have conventional steam turbine technology. We also have approximately 4 MW of capacity from solar power generation technology at our Vineland Solar Energy Center in New Jersey.

15



Table of Operating Power Plants and Projects Under Construction and Advanced Development
Set forth below is certain information regarding our operating power plants and projects under construction and advanced development at December 31, 2012.
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)
 
2012
Total MWh
Generated(4)
WEST
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Geothermal
 
 
 
 
 
 
 
 
 
 
 
 
 
 
McCabe #5 & #6
 
WECC
 
CA
 
Renewable
 
100
%
 
78

 
78

 
690,435

Ridge Line #7 & #8
 
WECC
 
CA
 
Renewable
 
100
%
 
69

 
69

 
627,748

Calistoga
 
WECC
 
CA
 
Renewable
 
100
%
 
66

 
66

 
536,435

Eagle Rock
 
WECC
 
CA
 
Renewable
 
100
%
 
66

 
66

 
601,883

Quicksilver
 
WECC
 
CA
 
Renewable
 
100
%
 
53

 
53

 
393,048

Cobb Creek
 
WECC
 
CA
 
Renewable
 
100
%
 
52

 
52

 
433,795

Lake View
 
WECC
 
CA
 
Renewable
 
100
%
 
52

 
52

 
508,540

Sulphur Springs
 
WECC
 
CA
 
Renewable
 
100
%
 
51

 
51

 
388,902

Socrates
 
WECC
 
CA
 
Renewable
 
100
%
 
50

 
50

 
339,550

Big Geysers
 
WECC
 
CA
 
Renewable
 
100
%
 
48

 
48

 
483,630

Grant
 
WECC
 
CA
 
Renewable
 
100
%
 
43

 
43

 
346,996

Sonoma
 
WECC
 
CA
 
Renewable
 
100
%
 
42

 
42

 
324,759

West Ford Flat
 
WECC
 
CA
 
Renewable
 
100
%
 
24

 
24

 
221,400

Aidlin
 
WECC
 
CA
 
Renewable
 
100
%
 
17

 
17

 
119,471

Bear Canyon
 
WECC
 
CA
 
Renewable
 
100
%
 
14

 
14

 
98,335

Natural Gas-Fired
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Delta Energy Center
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
835

 
857

 
5,704,956

Pastoria Energy Center
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
770

 
749

 
4,371,891

Hermiston Power Project
 
WECC
 
OR
 
Combined Cycle
 
100
%
 
566

 
635

 
2,888,861

Otay Mesa Energy Center
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
513

 
608

 
3,852,390

Metcalf Energy Center
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
564

 
605

 
2,778,933

Sutter Energy Center
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
542

 
578

 
1,273,920

Los Medanos Energy Center
 
WECC
 
CA
 
Cogen
 
100
%
 
518

 
572

 
3,588,525

South Point Energy Center
 
WECC
 
AZ
 
Combined Cycle
 
100
%
 
520

 
530

 
1,364,070

Gilroy Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
141

 
67,181

Gilroy Cogeneration Plant
 
WECC
 
CA
 
Cogen
 
100
%
 
109

 
130

 
241,850

King City Cogeneration Plant
 
WECC
 
CA
 
Cogen
 
100
%
 
120

 
120

 
499,483

Greenleaf 1 Power Plant
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
50

 
50

 
60,273

Greenleaf 2 Power Plant
 
WECC
 
CA
 
Cogen
 
100
%
 
49

 
49

 
279,760

Wolfskill Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
48

 
16,549

Yuba City Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
45,663

Feather River Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
36,633

Creed Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
10,130

Lambie Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
9,371

Goose Haven Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
9,801

Riverview Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
19,048

King City Peaking Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
44

 
11,772

Agnews Power Plant
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
28

 
28

 
143,775

Subtotal
 
 
 
 
 
 
 
 
 
5,909

 
6,751

 
33,389,762




16



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)
 
2012
Total MWh
Generated(4)
TEXAS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deer Park Energy Center
 
TRE
 
TX
 
Cogen
 
100
%
 
843

 
1,014

 
6,164,077

Baytown Energy Center
 
TRE
 
TX
 
Cogen
 
100
%
 
782

 
842

 
4,510,187

Pasadena Power Plant(5)
 
TRE
 
TX
 
Cogen/Combined Cycle
 
100
%
 
763

 
781

 
4,638,034

Bosque Energy Center(6)
 
TRE
 
TX
 
Combined Cycle
 
100
%
 
740

 
762

 
301,167

Freestone Energy Center
 
TRE
 
TX
 
Combined Cycle
 
75
%
 
779

 
746

 
3,987,727

Magic Valley Generating Station
 
TRE
 
TX
 
Combined Cycle
 
100
%
 
662

 
692

 
4,290,913

Channel Energy Center
 
TRE
 
TX
 
Cogen
 
100
%
 
463

 
608

 
2,501,611

Brazos Valley Power Plant
 
TRE
 
TX
 
Combined Cycle
 
100
%
 
520

 
606

 
3,384,971

Corpus Christi Energy Center
 
TRE
 
TX
 
Cogen
 
100
%
 
426

 
500

 
2,287,273

Texas City Power Plant
 
TRE
 
TX
 
Cogen
 
100
%
 
400

 
453

 
1,230,745

Clear Lake Power Plant
 
TRE
 
TX
 
Cogen
 
100
%
 
344

 
400

 
515,663

Hidalgo Energy Center
 
TRE
 
TX
 
Combined Cycle
 
78.5
%
 
392

 
374

 
2,133,709

Freeport Energy Center(7)
 
TRE
 
TX
 
Cogen
 
100
%
 
210

 
236

 
1,436,720

Subtotal
 
 
 
 
 
 
 
 
 
7,324

 
8,014

 
37,382,797

NORTH
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Bethlehem Energy Center
 
RFC
 
PA
 
Combined Cycle
 
100
%
 
1,037

 
1,130

 
5,811,693

Hay Road Energy Center
 
RFC
 
DE
 
Combined Cycle
 
100
%
 
1,030

 
1,130

 
5,179,087

Edge Moor Energy Center
 
RFC
 
DE
 
Steam Cycle
 
100
%
 

 
725

 
1,077,342

York Energy Center
 
RFC
 
PA
 
Combined Cycle
 
100
%
 
519

 
565

 
3,484,727

Westbrook Energy Center
 
NPCC
 
ME
 
Combined Cycle
 
100
%
 
552

 
552

 
2,446,074

Greenfield Energy Centre(8)
 
NPCC
 
ON
 
Combined Cycle
 
50
%
 
422

 
519

 
1,645,699

RockGen Energy Center
 
MRO
 
WI
 
Simple Cycle
 
100
%
 

 
503

 
260,064

Zion Energy Center
 
RFC
 
IL
 
Simple Cycle
 
100
%
 

 
503

 
133,143

Mankato Power Plant
 
MRO
 
MN
 
Combined Cycle
 
100
%
 
280

 
375

 
495,871

Cumberland Energy Center
 
RFC
 
NJ
 
Simple Cycle
 
100
%
 

 
191

 
43,623

Deepwater Energy Center(9)
 
RFC
 
NJ
 
Steam Cycle
 
100
%
 

 
158

 
96,860

Kennedy International Airport Power Plant
 
NPCC
 
NY
 
Cogen
 
100
%
 
110

 
121

 
664,482

Sherman Avenue Energy Center
 
RFC
 
NJ
 
Simple Cycle
 
100
%
 

 
92

 
30,757

Bethpage Energy Center 3
 
NPCC
 
NY
 
Combined Cycle
 
100
%
 
60

 
80

 
204,385

Middle Energy Center(9)
 
RFC
 
NJ
 
Simple Cycle
 
100
%
 

 
77

 
475

Carll’s Corner Energy Center
 
RFC
 
NJ
 
Simple Cycle
 
100
%
 

 
73

 
23,151

Cedar Energy Center(9)
 
RFC
 
NJ
 
Simple Cycle
 
100
%
 

 
68

 
1,659

Mickleton Energy Center
 
RFC
 
NJ
 
Simple Cycle
 
100
%
 

 
67

 
3,932

Missouri Avenue Energy Center(9)
 
RFC
 
NJ
 
Simple Cycle
 
100
%
 

 
60

 
685

Bethpage Power Plant
 
NPCC
 
NY
 
Combined Cycle
 
100
%
 
55

 
56

 
197,899

Christiana Energy Center
 
RFC
 
DE
 
Simple Cycle
 
100
%
 

 
53

 
159

Bethpage Peaker
 
NPCC
 
NY
 
Simple Cycle
 
100
%
 

 
48

 
106,552

Stony Brook Power Plant
 
NPCC
 
NY
 
Cogen
 
100
%
 
45

 
47

 
309,901

Tasley Energy Center
 
RFC
 
VA
 
Simple Cycle
 
100
%
 

 
33

 
164

Whitby Cogeneration(10)
 
NPCC
 
ON
 
Cogen
 
50
%
 
25

 
25

 
205,417

Delaware City Energy Center
 
RFC
 
DE
 
Simple Cycle
 
100
%
 

 
23

 
68

West Energy Center
 
RFC
 
DE
 
Simple Cycle
 
100
%
 

 
20

 
42

Bayview Energy Center
 
RFC
 
VA
 
Simple Cycle
 
100
%
 

 
12

 
1,772

Crisfield Energy Center
 
RFC
 
MD
 
Simple Cycle
 
100
%
 

 
10

 
451

Vineland Solar Energy Center
 
RFC
 
NJ
 
Renewable
 
100
%
 

 
4

 
8,960

Subtotal
 
 
 
 
 
 
 
 
 
4,135

 
7,320

 
22,435,094


17



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)
 
2012
Total MWh
Generated(4)
SOUTHEAST
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oneta Energy Center
 
SPP
 
OK
 
Combined Cycle
 
100
%
 
980

 
1,134

 
3,320,995

Morgan Energy Center
 
SERC
 
AL
 
Cogen
 
100
%
 
720

 
807

 
4,062,128

Decatur Energy Center
 
SERC
 
AL
 
Combined Cycle
 
100
%
 
782

 
795

 
3,176,398

Columbia Energy Center
 
SERC
 
SC
 
Cogen
 
100
%
 
455

 
606

 
51,561

Osprey Energy Center
 
FRCC
 
FL
 
Combined Cycle
 
100
%
 
537

 
599

 
3,127,895

Carville Energy Center
 
SERC
 
LA
 
Cogen
 
100
%
 
449

 
501

 
2,855,396

Hog Bayou Energy Center
 
SERC
 
AL
 
Combined Cycle
 
100
%
 
235

 
237

 
1,113,720

Santa Rosa Energy Center
 
SERC
 
FL
 
Combined Cycle
 
100
%
 
235

 
225

 
850,178

Pine Bluff Energy Center
 
SERC
 
AR
 
Cogen
 
100
%
 
184

 
215

 
1,489,526

Auburndale Peaking Energy Center
 
FRCC
 
FL
 
Simple Cycle
 
100
%
 

 
117

 
27,080

Subtotal
 
 
 
 
 
 
 
 
 
4,577

 
5,236

 
20,074,877

Total operating power plants
 
90
 
 
 
 
 
 
 
21,945

 
27,321

 
113,282,530

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Power plants sold during 2012
Riverside Energy Center
 
MRO
 
WI
 
Combined Cycle
 
100%
 
n/a
 
n/a
 
1,148,198

Broad River Energy Center
 
SERC
 
SC
 
Simple Cycle
 
100%
 
n/a
 
n/a
 
1,073,303

Subtotal
 
 
 
 
 
 
 
 
 
 
 
 
 
2,221,501

Total operating and sold power plants
 
 
 
 
 
 
 
 
 
 
 
 
 
115,504,031

Projects Under Construction and Advanced Development
Projects under construction
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Russell City Energy Center
 
WECC
 
CA
 
Combined Cycle
 
75
%
 
429

 
464

 
n/a

Los Esteros Critical Energy Facility(11)
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
243

 
309

 
n/a

Channel Energy Center Expansion
 
TRE
 
TX
 
Cogen
 
100
%
 
260

 
200

 
n/a

Deer Park Energy Center Expansion
 
TRE
 
TX
 
Cogen
 
100
%
 
260

 
190

 
n/a

Projects under advanced development
 
 
 
 
 
 
 
 
 
 
Garrison Energy Center
 
RFC
 
DE
 
Combined Cycle
 
100
%
 
273

 
309

 
n/a

Total operating power plants and projects
 
 
 
 
 
 
 
 
 
23,410

 
28,793

 
 
___________
(1)
Natural gas-fired fleet capacities are generally 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. Oil-fired capacities reflect capacity test results.
(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)
Pasadena is comprised of 260 MW of cogen technology and 521 MW of combined cycle (non-cogen) technology.
(6)
Bosque Energy Center was acquired on November 7, 2012.
(7)
Freeport Energy Center is owned by Calpine; however, it is contracted and operated by The Dow Chemical Company.
(8)
Calpine holds a 50% partnership interest in Greenfield LP through its subsidiaries; however, it is operated by a third party.
(9)
We have provided notice to PJM that we plan to retire these units before commencement of the PJM Reliability Pricing Model 2015/2016 delivery year.

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(10)
Calpine holds a 50% partnership interest in Whitby Cogeneration through its subsidiaries; however, it is operated by Atlantic Packaging Products Ltd.
(11)
Los Esteros Critical Energy Facility is currently under construction to upgrade from a 188 MW simple-cycle generation power plant to a 309 MW combined-cycle generation power plant.
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. Although we do not operate the Freeport Energy Center, our outage services subsidiary performs all major maintenance services for this plant under a contract with The Dow Chemical Company through April 2032.
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 provide that the obligations to pay interest and principal on the loans are secured solely by the capital stock or partnership interests, physical assets, contracts and/or cash 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 debt instruments, including our First Lien Notes, First Lien Term Loans, and Corporate Revolving Facility. 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.

EMISSIONS AND OUR ENVIRONMENTAL PROFILE
Our environmental record has been widely recognized. We were an EPA Climate Leaders Partner with a stated goal to reduce GHG emissions, and we became the first power producer to earn the distinction of Climate Action LeaderTM. We have certified our GHG emissions inventory with the California Climate Action Registry every year since 2003. In 2011, our emissions of GHG amounted to about 41 million tons.
Natural Gas-Fired Generation
Our natural gas-fired, primarily combined-cycle fleet consumes significantly less fuel to generate power than conventional boiler/steam turbine power plants and emits fewer air pollutants per MWh of power produced as compared to coal-fired or oil-fired power plants. All of our 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 further lower air pollutant emissions per MWh of power generated. The table below summarizes approximate air pollutant emission rates from our natural gas-fired, combined-cycle power plants compared to the average emission rates from U.S. coal-, oil- and natural 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)
 
Advantage Compared to
Average U.S. Coal-, Oil-,
and Natural Gas-Fired
Power Plant
Nitrogen Oxides, NOx
 
1.92
 
0.14
 
92.7%
Acid rain, smog and fine particulate formation
 
 
 
 
 
 
Sulfur Dioxide, SO2
 
3.87
 
0.0058
 
99.9%
Acid rain and fine particulate formation
 
 
 
 
 
 
Mercury Compounds(3)
 
0.00002
 
 
100%
Neurotoxin
 
 
 
 
 
 
Carbon Dioxide, CO2
 
1,825
 
876
 
52%
Principal GHG—contributor to climate change
 
 
 
 
 
 

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___________
(1)
The average U.S. coal-, oil- and natural gas-fired power plants’ emission rates were obtained from the U.S. Department of Energy’s Electric Power Annual Report for 2011. Emission rates are based on 2011 emissions and net generation. The U.S. Department of Energy has not yet released 2012 information.
(2)
Our natural gas-fired, combined-cycle power plant estimated emission rates are based on our 2011 emissions and power generation data from our natural gas-fired, combined-cycle power plants (excluding combined heat 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 EPA Toxics Release Inventory for 2011. Emission rates are based on 2011 emissions and net generation from U.S. Department of Energy’s Electric Power Annual Report for 2011.
Geothermal Generation
Our 725 MW fleet of geothermal turbine-based power plants utilizes a natural, 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 natural gas-fired power plant, our Geysers Assets emit 99.9% less NOX, 100% less SO2 and 96.9% 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 water from local municipalities is recycled into the geothermal resource where it is converted by the Earth’s heat into steam for power production.
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 16 million gallons of reclaimed water 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 12 million gallons per day are received from the Santa Rosa Geysers Recharge Project, which we developed jointly with the City of Santa Rosa, and we receive, on average, approximately 4 million gallons a day from The Lake County Recharge Project from Lake County. 
In our combined-cycle power plants, we use mechanical draft cooling towers, which use up to 90% less water than conventional once-through cooling systems. Two of our combined-cycle power plants employ air-cooled condensers, which consume virtually no water for cooling.
In eleven of our operating power plants and one power plant under construction equipped with cooling towers, we reuse treated water from municipal treatment systems for cooling. By reusing water in these cooling towers, we avoid the usage of as much as 35 million gallons per day of valuable surface and/or groundwater for cooling.
Our Russell City Energy Center 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.
GOVERNMENTAL AND REGULATORY MATTERS
We are subject to complex and stringent energy, environmental and other laws and regulations at the federal, state and local levels as well as within the RTO and ISO markets in which we participate 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.
Environmental Matters
Federal Regulation of Air Emissions
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 existing federal and state performance standards mandated under the CAA. We continue to monitor and actively participate in EPA initiatives where we anticipate an impact on our business. Some of the more significant governmental and regulatory matters that affect our business are discussed below.

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Criteria Pollutants and Hazardous Air Pollutants
The CAA requires the EPA to regulate emissions of pollutants considered harmful to public health and the environment. The EPA has set NAAQS for six “criteria” pollutants: carbon monoxide, lead, NO2, particulate matter (“PM”), ozone and SO2. In addition, the CAA regulates a large number of air pollutants that are known to cause or may reasonably be anticipated to cause adverse effects to human health or adverse environmental effects, known as hazardous air pollutants (“HAPs”). The EPA is required to issue technology-based national emissions standards for hazardous air pollutants (“NESHAPs”) to limit the release of specified HAPs from specific industrial sectors.
Mercury and Air Toxics Standards
On December 21, 2011, the EPA issued the National Emission Standards for Hazardous Air Pollutants from Coal- and Oil-fired Electric Utility Steam Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric Utility, Industrial-Commercial-Institutional, and Small Industrial-Commercial-Institutional Steam Generating Units, otherwise known as the Mercury and Air Toxics Standards (“MATS”). MATS will reduce emissions of all hazardous air pollutants emitted by coal- and oil-fired electric generating units, including mercury (Hg), arsenic (As), chromium (Cr), nickel (Ni) and acid gases.
The EPA estimates that there are approximately 1,400 units affected by MATS, consisting of approximately 1,100 existing coal-fired units and 300 oil-fired units at approximately 600 power plants. The CAA provides existing units three years from the effective date of MATS to achieve compliance. As a result, existing coal-fired units without emissions controls will need to retire or install controls on acid gases, mercury and particulate matter emissions by April 16, 2015. State enforcement authorities also have discretion under the CAA to provide an additional year for technology installation. Further, the EPA issued a policy memorandum which indicates that the EPA may provide, in limited circumstances due to delays in the installation of controls, an additional year extension for MATS compliance where necessary to maintain electric system reliability. Accordingly, although the EPA’s analysis indicates that it should take no longer than three years for most existing units to comply, they may have up to five years, or until April 16, 2017, to install controls and comply with MATS.
We are not directly affected by MATS because it does not apply to natural gas-fired units, peaking units or units that use fuel oil as a backup fuel. We believe that the emission standards are sufficiently stringent to force existing coal-fired units without emissions controls to retire or to install the necessary controls by April 16, 2015 (unless an extension is granted), which could benefit our competitive position.
Prior to the April 16, 2012 filing deadline, a total of 30 petitions for review challenging MATS were filed in the U.S. Court of Appeals for the D.C. Circuit (“D.C. Circuit”) and subsequently consolidated under the case White Stallion Energy Center v. EPA. On March 19, 2012, Calpine, along with other energy companies, filed a motion for leave to intervene in the consolidated case in support of the EPA. Petitioners are expected to argue that the rule is arbitrary and capricious because the EPA failed to adequately demonstrate its threshold finding that the rule is “appropriate and necessary”; the EPA failed to address their concerns that MATS could damage electricity grid reliability; and the standards for new sources are not achievable.
Several petitioners moved to sever the issues specific to the standards for new coal-fired power plants and expedite briefing on those issues. On June 28, 2012, the D.C. Circuit granted the motion to sever and expedite briefing, and the new unit case is being considered under a separate docket number. However, on July 20, 2012, the EPA granted partial administrative reconsideration of certain issues affecting new units, namely, measurement issues related to mercury and the data underlying particulate matter and hydrogen chloride emissions standards. The EPA stayed the effectiveness of MATS with respect to the new unit issues under reconsideration.
As a consequence, on September 12, 2012, the D.C. Circuit stayed the severed case addressing standards for new units and held that case in abeyance pending the EPA’s administrative reconsideration of the new unit standards. In response to the petition for reconsideration, the EPA issued a proposed rule reconsidering MATS for new sources on November 30, 2012. The proposed rule would, among other things, amend certain new source standards and the requirements applicable during periods of startup and shut down. The public comment period on the proposed rule for new units closed on January 7, 2013. The EPA will issue a final reconsideration in March 2013.
The D.C. Circuit is being briefed on the remaining challenges to MATS that are not being held in abeyance (e.g., challenges to existing unit standards). Oral argument has not been scheduled for the remaining consolidated challenges to MATS.
Cross-State Air Pollution Rule
On July 6, 2011, the EPA finalized the Cross-State Air Pollution Rule (“CSAPR”) which would require a total of 28 states, primarily in the eastern U.S., to reduce annual SO2 emissions, annual NOx emissions and/or ozone season NOx emissions

21



to assist in attaining three NAAQS: the 1997 annual PM2.5 NAAQS, the 1997 8-hour ozone NAAQS, and the 2006 24-hour PM2.5 NAAQS.
CSAPR established an unlimited intrastate and limited interstate trading program with allowances allocated to sources based on historic heat input but capped at maximum annual emissions from 2003 to 2010. At current capacity factors, Calpine would have been allocated sufficient allowances; thus, CSAPR was not expected to have a negative impact on our operations. We expected the overall impact of CSAPR to be positive for Calpine because the significant emissions reduction requirements would require coal-fired electric generating units to either purchase allowances, switch to more expensive fuels, install air pollution controls, or reduce or discontinue operations, thereby incenting the increased utilization of existing, and development of new, natural gas-fired power plants.
A number of power generation companies, states and other groups filed petitions for review in the D.C. Circuit challenging CSAPR, and these cases were consolidated under EME Homer City Generation v. EPA. Calpine, other power generation companies, states, cities, and public health groups were granted intervenor status on behalf of respondent EPA.
On August 21, 2012, the D.C. Circuit vacated CSAPR. The D.C. Circuit ordered the EPA to continue administering CAIR, which the EPA has been implementing since the D.C. Circuit stayed CSAPR in December 2011 and which CSAPR was designed to replace due to the flaws in CAIR identified by the D.C. Circuit in North Carolina v. EPA.
The EPA petitioned for en banc rehearing (i.e., by all active judges on the D.C. Circuit) on October 5, 2012. Intervenors supporting the EPA also submitted three petitions for en banc rehearing upon similar grounds, including one submitted by a coalition of environmental and public health organizations, one by a group of cities and states (including the states of North Carolina, Connecticut, Delaware, Illinois, Maryland, Massachusetts, New York, Rhode Island and Vermont) and one jointly filed by Calpine and Exelon Corporation. On January 24, 2013, the D.C. Circuit denied en banc rehearing in this case. A petition for a writ of certiorari to appeal this decision to the Supreme Court may still be filed by the EPA or any other party. Assuming the decision is not reversed by the U.S. Supreme Court upon a petition for writ of certiorari, the EPA must continue to implement CAIR while it creates a replacement for CSAPR.
CAIR and Multi-Pollutant Program
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 NAAQS issued in 1997. 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 established annual Cap-and-trade programs for SO2 and NOX as well as a seasonal program for NOX. On July 11, 2008, 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 is positive. As a result of CSAPR being vacated in August 2012, the D.C. Circuit reinstated CAIR until the EPA creates a replacement for CSAPR.
GHG Emissions
On April 2, 2007, the U.S. Supreme Court in Massachusetts v. EPA ruled that the EPA has the authority to regulate GHG emissions under the CAA. In response to Massachusetts, the EPA issued an endangerment finding for GHGs on December 7, 2009, determining that concentrations of six GHGs endanger the public health and welfare. Further, pursuant to the CAA’s requirement that the EPA establish motor-vehicle emission standards for “any air pollutant . . . which may reasonably be anticipated to endanger public health or welfare,” the EPA promulgated the so-called “Tailpipe Rule” for GHGs, which set GHG emission standards for cars and light trucks.
Under the EPA’s longstanding interpretation of the CAA, the Tailpipe Rule automatically triggered regulation of stationary sources of GHG emissions under the Prevention of Significant Deterioration (“PSD”) program (which requires state-issued construction permits for stationary sources that have the potential to emit over 100 or 250 tons per year (“tpy”), the applicable threshold depending on the type of source, of “any air pollutant”) and Title V (which requires state-issued operating permits for stationary sources that have the potential to emit at least 100 tpy of “any air pollutant”). Accordingly, the EPA issued two rules phasing in stationary source GHG regulation. In the Timing Rule, the EPA delayed when major stationary sources of GHGs would otherwise be subject to PSD and Title V permitting, concluding that these requirements would commence on January 2, 2011, the

22



date on which the Tailpipe Rule became effective. In the Tailoring Rule, the EPA departed from the CAA’s 100/250 tpy emissions thresholds and provided that only the largest sources, those exceeding 75,000 or 100,000 tpy carbon dioxide equivalent (“CO2e”), depending on the program and project, would initially be subject to GHG permitting.
Under Step 1 of the Tailoring Rule (beginning in January 2011), new or modified sources already required to obtain a PSD permit due to their emissions of conventional regulated pollutants must satisfy best available control technology (“BACT”) requirements for GHGs if they emit or have the potential to emit at least 75,000 tpy CO2e. Under Step 2 of the Tailoring Rule (beginning in July 2011), new sources that emit or have the potential to emit at least 100,000 tpy CO2e and existing sources that emit at that level and that undertake modifications that increase emissions by at least 75,000 tpy CO2e must obtain a PSD permit and satisfy BACT requirements for GHGs, regardless of their emissions of any conventional pollutants. Step 3 of the Tailoring Rule was finalized in July 2012 and maintained the GHG PSD and Title V permitting thresholds specified under Step 2.
The EPA has issued guidance to permitting authorities on the implementation of GHG BACT that focuses on energy efficiency. We believe that the impact of the Tailoring Rule will be neutral to us because we expect that our efficient power plants would be found to meet BACT for GHGs if required to undergo PSD review. Calpine’s Russell City Energy Center, a 619 MW combined-cycle power plant (Calpine’s 75% net interest is 464 MW) being constructed in Hayward, California, voluntarily accepted GHG BACT limits in its PSD permit before such limits were required by law.
More than sixty petitions for review of these EPA rules were filed by industry and states, which were subsequently consolidated in the D.C. Circuit case Coalition for Responsible Regulation v. EPA. On June 26, 2012, the D.C. Circuit, in an unsigned per curiam opinion, upheld all of the challenged GHG regulations. Specifically, the D.C. Circuit denied the petitions relating to the Endangerment Finding and the Tailpipe Rule on the merits, while dismissing the petitions for review of the Timing Rule and the Tailoring Rule on constitutional standing grounds.
On August 10, 2012, industry groups requested rehearing en banc of the D.C. Circuit’s decision in Coalition for Responsible Regulation. On October 12, 2012, the EPA filed its response in opposition to the rehearing petition. The D.C. Circuit denied en banc review on December 20, 2012. The petitioners can still petition for a writ of certiorari to the U.S. Supreme Court, which must be done by March 20, 2013.
In light of the rehearing petition, on October 9, 2012, the D.C. Circuit decided to hold in abeyance a related case regarding Step 3 of the EPA’s Tailoring Rule (American Petroleum Institute v. EPA). The parties were directed to file motions to govern future proceedings in American Petroleum Institute within 30 days of the D.C. Circuit’s decision regarding en banc review in Coalition for Responsible Regulation. The case is still being held in abeyance and no motion has been filed seeking to release the case from abeyance.
In a related development, the EPA published a proposed New Source Performance Standard (“NSPS”) for GHG emissions from new electric generating units on April 13, 2012. The proposed rule would establish an output-based CO2 emissions standard of 1,000 lbs/MWh gross for new fossil fuel-fired generating units, which include boilers, integrated gasification combined-cycle units and stationary combined-cycle turbine units greater than 25 MW. The emissions standard is based on the performance of natural gas combined-cycle technology. The proposed NSPS would not apply to simple-cycle plants, plants that burn biomass, existing sources, sources being modified, or so-called “transitional sources” (i.e., coal-fired plants that received PSD permits by the publication date of the proposed rule (April 13, 2012) and commence construction within 12 months of the publication date of the proposal).
The proposed NSPS would have no impact on Calpine’s fleet or development plans. According to the EPA, the proposed NSPS would result in no notable compliance costs because, even in its absence, the electric sector would choose to build natural gas-fired electric generating units that already comply with the proposed standard.
The comment period on the proposed NSPS rule closed on June 25, 2012. Although the proposal is not yet final, several developers of permitted coal-fired power plants that could not meet the proposed NSPS without installation of carbon capture and storage technology filed suit in the D.C. Circuit, challenging the EPA’s proposal. On December 13, 2012, the D.C. Circuit dismissed the industry challenge to the proposed NSPS because the proposed rule is not “final agency action” subject to judicial review.
The EPA expects to finalize the proposed NSPS in March 2013.
Fees on Permissible Emissions
Section 185 of the CAA requires major stationary sources of NOX and volatile organic compounds (“VOCs”), such as power plants and refineries, in areas that fail to attain the NAAQS for ozone by the attainment date to pay a fee to the state or, if the state fails to collect the fee, the EPA. The fee is set in the CAA at $5,000 per ton of NOX or VOC (adjusted for inflation or approximately $9,000 per ton in 2011) and is payable on emissions that exceed 80% of each individual power plant’s baseline

23



emissions, which are established in the year before the attainment date; however, the EPA has provided guidance for the calculation of alternative baselines. The fee will remain in effect until the designated area achieves attainment.
We operate seven power plants in Texas and one in California that are located within a designated nonattainment area subject to Section 185. On January 5, 2010, the EPA issued guidance on developing fee programs required under Section 185, but that guidance was vacated by the D.C. Circuit in 2011 due to the EPA’s failure to follow notice-and-comment rulemaking procedures in its publication. On August 20, 2012, the EPA finalized approval of San Joaquin Valley Unified Air Pollution Control District’s (“SJVUAPCD”) fee-equivalent program, which the EPA determined is not less stringent than the program required by Section 185, and, therefore, is approvable as an equivalent alternative program. Environmentalists have challenged EPA’s approval of this program in the U.S. Court of Appeals for the Ninth Circuit. The lawsuit is currently pending.
The TCEQ proposed a rule in November 2012 to create a Section 185 program, using an approach similar to that used in the approved SJVUAPCD program. We estimate that compliance with this fee could result in additional costs to us of up to $4 million on an annual basis and our financial statements include accruals for our estimated Section 185 fees. In addition to this annual fee, we have accrued our estimate for Section 185 fees that may be applied retroactively, although it is unclear whether the EPA intends to require such retroactive fees to be collected. Our estimates are dependent upon a number of factors that could change in the future dependent upon, among other things: the EPA approval of state rulemakings, the designation of nonattainment status, the outcome of pending and potential litigation challenging the EPA’s approvals, the number of our operational power plants located in these areas and our emissions of NOX and VOC.
On June 18, 2012, the EPA determined that the New York-Northern New Jersey-Long Island (“NY-NJ-CT”) one-hour ozone attainment area failed to achieve the one-hour NAAQS by the applicable deadline, but also that it is currently attaining the one-hour standard. As a result of this action, our facilities in New York and New Jersey will not incur Section 185 fees as of the date of that determination. The EPA has not taken a firm position on retroactive collection of Section185 fees.
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. Our power plants currently receive sufficient free SO2 allowances; therefore, we will have no compliance expense for this program.
Regional and State Air Emissions 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 suite of GHG policies promulgated pursuant to AB 32, including its Cap-and-trade program. The evolution of these programs could have a material impact on our business.
California: GHG — Cap-and-Trade Regulation
California’s AB 32 requires the state to return to 1990 GHG emissions levels by 2020. To meet these levels, CARB has promulgated a number of regulations, including the Cap-and-trade regulation. In late 2011, CARB finalized its Cap-and-trade regulation and mandatory reporting regulation, which took effect on January 1, 2012. These regulations were further amended by CARB in 2012.
Under the Cap-and-trade regulation, the first compliance period for covered entities like Calpine began on January 1, 2013 and runs through the end of 2014. The second and third compliance periods cover 2015 through 2017 and 2018 through 2020, respectively. Covered entities must hold compliance instruments, which include allowances and offsets, in an amount equivalent to their emissions from sources of GHG located in California and from power imported into California. The first auction of GHG allowances was held on November 14, 2012 and included the sale of 2013 and 2015 vintage allowances. Quarterly auctions will be held every year from 2013 to 2020 with the next auction scheduled for February 19, 2013. The emissions market is currently functioning and the cost of the emissions permits is reflected in market pricing.
Currently, there are two pending lawsuits challenging the Cap-and-trade regulation. On March 28, 2012, two environmental organizations filed a lawsuit in San Francisco Superior Court seeking to invalidate the four protocols published by CARB for issuing offsets. On January 25, 2013, the court rejected the petitioners’ claims, holding that CARB’s development of the protocols was consistent with AB 32. The petitioners have until May 26, 2013 to appeal the decision in the California Court of Appeals. Additionally, on November 13, 2012, the California Chamber of Commerce filed a complaint in the Sacramento

24



Superior Court challenging CARB’s authority to auction allowances. The Sacramento Superior Court is scheduled to hold a hearing on the merits in that case on May 31, 2013. We cannot predict the ultimate success of either of these lawsuits nor can we predict whether there will be any additional legal challenges filed against the regulation or what the associated impacts of any such litigation would be.
In September 2012, the CARB Board directed its staff, by mid-2013, to propose amendments to the Cap-and-trade regulation that would, among other things, increase the auction purchase limit for covered entities and provide allowances to covered entities that have long-term contracts that do not allow the costs of compliance to be passed through to their customers. On January 8, 2013, CARB published a notice for a 15-day rulemaking concerning linkage of California’s and Quebec’s Cap-and-trade programs (“Linkage Notice”). The Linkage Notice provides background for CARB’s expected request that the California Governor make certain findings under Senate Bill (“SB”) 1018, which are required before California links with any other jurisdiction’s Cap-and-trade program. If the Governor makes these findings and CARB approves the proposed amendments, California and Quebec could hold their first joint auction of GHG allowances in August 2013. CARB’s economic analysis estimates that linkage between California and Quebec has the potential to increase California’s GHG allowance prices by 5% to 15%.
Overall, we support AB 32 and expect the net impact of the Cap-and-trade regulation to be beneficial to Calpine. We also believe we are positioned to comply with these regulations.
Northeast and Mid-Atlantic States: CO2 – RGGI
On January 1, 2009, ten northeast and Mid-Atlantic states implemented a Cap-and-trade program, RGGI, which affects our power plants in Maine, New York and Delaware (together emitting about 3.9 million tons of CO2 annually). In 2011, New Jersey announced its withdrawal from the RGGI program effective as of the 2012 compliance year.
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 quarterly public auctions. The most recent RGGI auction, conducted on December 5, 2012, cleared at the program’s floor price of $1.93 per allowance.
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 have also received annual allocations 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 or financial impact from RGGI, given the efficiency of our power plants in RGGI states.
The original memorandum of understanding under which the states created RGGI envisioned a review of the program after the first compliance period, which ended in 2011. The intent of the review is to assess the need for modifications to the RGGI program design. The program review has incorporated input from the states, regulated industry, and other stakeholders, including environmental advocacy groups. Calpine is actively participating in the process. As a result of the program review, a model rule was issued on February 7, 2013, with a significantly lower regional emission cap. To enact this change, RGGI states must promulgate the model rule or something substantially similar at the state level. The RGGI states have indicated a desire to incorporate the model rule into state regulations by the end of 2013, with a new emission cap taking effect in 2014. We do not expect any material impact to our business from this change in regulations.
Texas: NOX
Pursuant to authority granted under the CAA, regulations adopted by the 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 plants in the Houston-Galveston-Brazoria 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.
New Jersey: NOX
New Jersey’s High Electric Demand Day (“HEDD”) Rule limits NOx emissions from turbines and boilers. Beginning in 2015, Phase 2 of the HEDD Rule will require investments in emissions controls on some of our peaking power plants. We have provided notice to PJM that our 158 MW Deepwater Energy Center, 68 MW Cedar Energy Center and 60 MW Missouri Avenue Energy Center will be physically unable to perform in the delivery year 2015 as a result of the HEDD Rule and that we plan to retire the units before the commencement of the PJM Reliability Pricing Model 2015/2016 delivery year. We received PJM’s response in May 2012 in which PJM indicated its agreement with our deactivation request provided certain planned transmission

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upgrades are completed as scheduled. In the event the transmission upgrades are not completed as planned, PJM may require one or more of the plants to continue to operate for a period of time, but we would be entitled to full cost recovery.
We plan to install emissions controls equipment at our 73 MW Carll’s Corner Energy Center and 67 MW Mickleton Energy Center as these power plants cleared PJM’s 2015/2016 base residual auction. Our 77 MW Middle Energy Center did not clear PJM’s 2015/2016 base residual auction and we have provided notice to PJM of our intent to retire this unit before the commencement of the PJM Reliability Pricing Model 2015/2016 delivery year. All six of our power plants impacted by the HEDD Rule will be fully depreciated by June 2015. We expect that the retirement of these power plants or installation of emissions controls will not have a material impact on our financial condition, results of operations or cash flows.
Renewable Portfolio Standards
Policymakers have been considering variations of an RPS at the federal and state level. Generally, an 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 or clean energy resources by a certain date.
Federal RPS
Although there is currently no national RPS, President Obama has stated his goal is to have 80% of the nation’s electricity provided from clean energy resources, which includes natural gas resources, by 2035, and some U.S. Congressional members have expressed interest in national renewable or clean energy standard legislation. 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-fired power plants, primarily in Texas and California. Conversely, our natural gas power plants could benefit by providing complementary/back-up service for these intermittent renewable resources or by being included in a clean energy standard.
California RPS
On April 12, 2011, California’s Governor signed into law legislation establishing a new and higher RPS. The new law requires implementation of a 33% RPS by 2020, with intermediate targets between 2010 and 2020. The previous RPS legislation required certain retail power providers to generate or procure 20% of the power they sell to retail customers from renewable resources beginning in 2010. The new standard applies to all load-serving entities, including entities such as large municipal utilities that are not subject to CPUC jurisdiction. Under the new law, there are limits on different “buckets” of procurement that can be used to satisfy the RPS. Load-serving entities must satisfy at least a fraction of their compliance obligations with renewable power from resources located in California or delivered into California within the hour. Similarly, the legislation places limits on the use of “firmed and shaped” transactions and unbundled RECs – claims to the renewable aspect of the power produced by a renewable resource that can be traded separately from the underlying power. In general, the ability to use “firmed and shaped” transactions and unbundled RECs becomes more limited over the course of the implementation period. On December 1, 2011, the CPUC issued a decision on intermediate RPS procurement targets between the present and 2020. On December 15, 2011, the CPUC issued a decision clarifying exactly what transactions will fall into which bucket. In our role as an energy service provider, we are subject to the RPS requirements and continue to meet our compliance obligations. The increase in solar and wind generation on the state’s electrical grid has increased the need for flexible thermal generation which may be beneficial to Calpine.
Other
A number of additional states have an 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.
Other Environmental Regulations
In addition to controls on air emissions, our power plants and the equipment necessary to support them are subject to other 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 the use of water, but can also include wetlands protection and 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. In general, our relatively clean portfolio as compared to our competitors affords us some advantage in complying with these laws.

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Clean Water Act and Water Intake Rule
The federal Clean Water Act establishes requirements relating to 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 some of our power plants. In addition, we are required to maintain a spill prevention control and countermeasure plan with respect to some of our natural gas-fired power plants. We believe that we are in material compliance with applicable discharge requirements of the Clean Water Act.
Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of cooling water intake structures reflect the best technology available for minimizing adverse environmental impact. The EPA finalized the Phase I Rule in 2001, which applies to new facilities. The EPA initially promulgated the Phase II Rule, applying to large existing facilities, in 2004. However, the Phase II Rule was subsequently suspended and the EPA is required to finalize an updated rule applying to existing facilities by June 27, 2013. Calpine continues to participate in the rulemaking process; however, while the Section 316(b) rule will likely affect our competitors, we do not expect these rules to have a material impact on our operations because only two peaking power plants we own employ once-through cooling systems, one of which (Deepwater Energy Center) is scheduled to retire in 2015.
Additionally, the EPA is bound by a consent decree to issue a final rule to establish revised effluent limitation guidelines for the steam electric point source category by January 31, 2014. This rule is unlikely to have a material impact on our operations.
In California, the EPA delegates the implementation of Section 316(b) to the California State Water Resources Control Board (“SWRCB”). SWRCB has promulgated its own once-through cooling policy that establishes a schedule for once-through cooling units to install cooling towers or reduce entrainment and impingement to comparable levels as would be achieved with a cooling tower, or be retired. The compliance dates for approximately 12,000 MW of once-through cooling capacity in California occur between 2012 and 2020. We do not anticipate that the SWRCB’s policy will have a negative impact on our operations, as none of our power plants in California utilize once-through cooling systems.
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 (“EPAct 2005”), we use geothermal re-injection wells to inject reclaimed wastewater back into the steam reservoir, which are subject to the underground injection control program. We believe that we are in material compliance with Part C of the Safe Drinking Water Act.
Resource Conservation and Recovery Act
The Resource Conservation and Recovery Act (“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 related state laws.
On June 21, 2010, the EPA proposed a rule to regulate coal combustion residuals (“CCRs”) under RCRA. A Notice of Data Availability (“NODA”) was issued on October 12, 2011; but, there has not been any public movement on the rule since then. The EPA seeks to establish more stringent dam safety requirements to enhance performance surface impoundments used to manage CCRs. The EPA also seeks to regulate disposal of CCRs and has proposed to either regulate them as hazardous waste under Subtitle C of RCRA, or as nonhazardous waste under Subtitle D of RCRA. Both options will impose additional waste management costs on our competitors who rely on coal as a fuel. The EPA estimates a net present value cost of $3 billion to $21 billion to coal plants. We do not use coal so the CCRs rule, when finalized, will have no direct impact on our financial condition, results of operations or cash flows.
Comprehensive Environmental Response, Compensation and Liability Act
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also referred to as the 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.

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Federal Litigation regarding Liability for GHG Emissions
Litigation relating to common law tort liability for GHG emissions is working its way through the federal courts. While the U.S. Supreme Court has established that, in light of the EPA regulation of GHGs under the CAA, companies cannot be sued under federal common law theories of nuisance and negligence for their contribution to climate change, questions remain as to the viability of related state-law claims.
On September 21, 2009, the U.S. Court of Appeals for the Second Circuit (“Second Circuit”) issued a ruling in State of Connecticut v. American Electric Power Company Inc., 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 of CO2 per year and these emissions are causing and will continue to cause serious harm 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 decision, ruling in favor of the plaintiffs.
The Second Circuit’s decision was appealed to the U.S. Supreme Court. On June 20, 2011, the Supreme Court issued a decision rejecting the plaintiffs’ federal common law claim. The Court found that even if a federal common law claim could be made by plaintiffs, the CAA essentially “displaced” that claim. The case was remanded to the Second Circuit for further consideration of whether the plaintiffs may raise their claims under state common law or whether those claims are also preempted by federal law. The Second Circuit remanded to the district court for additional fact-finding. On December 6, 2011, the case was voluntarily dismissed. We cannot predict what impact the precedent of this case could have on our business.
The Supreme Court’s decision in the above matter has had significant consequences for other climate change cases, including Native Village of Kivalina v. ExxonMobil. In Kivalina, a federal district court in California sided with the defendants (multiple 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 to which the defendants allegedly contributed, Kivalina is subject to coastal storm waves and surges. On September 30, 2009, the court ruled in favor of the defendants, finding that the political question doctrine precluded the court from considering the plaintiff’s federal public nuisance claim. On September 21, 2012, the U.S. Court of Appeals for the Ninth Circuit affirmed, holding that the intervening U.S. Supreme Court case in American Electric Power militated against judicial review of Kivalina’s claim because the CAA displaces federal common law addressing domestic GHG emissions. We cannot predict what impact the precedent of this case could have on our business.
Power and Natural Gas Matters
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 (“FPA”), and the U.S. Public Utility Holding Company Act of 1935. These statutes have been amended and supplemented by subsequent legislation, including PURPA, EPAct 2005, and PUHCA 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.
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.

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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 books and records 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 (“FUCOs”). If any of our entities were not a QF, EWG or FUCO, then we and our holding company s