10-K 1 cpn_10kx12312013.htm CALPINE 10-K FOR YEAR-ENDED DECEMBER 31, 2013 CPN_10K_12.31.2013


 
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, 2013
 
 
[    ]
 
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.     [X]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer, “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer [X]
 
Accelerated filer  [    ]                
Non-accelerated filer  [    ]
 
Smaller reporting company  [    ]
(Do not check if a smaller reporting company)
 
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the 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, 2013, the last business day of the registrant’s most recently completed second fiscal quarter: approximately $9,361 million.
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: Calpine Corporation: 422,950,351 shares of common stock, par value $0.001, were outstanding as of February 10, 2014.

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 2014 Annual Meeting of Shareholders are incorporated by reference into Part III to the extent described therein.
 





CALPINE CORPORATION AND SUBSIDIARIES
FORM 10-K
ANNUAL REPORT
For the Year Ended December 31, 2013
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 annual report for the year ended December 31, 2013, 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
 
 
 
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
 
 
 
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
 
 
 
2020 First Lien Term Loan
 
The $390 million first lien senior secured term loan, dated October 23, 2013, among Calpine Corporation, as borrower, and the lenders party hereto, and Citibank, N.A., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent
 
 
 
2021 First Lien Notes
 
The $2.0 billion aggregate principal amount of 7.50% senior secured notes due 2021, issued October 22, 2010
 
 
 
2022 First Lien Notes
 
The $750 million aggregate principal amount of 6.0% senior secured notes due 2022, issued October 31, 2013
 
 
 
2023 First Lien Notes
 
The $1.2 billion aggregate principal amount of 7.875% senior secured notes due 2023, issued January 14, 2011
 
 
 
2024 First Lien Notes
 
The $490 million aggregate principal amount of 5.875% senior secured notes due 2024, issued October 31, 2013
 
 
 
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) adjustments to exclude the Adjusted EBITDA related to the noncontrolling interest, (g) stock-based compensation expense, (h) gains or losses on sales, dispositions or retirements of assets, (i) non-cash gains and losses from foreign currency translations, (j) gains or losses on the repurchase or extinguishment of debt, (k) non-cash GAAP-related adjustments to levelize revenues from tolling contracts and (l) other 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
 
 
 
 
 
 
 
 
 

ii



ABBREVIATION
 
DEFINITION
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
 
 
 
Broad River
 
Broad River Energy LLC, formerly an indirect, wholly-owned subsidiary of Calpine that leased the Broad River Energy Center, an 847 MW natural gas-fired, peaking power plant located in Gaffney, South Carolina
 
 
 
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 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 Notes
 
The $1.0 billion aggregate principal amount of 8.0% Senior Secured Notes due 2016 issued May 19, 2009, by CCFC and CCFC Finance
 
 
 
CCFC Term Loans
 
Collectively, the $900 million first lien senior secured term loan and the $300 million first lien senior secured term loan entered into on May 3, 2013, between CCFC, as borrower, and Goldman Sachs Lending Partners, LLC, as administrative agent and as collateral agent, and the lenders party thereto
 
 
 
CDHI
 
Calpine Development Holdings, Inc., an indirect, wholly-owned subsidiary of Calpine
 
 
 
CES
 
Calpine Energy Services, L.P., an indirect, wholly-owned subsidiary of Calpine
 
 
 

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, environmental compliance expense 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, environmental compliance expense, 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
 
 
 
Corporate Revolving Facility
 
The $1.0 billion aggregate amount revolving credit facility credit agreement, dated as of December 10, 2010, and was amended on June 27, 2013, 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, the 2022 First Lien Notes, the 2023 First Lien Notes and the 2024 First Lien Notes
 
 
 
First Lien Term Loans
 
Collectively, the 2018 First Lien Term Loans, the 2019 First Lien Term Loan and the 2020 First Lien Term Loan
 
 
 
FRCC
 
Florida Reliability Coordinating Council
 
 
 
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
 
 
 
IRC
 
Internal Revenue Code
 
 
 
IRS
 
U.S. Internal Revenue Service
 
 
 
ISO(s)
 
Independent System Operator(s)
 
 
 
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 of Calpine
 
 
 
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 of Calpine 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
 
 
 
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, 2013, filed with the SEC on February 12, 2014
 
 
 
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)
 
 
 
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
 
 
 
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.
 
 
 
TSR
 
Total shareholder return
 
 
 
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 Whitby, a 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada
 
 
 
WP&L
 
Wisconsin Power & Light Company

 

viii



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, seasonality of demand, 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 Term Loans 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;
Structural changes in the supply and demand of power, resulting from the development of new fuels or technologies and demand-side management tools;
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.

1



Where You Can Find Other Information
Our website is www.calpine.com. Information contained on our website is not part of this Report. Information that we furnish or file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to, or exhibits included in, these reports are available for download, free of charge, on our website soon after such reports are filed with or furnished to the SEC. Our SEC filings, including exhibits filed therewith, are also available at the SEC’s website at www.sec.gov. You may obtain and copy any document we furnish or file with the SEC at the SEC’s public reference room at 100 F Street, NE, Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the SEC’s public reference facilities by calling the SEC at 1-800-SEC-0330. You may request copies of these documents, upon payment of a duplicating fee, by writing to the SEC at its principal office at 100 F Street, NE, Room 1580, Washington, D.C. 20549.


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 at our power plants and in our commercial activity and on a disciplined approach to capital allocation that includes investing in growth, returning money to shareholders through share repurchases, and prudent balance sheet management.
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 2012.
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 93 power plants, including three under construction (one new power plant and two expansions of existing power plants), located throughout 20 states in the U.S. and Canada, with an aggregate generation capacity of 28,104 MW and 699 MW under construction. We have also announced the acquisition of a 1,050 MW power plant in Texas that is expected to close in the first quarter of 2014. Our fleet, including projects under construction, consists of 75 combustion turbine-based plants, two fossil steam-based plants, 15 geothermal turbine-based plants and one photovoltaic solar plant. In 2013, our fleet of power plants produced approximately 104 billion KWh of electric power for our customers. In addition, we are one of the largest consumers of natural gas in North America. In 2013, we consumed 782 Bcf or approximately 10% of the total estimated natural gas consumed for power generation in the U.S.
We believe our unique fleet compares favorably with those of our major competition on a cost basis, an environmental basis, and a scale and geographical diversity basis. The discovery and exploitation of shale natural gas combined with our modern and efficient combined-cycle plants has created short-term and long-term advantages. In the short-term, we are often the lowest cost resource to dispatch compared to other fuel types as demonstrated in 2012 and in 2013 when we realized meaningfully higher capacity factors than we have historically given our ability to displace other fuel types and older technologies. In the long-term, when compared on a full life-cycle cost, our power plants are even more competitive when considering the greater non-fuel operating costs and potential environmental liabilities associated with other technologies.
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 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.

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Our scale provides 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 to develop and offer a wide array of products and services to our customers. Finally, geographic diversity helps us manage and mitigate the impact of weather, regulatory and regional economic differences across our markets to provide more consistent financial performance.
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 power generation 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 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 Remaining a 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.
Our entire fleet achieved an exceptionally low forced outage factor of 1.6% and an impressive starting reliability of 98.5% during the year ended December 31, 2013.
Our 619 MW Russell City Energy Center (Calpine's 75% net interest is 464 MW) and 309 MW Los Esteros Critical Energy Facility commenced commercial operations during the third quarter of 2013 and achieved average capacity factors of 63.9% and 28.0%, respectively, after COD.
We commenced construction on the first phase of our Garrison Energy Center located in Dover, Delaware, during the second quarter of 2013 and expect COD during the second quarter of 2015.
For the past thirteen consecutive years, our Geysers Assets have reliably generated approximately 6 million MWh of renewable power per year and, in 2013, achieved an exceptional availability factor of approximately 96%.
2.
Focus on Enhancing Shareholder Value — We continue to make significant progress to deliver financially disciplined growth, to enhance shareholder value through disciplined capital allocation and to set the foundation for future 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, 2013 was marked by the following accomplishments:
Having previously authorized $600 million in repurchases of our common stock, our Board of Directors authorized the repurchase of an additional $400 million in shares of our common stock in February 2013 and an additional $100 million in August 2013. Under the aggregate $1.1 billion of authorizations, we repurchased a total of 60,139,816 shares of our outstanding common stock at an average price of $18.29 per share. In November 2013, our Board of Directors authorized a new $1.0 billion multi-year share repurchase program, under which we have repurchased a total of 12,459,919 shares of our common stock for approximately $239 million at an average price of $19.15 per share as of the filing of this Report.
In February 2013, we repriced our First Lien Term Loans by lowering the LIBOR floor by 0.25% to 1.0% and the margin over LIBOR by 0.25% to 3.0%.
On May 3, 2013, CCFC, our indirect, wholly-owned subsidiary, entered into a credit agreement providing for a first lien senior secured term loan facility comprised of (i) a $900 million 7-year term loan and (ii) a $300 million 8.5-year term loan. CCFC utilized the proceeds received from the CCFC Term Loans to redeem the CCFC Notes which converted $1.0 billion in fixed rate debt to lower variable rate debt and extended the maturity.
On June 27, 2013, we amended our Corporate Revolving Facility which lowered our costs and extended the maturity by more than two and half years.
On October 31, 2013, we issued our 2024 First Lien Notes and used the proceeds to reduce our overall cost of debt and extend maturities by redeeming a portion of our 2019 First Lien Notes, 2020 First Lien Notes, 2021 First Lien Notes and 2023 First Lien Notes each of which carry a higher fixed interest rate.
On December 2, 2013, we completed the repayment of our 2017 First Lien Notes with the proceeds from our 2020 First Lien Term Loan and 2022 First Lien Notes which will lower our annual interest expense and extend the maturity of approximately $1.1 billion in debt.

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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 acquisitions, 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, growth initiatives and modernization activities are discussed below:
West:
Russell City Energy Center — Our Russell City Energy Center commenced commercial operations in August 2013 which brought on line approximately 429 MW of net interest baseload capacity (464 MW with peaking capacity) representing our 75% share. Russell City Energy Center is contracted to deliver its full output to PG&E under a ten-year PPA.
Los Esteros Critical Energy Facility — During 2009, we and PG&E negotiated a new ten-year 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 has increased the efficiency and environmental performance of the power plant by lowering the Heat Rate. Our Los Esteros Critical Energy Facility commenced commercial operations in August 2013.
Texas:
Channel and Deer Park Expansions In the fourth quarter of 2012, we began construction to expand the baseload capacity of our Deer Park and Channel Energy Centers by approximately 260 MW each. Each power plant features an oversized steam turbine that, along with existing plant infrastructure, allows us to add capacity and improve the power plant's overall efficiency at a meaningful discount to the market cost of building new capacity. We expect COD on the expansions of our Channel and Deer Park Energy Centers during the second quarter of 2014.
Guadalupe Energy Center On December 2, 2013, we announced an agreement to purchase a natural gas-fired, combined-cycle power plant with a nameplate capacity of 1,050 MW located in Guadalupe County, Texas for approximately $625 million, which will increase capacity in our Texas segment. The purchase price does not include $15 million in consideration for the rights we also acquired to an advanced development opportunity for an approximately 400 MW quick-start, natural gas-fired peaker, if market conditions warrant. We are currently evaluating funding sources for the acquisition of this power plant including, but not limited to, nonrecourse financing, corporate financing or internally generated funds.
North:
Garrison Energy Center — Garrison Energy Center is a 309 MW combined-cycle project located in Delaware on a site secured by a long-term lease with the City of Dover. Construction commenced in April 2013, and we expect COD during the second quarter of 2015. The project’s capacity cleared PJM’s 2015/2016 and 2016/2017 base residual auctions. We are currently evaluating funding sources for the construction of this project including, but not limited to, nonrecourse financing, corporate financing or internally generated funds. We are in the early stages of development of a second phase (309 MW) of this project. PJM has completed the feasibility and system impact studies for this phase and the facilities study is currently underway.
Mankato Power Plant Expansion — We are proposing a 345 MW expansion of the Mankato Power Plant in response to a competitive resource acquisition process for approximately 500 MW of new capacity established by the Minnesota Public Utilities Commission (“MPUC”). The initial stage of the proceeding was managed via a contested case hearing. On December 31, 2013, the Administrative Law Judge (“ALJ”) in the contested case issued a non-binding recommendation to the MPUC that the state should secure approximately 100 MW of distributed solar resources at this time and defer procurement of new thermal resources. Xcel Energy (Northern States Power) and the Minnesota Department of Commerce subsequently filed exceptions to the ALJ decision and continue to advocate in support of new, natural gas-fired generation resources. The MPUC will hold deliberations and decide whether to accept, reject or modify the ALJ recommendation in early 2014.
PJM Development Opportunities — We are currently evaluating opportunities to develop more than 1,000 MW in the PJM market area that feature cost advantages such as existing infrastructure and favorable transmission queue

5



positions. These projects are continuing to advance entitlements (permits, zoning, transmission, etc.) for their potential development at a future date.
All Segments:
Turbine Modernization — We continue to move forward with our turbine modernization program. Through December 31, 2013, we have completed the upgrade of twelve Siemens and eight GE turbines totaling approximately 200 MW and have committed to upgrade approximately four additional turbines. Similarly, we have the opportunity at several of our power plants in Texas to implement further turbine modernizations to add as much as 500 MW of incremental capacity across the region at attractive prices. In addition, we have begun a program to update our dual-fueled turbines at certain of our power plants in our North segment. Our decision to invest in these turbine modernizations depends upon, among other things, further clarity on market design reforms currently being considered.
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 in 2013 is as follows:
We entered into a new three-year PPA with South Carolina Electric and Gas Company to provide 200 MW of power generated by our Columbia Energy Center, commencing in January 2014.
We entered into two new resource adequacy contracts with PG&E for our Delta and Sutter Energy Centers for the full capacity of each plant which commence in January and June 2014, respectively, and extend through December 2015 and 2016, respectively.
We entered into two new PPAs with the Marin Energy Authority consisting of a one-year contract to provide 3 MW of renewable power during 2014 and a ten-year contract to provide 10 MW of renewable power commencing in January 2017. The renewable power to be delivered under both contracts will be generated from our Geysers Assets.
We entered into a 100 MW financial PPA with a counterparty in PJM which commenced in November 2013 and extends through 2016.
We entered into a new five-year PPA commencing in 2014 for approximately 50 MW and extended the existing steam agreement for ten years beyond 2016 with Celanese Ltd for power and steam generated from our Clear Lake Power Plant.
We entered into a new ten-year PPA with the Sonoma Clean Power Authority to provide 10 MW of renewable power from our Geysers Assets commencing in May 2014. The capacity under contract will increase in increments each year, up to a maximum of 18 MW for years 2020 through 2023.
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 $369 billion in power sales in 2013 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 wholesale power markets in New York, the northeast and the midwest. In addition to our sales of electrical power and steam, we produce several ancillary 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 energy (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, especially during the record low gas prices of 2012.

6



Second, we provide capacity for sale to utilities, independent electric system operators, and retail power providers. In various markets, retail power providers (or independent electric system operators on their behalf) 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 or in neighboring areas. 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 a 4 MW photovoltaic solar generation facility located in Vineland, New Jersey.
Fourth, our cogeneration power plants produce steam in addition to electricity for sale to industrial customers for use in their manufacturing processes 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. For 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 emission allowances and credits, including those under California’s AB 32 GHG reduction program, RGGI, the federal Acid Rain and CAIR programs and emission reduction credits under the federal Nonattainment New Source Review 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 are our sale of wholesale power and capacity. We utilize long-term customer contracts for our power and steam sales where possible. For power and capacity that are not sold under customer contracts or longer-dated capacity auctions, we use our hedging program and sell power into shorter term wholesale markets throughout the regions in which we participate.
When selling 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 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 and power plant outage 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, higher capacity prices 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 and energy efficiency measures. Although uncertainty exists and there are key regional differences at a macro level, continued economic recovery and thus, corresponding net load recovery, with the lack of broad new power plant investments

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and the retirement of older, uneconomic units 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:
 
 
2013(1)
West:
 
WECC
24.7
%
Texas:
 
TRE
12.9
%
North:
 
NPCC
20.1
%
MISO
18.8
%
PJM
29.3
%
Southeast:
 
SERC
30.3
%
SPP
39.4
%
FRCC
28.4
%
___________
(1)
Data source is NERC weather-normalized estimates for 2013 published in May 2013.
In recent years and in some regional markets such as PJM, the ability of customers to curtail load or temporarily utilize onsite backup generation instead of grid-provided electricity, known as “demand response,” has become a significant portion of “supply” and thus contributes to reserve margin estimates. While demand response reduces demand for centralized generation during peak times, it typically does so at a very high variable cost. To the extent demand response resources are treated like other sources of supply (e.g., their variable cost-based bids are allowed to affect the market clearing price for power), high resulting prices benefit lower-cost units like Calpine’s. Further, in many cases demand response has acted to discourage new investment in competing centralized generation plants (for example, by winning capacity auctions instead of new units). This should eventually contribute to higher energy price volatility during peak energy demand periods.
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 generally do not expect fuel oil requirements to be material to our portfolio of power plants. In our North segment, where the supply of natural gas is constrained, we have approximately 5,500 MW of dual-fueled capable power plants. 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 population centers), transportation availability and supplier financial stability issues can and do occur. When natural gas supply interruptions do occur, some of our power plants benefit from the ability to operate on fuel oil instead of gas.
Lower natural gas prices over the past five 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 average natural gas price of $4.03/MMBtu, $2.83/MMBtu, and $3.73/MMBtu during 2011, 2012 and 2013, respectively. Natural gas prices in some parts of the country for parts of 2011, 2012 and 2013 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, particularly 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

8



gas to supply the U.S. for the next 90 years. Despite moderate increases in natural gas prices and some significant, weather induced regional price spikes this winter, there is an emerging view that lower priced natural gas will be available for the medium to long-term future. Further, high levels of natural gas production relative to available pipeline export capacity in some locations such as the Marcellus shale production region have put additional, seasonal downward pressure on local natural gas prices. Overall, low natural gas prices and corresponding low power prices have challenged the economics of nuclear and coal-fired plants, leading to numerous announced and potential unit retirements.
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. Additionally, in the Mid-Atlantic region, we have generating units capable of burning either natural gas or fuel oil. For these units, on the rare occasions when the price of natural gas is excessively high relative to fuel oil, our unhedged Commodity Margin may increase as a result of the lower cost fuel.
In 2012 and to a much lesser degree in 2013, 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 and, in fact, making it more challenging for existing generation resources that utilize such technology to continue operating economically.
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. However, our geographically diverse portfolio mitigates the impact on our Commodity Margin of weather in specific regions of the U.S. 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 Trends
We believe that, on balance, we will be favorably impacted by current regulatory and environmental trends, including those described below, given the characteristics of our power plant portfolio:
Economic pressures continue to increase for coal-fired power generation as state and federal agencies enact environmental regulations 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. We anticipate that older, less efficient fossil-fuel power plants that emit much higher amounts of GHG, SO2, NOX, Hg and acid gases, which operate nationwide, but more prominently in the eastern U.S., will be negatively impacted by current and future air emissions, water and waste regulations and legislation both at the state and federal levels which will require many coal-fired power plants to install expensive air pollution controls or reduce or discontinue operations. As a result, any retirements or curtailments could enhance our growth opportunities. The estimated capacity for fossil-fueled plants 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
 
9,469

MW
 
133,348

MW
Texas:
 
 
 
 
 
 
TRE
 
3,059

MW
 
82,920

MW
North:
 
 
 
 
 
 
NPCC
 
7,286

MW
 
57,428

MW
MRO
 
4,736

MW
 
46,037

MW
RFC
 
25,234

MW
 
195,002

MW
Southeast:
 
 
 
 
 
 
SERC
 
26,556

MW
 
232,000

MW
SPP
 
5,037

MW
 
60,093

MW
FRCC
 
279

MW
 
58,805

MW
Total
 
81,656

MW

865,633

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. Should wind and solar generation continue to expand, our energy margin may decrease. To the extent market structures evolve to appropriately compensate units for providing flexible capacity to ensure reliability, our capacity revenues are likely to increase, providing an offset to reduced energy margin.
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, transmission lines and pipelines continue to increase in stringency and complexity, resulting in prolonged, expensive development cycles and high capital investments.
We believe these trends are overall positive for our existing 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:

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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;
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 2013, 27% of the power generated in the U.S. was fueled by natural gas, 39% by coal, 19% by nuclear facilities and the remaining 15% of power generated 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 retire. 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. Low power prices are even challenging the economics of existing nuclear facilities, resulting in the retirement or potential retirement of certain existing nuclear generating units.
Federal and state financial incentives and RPS requirements continue to foster renewables development. However, the production tax credit for wind expired at the end of 2013 (although if plants were “under construction”, they could keep the credit) and for solar the investment tax credit expires at the end of 2016. Unless the tax credits are extended and/or natural gas prices increase substantially from today’s levels, competition from new renewables will likely diminish. 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.

11



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, efficiency and production cost management;
accurately assess and effectively manage our risks; and
accomplish all of the above with an environmental impact lower than the competition, and further decreasing over time.
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 power and in natural gas, natural gas transportation, electric transmission, REC prices, carbon allowance 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 104 billion KWh of electricity in 2013 across North America (primarily in the U.S.). We are one of the largest consumers of natural gas in North America having consumed approximately 782 Bcf during 2013. 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 2014 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 estimates 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

12



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 volatility in our earnings. The fair value of our commodity derivative instruments residing in AOCI during the previous application of hedge accounting was reclassified 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 two of our customers.


13



DESCRIPTION OF OUR POWER PLANTS
    
Geographic Diversity
Dispatch Technology
 

        

14



Power Plants in Operation at December 31, 2013
We own 93 power plants, including three under construction (one new power plant and two expansions of existing power plants), with an aggregate generation capacity of 28,104 MW and 699 MW under construction. We have also announced the acquisition of a 1,050 MW power plant in Texas that is expected to close in the first quarter of 2014.
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 24,027 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. 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 “all in” Steam Adjusted Heat Rate for 2013 for the power plants we operate was 7,386 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%.
Our natural gas fleet is relatively young with a weighted average age, based upon MW capacities in operation, of approximately fourteen 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 per MWh produced 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 thirteen consecutive years, our Geysers Assets have continued to generate approximately 6 million MWh of renewable power 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 96% in 2013.
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.

15



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, indicated 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 108 leases comprising approximately 29,000 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 2013 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 relative 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.

16



Table of Operating Power Plants and Projects Under Construction
Set forth below is certain information regarding our operating power plants and projects under construction at December 31, 2013.
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)
 
2013
Total MWh
Generated(4)
WEST
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Geothermal
 
 
 
 
 
 
 
 
 
 
 
 
 
 
McCabe #5 & #6
 
WECC
 
CA
 
Renewable
 
100
%
 
78

 
78

 
640,071

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

 
69

 
670,778

Calistoga
 
WECC
 
CA
 
Renewable
 
100
%
 
66

 
66

 
470,897

Eagle Rock
 
WECC
 
CA
 
Renewable
 
100
%
 
66

 
66

 
565,293

Quicksilver
 
WECC
 
CA
 
Renewable
 
100
%
 
53

 
53

 
381,149

Cobb Creek
 
WECC
 
CA
 
Renewable
 
100
%
 
52

 
52

 
428,533

Lake View
 
WECC
 
CA
 
Renewable
 
100
%
 
52

 
52

 
506,450

Sulphur Springs
 
WECC
 
CA
 
Renewable
 
100
%
 
51

 
51

 
448,878

Socrates
 
WECC
 
CA
 
Renewable
 
100
%
 
50

 
50

 
374,884

Big Geysers
 
WECC
 
CA
 
Renewable
 
100
%
 
48

 
48

 
439,554

Grant
 
WECC
 
CA
 
Renewable
 
100
%
 
43

 
43

 
329,350

Sonoma
 
WECC
 
CA
 
Renewable
 
100
%
 
42

 
42

 
332,408

West Ford Flat
 
WECC
 
CA
 
Renewable
 
100
%
 
24

 
24

 
207,479

Aidlin
 
WECC
 
CA
 
Renewable
 
100
%
 
17

 
17

 
112,149

Bear Canyon (5)
 
WECC
 
CA
 
Renewable
 
100
%
 
14

 
14

 
94,787

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

 
857

 
5,652,554

Pastoria Energy Center
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
770

 
749

 
4,998,564

Hermiston Power Project
 
WECC
 
OR
 
Combined Cycle
 
100
%
 
566

 
635

 
3,655,669

Otay Mesa Energy Center
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
513

 
608

 
3,702,500

Metcalf Energy Center
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
564

 
605

 
3,196,876

Sutter Energy Center
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
542

 
578

 
1,042,367

Los Medanos Energy Center
 
WECC
 
CA
 
Cogen
 
100
%
 
518

 
572

 
3,524,373

South Point Energy Center
 
WECC
 
AZ
 
Combined Cycle
 
100
%
 
520

 
530

 
1,939,129

Russell City Energy Center
 
WECC
 
CA
 
Combined Cycle
 
75
%
 
429

 
464

 
1,038,642

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

 
309

 
300,600

Gilroy Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
141

 
63,072

Gilroy Cogeneration Plant
 
WECC
 
CA
 
Cogen
 
100
%
 
109

 
130

 
126,272

King City Cogeneration Plant
 
WECC
 
CA
 
Cogen
 
100
%
 
120

 
120

 
409,944

Greenleaf 1 Power Plant
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
50

 
50

 
21,634

Greenleaf 2 Power Plant
 
WECC
 
CA
 
Cogen
 
100
%
 
49

 
49

 
264,182

Wolfskill Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
48

 
19,023

Yuba City Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
37,185

Feather River Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
32,355

Creed Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
12,688

Lambie Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
11,526

Goose Haven Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
12,253

Riverview Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
20,288

King City Peaking Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
44

 
6,453

Agnews Power Plant
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
28

 
28

 
19,489

Subtotal
 
 
 
 
 
 
 
 
 
6,581

 
7,524

 
36,110,298




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)
 
2013
Total MWh
Generated(4)
TEXAS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deer Park Energy Center
 
TRE
 
TX
 
Cogen
 
100
%
 
843

 
1,014

 
5,526,362

Baytown Energy Center
 
TRE
 
TX
 
Cogen
 
100
%
 
782

 
842

 
3,411,055

Pasadena Power Plant(6)
 
TRE
 
TX
 
Cogen/Combined Cycle
 
100
%
 
763

 
781

 
3,995,967

Bosque Energy Center
 
TRE
 
TX
 
Combined Cycle
 
100
%
 
740

 
762

 
3,733,111

Freestone Energy Center
 
TRE
 
TX
 
Combined Cycle
 
75
%
 
779

 
746

 
2,988,092

Magic Valley Generating Station
 
TRE
 
TX
 
Combined Cycle
 
100
%
 
672

 
702

 
3,548,653

Channel Energy Center
 
TRE
 
TX
 
Cogen
 
100
%
 
463

 
608

 
2,411,706

Brazos Valley Power Plant
 
TRE
 
TX
 
Combined Cycle
 
100
%
 
520

 
606

 
2,651,755

Corpus Christi Energy Center
 
TRE
 
TX
 
Cogen
 
100
%
 
426

 
500

 
1,996,448

Texas City Power Plant
 
TRE
 
TX
 
Cogen
 
100
%
 
400

 
453

 
946,076

Clear Lake Power Plant
 
TRE
 
TX
 
Cogen
 
100
%
 
344

 
400

 
419,127

Hidalgo Energy Center
 
TRE
 
TX
 
Combined Cycle
 
78.5
%
 
392

 
374

 
1,714,807

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

 
236

 
1,253,892

Subtotal
 
 
 
 
 
 
 
 
 
7,334

 
8,024

 
34,597,051

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

 
1,130

 
4,863,858

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

 
1,130

 
4,506,365

Edge Moor Energy Center
 
RFC
 
DE
 
Steam Cycle
 
100
%
 

 
725

 
400,052

York Energy Center
 
RFC
 
PA
 
Combined Cycle
 
100
%
 
519

 
565

 
2,018,753

Westbrook Energy Center
 
NPCC
 
ME
 
Combined Cycle
 
100
%
 
552

 
552

 
2,372,882

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

 
519

 
846,921

RockGen Energy Center
 
MRO
 
WI
 
Simple Cycle
 
100
%
 

 
503

 
172,430

Zion Energy Center
 
RFC
 
IL
 
Simple Cycle
 
100
%
 

 
503

 
116,809

Mankato Power Plant
 
MRO
 
MN
 
Combined Cycle
 
100
%
 
280

 
375

 
597,842

Cumberland Energy Center
 
RFC
 
NJ
 
Simple Cycle
 
100
%
 

 
191

 
80,206

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

 
158

 
35,444

Kennedy International Airport Power Plant
 
NPCC
 
NY
 
Cogen
 
100
%
 
110

 
121

 
636,503

Sherman Avenue Energy Center
 
RFC
 
NJ
 
Simple Cycle
 
100
%
 

 
92

 
23,550

Bethpage Energy Center 3
 
NPCC
 
NY
 
Combined Cycle
 
100
%
 
60

 
80

 
221,689

Middle Energy Center(10)
 
RFC
 
NJ
 
Simple Cycle
 
100
%
 

 
77

 
599

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

 
73

 
21,204

Cedar Energy Center(10)
 
RFC
 
NJ
 
Simple Cycle
 
100
%
 

 
68

 
9,456

Mickleton Energy Center
 
RFC
 
NJ
 
Simple Cycle
 
100
%
 

 
67

 
6,538

Missouri Avenue Energy Center(10)
 
RFC
 
NJ
 
Simple Cycle
 
100
%
 

 
60

 
1,283

Bethpage Power Plant
 
NPCC
 
NY
 
Combined Cycle
 
100
%
 
55

 
56

 
256,496

Christiana Energy Center
 
RFC
 
DE
 
Simple Cycle
 
100
%
 

 
53

 
56

Bethpage Peaker
 
NPCC
 
NY
 
Simple Cycle
 
100
%
 

 
48

 
154,107

Stony Brook Power Plant
 
NPCC
 
NY
 
Cogen
 
100
%
 
45

 
47

 
313,139

Tasley Energy Center
 
RFC
 
VA
 
Simple Cycle
 
100
%
 

 
33

 
308

Whitby Cogeneration(11)
 
NPCC
 
ON
 
Cogen
 
50
%
 
25

 
25

 
202,322

Delaware City Energy Center
 
RFC
 
DE
 
Simple Cycle
 
100
%
 

 
23

 
173

West Energy Center
 
RFC
 
DE
 
Simple Cycle
 
100
%
 

 
20

 
161

Bayview Energy Center
 
RFC
 
VA
 
Simple Cycle
 
100
%
 

 
12

 
682

Crisfield Energy Center
 
RFC
 
MD
 
Simple Cycle
 
100
%
 

 
10

 
559

Vineland Solar Energy Center
 
RFC
 
NJ
 
Renewable
 
100
%
 

 
4

 
5,694

Subtotal
 
 
 
 
 
 
 
 
 
4,135

 
7,320

 
17,866,081


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SEGMENT / Power Plant
 
NERC
Region
 
U.S. State or
Canadian
Province
 
Technology
 
Calpine
Interest
Percentage
 
Calpine Net
Interest
Baseload
(MW)(1)(3)
 
Calpine Net
Interest
With Peaking
(MW)(2)(3)
 
2013
Total MWh
Generated(4)
SOUTHEAST
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oneta Energy Center
 
SPP
 
OK
 
Combined Cycle
 
100
%
 
980

 
1,134

 
2,303,798

Morgan Energy Center
 
SERC
 
AL
 
Cogen
 
100
%
 
720

 
807

 
3,728,930

Decatur Energy Center
 
SERC
 
AL
 
Combined Cycle
 
100
%
 
782

 
795

 
1,108,330

Columbia Energy Center
 
SERC
 
SC
 
Cogen
 
100
%
 
455

 
606

 
695,189

Osprey Energy Center
 
FRCC
 
FL
 
Combined Cycle
 
100
%
 
537

 
599

 
2,679,745

Carville Energy Center
 
SERC
 
LA
 
Cogen
 
100
%
 
449

 
501

 
2,218,870

Hog Bayou Energy Center
 
SERC
 
AL
 
Combined Cycle
 
100
%
 
235

 
237

 
733,987

Santa Rosa Energy Center
 
SERC
 
FL
 
Combined Cycle
 
100
%
 
235

 
225

 
373,755

Pine Bluff Energy Center
 
SERC
 
AR
 
Cogen
 
100
%
 
184

 
215

 
1,491,617

Auburndale Peaking Energy Center
 
FRCC
 
FL
 
Simple Cycle
 
100
%
 

 
117

 
5,959

Subtotal
 
 
 
 
 
 
 
 
 
4,577

 
5,236

 
15,340,180

Total operating power plants
 
92
 
 
 
 
 
 
 
22,627

 
28,104

 
103,913,610

 
Projects Under Construction
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

Garrison Energy Center
 
RFC
 
DE
 
Combined Cycle
 
100
%
 
273

 
309

 
n/a

Total operating power plants and projects
 
 
 
 
 
 
 
 
 
23,420

 
28,803

 
 
___________
(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)
Bear Canyon will be retired in December 2014; however, the steam used to run its turbine will be redirected to a different Geysers power plant resulting in no diminution of overall generating capacity at our Geysers fleet.
(6)
Pasadena is comprised of 260 MW of cogen technology and 521 MW of combined cycle (non-cogen) technology.
(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)
Deepwater Energy Center is currently scheduled to be retired in May 2014.
(10)
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.
(11)
Calpine holds a 50% partnership interest in Whitby Cogeneration through its subsidiaries; however, it is operated by Atlantic Packaging Products Ltd.
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

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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 2012, our emissions of GHG amounted to approximately 49 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 and acid rain. 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
 
4.16
 
0.12
 
97.1%
Acid rain, smog and fine particulate formation
 
 
 
 
 
 
Sulfur Dioxide, SO2
 
8.71
 
0.0043
 
99.9%
Acid rain and fine particulate formation
 
 
 
 
 
 
Mercury Compounds(3)
 
0.00002
 
 
100%
Neurotoxin
 
 
 
 
 
 
Carbon Dioxide, CO2
 
1,941
 
852
 
56.1%
Principal GHG—contributor to climate change
 
 
 
 
 
 
___________
(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 2012. Emission rates are based on 2012 emissions and net generation. The U.S. Department of Energy has not yet released 2013 information.
(2)
Our natural gas-fired, combined-cycle power plant estimated emission rates are based on our 2012 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.

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(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 2012. Emission rates are based on 2012 emissions and net generation from U.S. Department of Energy’s Electric Power Annual Report for 2012.
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 twelve of our operating power plants 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.
Russell City Energy Center was designed to operate on potable water initially until the recycled water facility allowing 100% reclaimed water to be used becomes fully operational. Initial performance of the recycled water facility has been insufficient to support plant operations on reclaimed water. As a result, Russell City Energy Center is continuing to use primarily potable water until such time as the recycled water facility achieves the desired performance. Calpine is in active discussions with regulatory agencies regarding this matter. We do not expect any material economic impact from the extended use of potable water.
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.
Some of the more significant governmental and regulatory matters that affect our business are discussed below.
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.
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, 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

21



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 NESHAP 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 to comply with MATS. 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.
MATS has been extensively challenged through both administrative challenges and litigation, on issues relating to new units, existing units, and other technical issues. On April 24, 2013, the EPA finalized changes to the new unit standards in an attempt to resolve the administrative and judicial challenges relating to that particular section of the rule. Additional challenges, both administrative and legal, were filed with respect to that revision. Briefing has been submitted and oral argument concluded before the U.S. Court of Appeals for the D.C. Circuit (“D.C. Circuit”). We believe that a ruling will be issued by summer 2014. We are unable to predict the outcome of the various challenges to MATS.
CAIR and Multi-Pollutant Programs
Pursuant to authority granted under the CAA, the EPA promulgated the Clean Air Interstate Rule, or CAIR, regulations in March 2005, applicable to 28 eastern states and the District of Columbia, to facilitate attainment of its ozone and fine particulates 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. 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. As a result of an EPA petition for rehearing, on December 23, 2008, the court left CAIR intact but remanded it to the EPA for further proceedings consistent with the July 11, 2008 opinion. As a result, CAIR went into effect on January 1, 2009, for many of our power plants located throughout the eastern and central U.S. Due to the low-emitting nature of our fleet, the net financial impact of this program to us is neutral to marginally positive.
Cross-State Air Pollution Rule
On July 6, 2011, the EPA finalized the Cross-State Air Pollution Rule (“CSAPR”) as the replacement program for CAIR. CSAPR would require a total of 28 primarily eastern states, to reduce annual SO2 emissions, annual NOx emissions and/or ozone seasonal NOx emissions 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.
As with MATS, CSAPR was extensively challenged through both administrative and judicial processes. As a result of one of these challenges, on August 21, 2012, the D.C. Circuit vacated CSAPR, and ordered the EPA to continue administering CAIR. The U.S. Supreme Court heard the case on December 10, 2013 after granting certiorari. We cannot predict the outcome of this case. A decision is expected during summer of 2014. In the event that the D.C. Circuit decision is upheld, the EPA must continue to implement CAIR while it creates a replacement for CSAPR.

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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”, 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 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 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 to correspond to the effective date of the Tailpipe Rule. In the Tailoring Rule, the EPA departed from the CAA’s 100/250 tpy emissions thresholds and provided that only sources with emissions exceeding 75,000 or 100,000 tpy carbon dioxide equivalent, depending on the program and project, would initially be subject to GHG permitting.
The EPA has issued guidance to permitting authorities on the implementation of GHG best available control technology (“BACT”) that focuses on energy efficiency. Our Russell City Energy Center, a 619 MW combined-cycle power plant (our 75% net interest is 464 MW) in Hayward, California, voluntarily accepted GHG BACT limits in its PSD permit before such limits were required by law. Our Deer Park and Channel Energy Center expansions in Texas and our Garrison Energy Center in Delaware were all subject to PSD review for GHG emissions and were issued permits using unit efficiency as the basis for BACT. Based on this experience, for the foreseeable future, we expect that our efficient power plants will be found to meet BACT for GHGs where required to undergo PSD review. Accordingly, and taking into consideration the highly efficient nature of our fleet, we believe that the impact of EPA’s GHG permitting rules will be neutral or marginally beneficial to us.
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 upheld all of the challenged GHG regulations. After D.C. Circuit appeals were denied, on October 15, 2013, the U.S. Supreme Court granted petitions for certiorari to review Coalition for Responsible Regulation, but only for consideration of one limited issue. Due to the narrowness of the question before the Court, this case does not appear to call into question the EPA’s endangerment determination or the legal basis for regulating GHGs under the CAA, as confirmed by the Supreme Court in Massachusetts v. EPA. We expect that a ruling will be issued by summer 2014. We cannot predict the outcome of the Supreme Court’s review or its implications on the EPA’s GHG regulations or our operations at this time.
On June 25, 2013, President Obama announced a Climate Action Plan aimed at reducing GHG emissions in the U.S. to 17 percent below 2005 levels by 2020, and at the same time instructed the EPA to develop and implement (1) New Source Performance Standards (“NSPS”) for GHG emissions from new electric generating units and (2) GHG emissions guidelines for existing power plants. In April 2012, the EPA had previously proposed a power sector NSPS of 1,000 lbs CO2 per Megawatt-hour (“lb CO2/MWh”) for new fossil fuel-fired generating units, including boilers, integrated gasification combined-cycle units and stationary combined-cycle turbine units greater than 25 MW, irrespective of fuel type and generating technology. The President’s memorandum directed the EPA to re-propose the new source rule by September 20, 2013. Next, the EPA is directed to propose a rule for modified, reconstructed and existing power plants by June 1, 2014. Finally, the EPA is directed to promulgate a final existing source rule no later than June 1, 2015. The memorandum also directs the EPA to require states to submit their implementation plans for the existing source role to the EPA by June 30, 2016.
On September 20, 2013, the EPA re-proposed the power sector GHG NSPS. The re-proposed rule, while similar to the original proposal in some respects, contains different emission standards for different generating technologies. Specifically, large combined-cycle turbines are subject to a standard of 1,000 lb CO2/MWh, small combined-cycle turbines are subject to a standard of 1,050 lb CO2/MWh, and traditional boiler-based power generation facilities are subject to a standard of 1,100 lb CO2/MWh. The standards for combined-cycle turbines are based on the EPA’s determination of what is achievable using natural gas combined-cycle technology. The standards for boiler-based units are based on the EPA’s determination of what is achievable from new coal-fired utility steam generating units utilizing partial carbon capture and storage technology. The proposed standards effectively exempt most simple-cycle turbines operated as peaking units. We expect no negative impact on Calpine’s fleet or development plans if the 2013 NSPS is finalized as proposed.

It is unclear what form the EPA’s rule for regulating the GHG emissions from existing power plants will take. Accordingly, we cannot predict how the existing source rules for GHG emissions will regulate power plants and, thereby, the impact of this rule

23



on Calpine is unknown. However, we believe that we operate one of the cleanest fleets of power plants in the U.S. and anticipate that we will be well positioned to comply with any such standards.
Demand Response Resources
On January 30, 2013, the EPA finalized amendments to the NESHAP for Reciprocating Internal Combustion Engines (“RICE”). The final rule creates an exemption from otherwise applicable air emission requirements for uncontrolled “emergency” diesel-fired backup generators to operate for up to 100 hours per year for “emergency demand response” and up to 50 hours per year in certain non-emergency situations as part of a financial arrangement with another entity.
On March 29, 2013, Calpine and PSEG Power LLC filed a petition for reconsideration with the EPA objecting to the final rule because it allows the increased use of uncontrolled, behind-the-meter diesel engines for the generation of electricity during periods of peak demand and, thereby, will cause an increase in ozone during the peak ozone season. Additionally, on April 1, 2013, Calpine, First Energy Solutions Corporation and PSEG Power LLC filed a petition for review of the final rule with the D.C. Circuit.
On June 28, 2013, the EPA granted partial reconsideration of the NESHAP for RICE, including the final rule’s provisions allowing uncontrolled diesel engines to operate for up to 50 hours per year in non-emergency situations as part of a financial arrangement. Administrative and judicial challenges continue and we cannot predict the outcome of this litigation.
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 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. The relevant agencies in both states issued regulations in 2012 and 2013 to address Section 185 fee collection. The EPA approval of the TCEQ regulation is pending. Our analysis of the final regulations indicates that we will have no fee obligation in either state.
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 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.
In both of these programs, a cap is established defining the maximum allowable emissions of GHGs emitted by sources subject to the program. Affected sources are required to hold one allowance for each ton of CO2 emitted (and, in the case of California’s program, other GHGs) during the applicable compliance period. Both programs also contain provisions for the use of qualified offsets in lieu of allowances. Allowances are distributed through auctions or through allocations to affected companies. In addition, there are functional secondary markets for allowances. We obtain allowances in a variety of ways, including participation in auctions, as part of power purchase agreements, and through bilateral or exchange transactions.
California: GHG — Cap-and-Trade Regulation
California’s AB 32 requires the state to reduce statewide GHG emissions to 1990 levels by 2020. To meet this benchmark, the CARB has promulgated a number of regulations, including the Cap-and-Trade Regulation and Mandatory Reporting Rule, which took effect on January 1, 2012. These regulations were further amended by the CARB in 2012.

24



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 and surrender 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 GHG emissions market is currently functioning and the cost of allowances is reflected in market pricing.
The California Cap-and-trade program has been challenged through administrative and judicial processes at both federal and state levels. Thus far, none of these challenges has been successful. We cannot predict the ultimate success of any of these lawsuits nor can we predict whether there will be any additional legal challenges filed against the Cap-and-Trade Regulation or what the associated impacts of any such litigation would be.
On April 19, 2013, the CARB Board approved amendments to the Cap-and-Trade Regulation to link its program with Quebec’s Cap-and-trade program starting January 1, 2014. While the linkage is currently effective, joint auctions of GHG allowances are not expected to occur until later in 2014. The 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%.
On September 4, 2013, the CARB proposed regulatory amendments to, among other things, provide allowances through 2017 to covered entities that have long-term contracts that do not allow the costs of compliance with the Cap-and-Trade Regulation to be passed through to their industrial host customers. If ultimately implemented in a form similar to the proposal, these amendments are expected to result in a modest benefit to us. The proposed amendments are likely to go into effect in late 2014.
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 well positioned to comply with the Cap-and-Trade Regulation.
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.
We receive 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.
Consistent with the original memorandum of understanding under which the states created RGGI, the overall success of the RGGI program was reviewed in 2012. This program review led to a number of changes, most significant of which was a reduction of the aggregate RGGI cap downward from 165 million tons to 91 million tons, slightly less than RGGI-wide emissions in 2012. 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 we plan to retire our 158 MW Deepwater Energy Center before the commencement of the PJM 2014/2015 delivery year and our 68 MW Cedar Energy Center, 60 MW Missouri Avenue Energy Center, and 77 MW Middle Energy Center before the commencement of the PJM 2015/2016 delivery year. In the event certain 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. 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.

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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 certain 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. 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 but may also have adverse effects on wholesale electricity prices.
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 wastewater and the use of water, but can also include wetlands protection and preservation, protection of 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.
Clean Water Act and Cooling Water Intake Structure 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 spill prevention control and countermeasure plans for some of our power plants. We believe that we are in 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 under Section 316(b) in 2001, which applies to new facilities. The EPA initially promulgated the Phase II Rule, applying to large

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existing facilities, in 2004. Finally, the EPA finalized the Phase III Rule in 2006, which covers certain existing facilities and new offshore and coastal oil and gas extraction facilities.
However, in response to the Second Circuit Court of Appeals’ decision in Riverkeeper, Inc., v. EPA, the EPA suspended the Phase II Rule. In November 2010, the EPA signed a settlement agreement with Riverkeeper, Inc. requiring the EPA to set technology standards for cooling water intake structures for existing facilities. The deadline for these final rules has been extended numerous times, and is currently in the process of being extended again until some time in 2014. 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 will be retired in May 2014.
Additionally, the EPA issued a proposed rule regarding effluent limitation guidelines and standards for the steam electric power generating point source category on June 7, 2013. The EPA is bound by a court-ordered consent decree to issue a final rule by May 22, 2014, although in January 2014, the EPA sought an extension to this deadline. This rule is not expected 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”). The SWRCB has promulgated its own once-through cooling policy that establishes a schedule for once-through cooling units to install closed-cycle wet cooling (i.e., 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 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 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.
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

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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. In general, these state law-related claims have been unsuccessful in assigning tort liability for GHG emissions to power generators. We cannot predict the outcomes of these cases or what impact such cases, if successful, 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.
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 subsidiaries would be subject to the books and records access requirement.
FERC has civil penalty authority over violations of any provision of Part II of the FPA, as well as any rule or order issued thereunder. FERC is authorized to assess a maximum civil penalty of $1 million per violation for each day that the violation continues. The FPA also provides for the assessment of criminal fines and imprisonment for violations under Part II of the FPA. This penalty authority was enhanced in EPAct 2005. With this expanded enforcement authority, violations of the FPA and FERC’s regulations could potentially have more serious consequences than in the past.
Pursuant to EPAct 2005, NERC has been certified by FERC as the Electric Reliability Organization to develop and oversee the enforcement of electric system reliability standards applicable throughout the U.S., which are subject to FERC review and approval. FERC-approved reliability standards may be enforced by FERC independently, or, alternatively, by NERC and the regional reliability organizations with frontline responsibility for auditing, investigating and otherwise ensuring compliance with reliability standards, subject to FERC oversight. Monetary penalties of up to $1 million per day per violation may be assessed for violations of the reliability standards.
FERC’s policies and rules will continue to evolve, and FERC may amend or revise them, or may introduce new policies or rules in the future. The impact of such policies and rules on our business is uncertain and cannot be predicted at this time.

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Power Regions
The following is a brief overview of the most significant regulatory issues affecting our business in our three core markets — CAISO, ERCOT and PJM. The CAISO, ERCOT and PJM markets are in our West, Texas and North segments, respectively.
CAISO
The majority of our power plants in our West segment are located in California, in the CAISO region. We also own one power plant in Arizona and one in Oregon.
CAISO is responsible for ensuring the safe and reliable operation of the transmission grid within the bulk of California and providing open, nondiscriminatory transmission services. CAISO maintains various markets for wholesale sales of power, differentiated by time and type of electrical service, into which our subsidiaries may sell power from time to time. These markets are subject to various controls, such as price caps and mitigation of bids when transmission constraints arise. The controls and the markets themselves are subject to regulatory change at any time.
The CPUC and CAISO continue to evaluate capacity procurement policies and products for the California power market. With the expectation of significant increases in renewables, both entities are evaluating the need for operational flexibility attributes including the ability to start and ramp quickly as well as the ability to operate efficiently at low output levels or cycle off. We are an active participant in these discussions and support products and policies that would provide appropriate compensation for the required attributes. As these proceedings are ongoing, we cannot predict the ultimate impact on our financial condition, results of operations or cash flows, though we believe our fleet offers many features that can and do provide operational flexibility to the power markets.
ERCOT
ERCOT is the ISO that manages approximately 85% of Texas’ load and an electric grid covering about 75% of the state, overseeing transactions associated with Texas’ competitive wholesale and retail power markets. FERC does not regulate wholesale sales of power in ERCOT. The PUCT exercises regulatory jurisdiction over the rates and services of any electric utility conducting business within Texas. Our subsidiaries that own power plants in Texas have power generation company status at the PUCT, and are either EWGs or QFs and are exempt from PUCT rate regulation. ERCOT ensures resource adequacy through an energy-only model. In ERCOT, there is a market price cap for energy and capacity purchased by ERCOT. Under certain market conditions, the offer cap could be lower. Our subsidiaries are subject to the offer cap rules, but only for sales of power and capacity services to ERCOT.
The PUCT is considering changes regarding its approach to resource adequacy, including a centralized forward capacity market, but the timing of any major change remains uncertain. The need for change is prompted by uncertainty over whether sufficient generation will be available to reliably meet ERCOT’s expected future demand growth, particularly during periods of high demand. The PUCT is attempting to address this issue with an increase in the system-wide offer cap to $7,000/MWh and implementing an operating reserve demand curve, which produces a price “adder” to the clearing price of energy. Both changes are effective on June 1, 2014. We support the development of a centralized forward capacity market to ensure ERCOT meets its reliability objective under almost any market conditions. As these proceedings are ongoing, we cannot predict the ultimate impact on our financial condition, results of operations or cash flows.
PJM
PJM operates wholesale power markets, a locationally based capacity market, a forward capacity market and ancillary service markets. PJM also performs transmission planning for the region. The rules and regulations affecting PJM power markets and transmission are subject to change at any time.
Certain states in the PJM market region, particularly New Jersey and Maryland, have taken anticompetitive actions that could have an adverse impact on the deregulated PJM power market by discouraging the construction of new generation. We are actively participating in the judicial process challenging these actions at the state and federal level. We believe the current competitive construct of the PJM power market whereby new construction of power generation facilities is determined by forward price signals and not ratepayer guaranteed rate recovery is the most efficient mechanism for incentivizing the construction of new power plants. As these judicial proceeding are ongoing, we cannot predict the ultimate impact on our financial condition, results of operations or cash flows.
PJM has submitted to the FERC for approval of new refinements to increase the effectiveness of the Reliability Pricing Model. We support these actions and believe that they generally enhance the competitiveness of the PJM power market; however, we cannot predict whether the FERC will approve these changes, what their ultimate impact may be, nor the impact on our financial condition, results of operations or cash flows.

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Other State Regulation of Power
State Public Utility Commissions, or PUC(s), have historically had broad authority to regulate both the rates charged by, and the financial activities of, electric utilities operating in their states and to promulgate regulation for implementation of PURPA. Since all of our affiliates are either QFs or EWGs, none of our affiliates are currently subject to direct rate regulation by a state PUC. However, states may assert jurisdiction over the siting and construction of power generating facilities including QFs and EWGs and, with the exception of QFs, over the issuance of securities and the sale or other transfer of assets by these facilities.
State PUCs also maintain extensive control over the procurement of wholesale power by the utilities that they regulate. Many of these utilities are our customers, and agreements between us and these counterparties often require approval by state PUCs.
Regulation of Transportation and Sale of Natural Gas
Since the majority of our power generating capacity is derived from natural gas-fired power plants, we are broadly impacted by federal regulation of natural gas transportation and sales. Furthermore, one of our natural gas transportation pipelines in Texas is subject to dual jurisdiction by the FERC and the Texas Railroad Commission. This pipeline is an intrastate pipeline within the meaning of Section 2(16) of the Natural Gas Policy Act (“NGPA”). FERC regulates the rates charged by this pipeline for transportation services performed under Section 311 of the NGPA, and the Texas Railroad Commission regulates the rates and services provided by this pipeline as a gas utility in Texas.
We also operate a proprietary pipeline system in California, which is regulated by the U.S. Department of Transportation and the Pipeline and Hazardous Materials Safety Administration with regard to safety matters. Additionally, some of our power plants own and operate short pipeline laterals that connect the natural gas-fired power plants to the North American natural gas grid. Some of these laterals are subject to state and/or federal safety regulations.
The FERC has civil penalty authority for violations of the Natural Gas Act (“NGA”) and NGPA, as well as any rule or order issued thereunder. The FERC’s regulations specifically prohibit the manipulation of the natural gas markets by making it unlawful for any entity in connection with the purchase or sale of natural gas, or the purchase or sale of transportation service under the FERC’s jurisdiction, to engage in fraudulent or deceptive practices. Similar to its penalty authority under the FPA described above, the FERC is authorized to assess a maximum civil penalty of $1 million per violation for each day that the violation continues. The NGA and NGPA also provide for the assessment of criminal fines and imprisonment time for violations.
Federal Regulation of Futures and Other Derivatives
CFTC Regulation of Futures Transactions
The CFTC has regulatory oversight of the futures markets, including trading on NYMEX for energy, and licensed futures professionals such as brokers, clearing members and large traders. In connection with its oversight of the futures markets and NYMEX, the CFTC regularly investigates market irregularities and potential manipulation of those markets. Recent laws also give the CFTC certain powers with respect to broker-type markets referred to as “exempt commercial markets” or ECMs, including the Intercontinental Exchange. The CFTC monitors activities in the OTC, ECM and physical markets that may be undertaken for the purpose of influencing futures prices. With respect to ECMs, the CFTC exercises only light-handed regulation primarily related to trade reporting, price dissemination and record retention (including retention of fraudulent claims and allegations).
The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
CFTC Regulation of Derivatives Transactions
The Dodd-Frank Act, which was signed into law on July 21, 2010, contains a variety of provisions designed to regulate financial markets, including credit and derivatives transactions. Title VII of the Dodd-Frank Act addresses regulatory reform of the OTC derivatives market in the U.S. and significantly changes the regulatory framework of this market. Certain Title VII regulations have been finalized and are effective though some regulations remain subject to a delayed compliance schedule. Other key regulations have not been finalized as of this time or remain in draft form. Until all of these regulations have been finalized, the extent to which the provisions of Title VII might affect our derivatives activities cannot be completely known.
While we are closely monitoring this rulemaking process from the CFTC (including related no-action relief, interpretations and orders), we have reviewed and assessed the impact of the CFTC’s Title VII regulations on our business and related processes, and we have adjusted our internal procedures where necessary to comply with the applicable statutory law and related Title VII regulations which are effective at this time. We will continue to monitor all relevant developments and rulemaking initiatives, and we expect to successfully implement any new applicable requirements. At this time, we cannot predict the impact or possible

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additional costs to us related to the implementation of, or compliance with, the potential future requirements under the Dodd-Frank Act.
EMPLOYEES
At December 31, 2013, we employed 2,157 full-time employees, of whom 149 were represented by collective bargaining agreements, none of which expire within one year. We have never experienced a work stoppage or strike.
Item 1A.
Risk Factors
Commercial Operations
Our financial performance is impacted by price fluctuations in the wholesale power and natural gas markets and other market factors that are beyond our control.
Market prices for power, generation capacity, ancillary services, natural gas and fuel oil are unpredictable and fluctuate substantially. Unlike most other commodities, power can only be stored on a very limited basis and generally must be produced concurrently with its use. As a result, power prices are subject to significant volatility due to supply and demand imbalances, especially in the day-ahead and spot markets. Long- and short-term power and natural gas prices may also fluctuate substantially due to other factors outside of our control, including:
increases and decreases in generation capacity in our markets, including the addition of new supplies of power as a result of the development of new power plants, expansion of existing power plants or additional transmission capacity;
changes in power transmission or fuel transportation capacity constraints or inefficiencies;
power supply disruptions, including power plant outages and transmission disruptions;
Heat Rate risk;
weather conditions, particularly unusually mild summers or warm winters in our market areas;
quarterly and seasonal fluctuations;
changes in commodity prices and the supply of commodities, including but not limited to coal, natural gas and fuel oil;
changes in the demand for power or in patterns of power usage, including the potential development of demand-side management tools and practices;
development of new fuels or new technologies for the production or storage of power;
federal and state regulations and actions of the ISOs;
federal and state power, market and environmental regulation and legislation, including mandating an RPS or creating financial incentives, each resulting in new renewable energy generation capacity creating oversupply;
changes in prices related to RECs; and
changes in capacity prices and capacity markets.
These factors have caused our operating results to fluctuate in the past and will continue to cause them to do so in the future.
Our revenues and results of operations depend on market rules, regulation and other forces beyond our control.
Our revenues and results of operations are influenced by factors that are beyond our control, including:
rate caps, price limitations and bidding rules imposed by ISOs, RTOs and other market regulators that may impair our ability to recover our costs and limit our return on our capital investments;
regulations promulgated by the FERC and the CFTC;
sufficient liquidity in the forward commodity markets to conduct our hedging activities;
some of our competitors (mainly utilities) receive entitlement-guaranteed rates of return on their capital investments, with returns that exceed market returns and may impact our ability to sell our power at economical rates;
structure and operating characteristics of our capacity markets such as our PJM capacity auctions and our NYISO markets; and

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regulations and market rules related to our RECs.
Accounting for our hedging activities may increase the volatility in our quarterly and annual financial results.
We engage in commodity-related marketing and price-risk management activities in order to economically hedge our exposure to market risk with respect to power sales from our power plants, fuel utilized by those assets and emission allowances. We generally attempt to balance our fixed-price physical and financial purchases, and sales commitments in terms of contract volumes and the timing of performance and delivery obligations through the use of financial and physical derivative contracts. These derivatives are accounted for under U.S. GAAP, which requires us to record all derivatives on the balance sheet at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. As a result, we are unable to accurately predict the impact that our risk management decisions may have on our quarterly and annual financial results.
The use of hedging agreements may not work as planned or fully protect us and could result in financial losses.
We typically enter into hedging agreements, including contracts to purchase or sell commodities at future dates and at fixed prices, in order to manage our commodity price risks. These activities, although intended to mitigate price volatility, expose us to other risks. When we sell power forward, we may be required to post significant amounts of cash collateral or other credit support to our counterparties, and we give up the opportunity to sell power at higher prices if spot prices are higher in the future. Further, if the values of the financial contracts change in a manner that we do not anticipate, or if a counterparty fails to perform under a contract, it could harm our financial condition, results of operations and cash flows.
We do not typically hedge the entire exposure of our operations against commodity price volatility. To the extent we do not hedge against commodity price volatility, our financial condition, results of operations and cash flows may be diminished based upon adverse movement in commodity prices.
Our ability to enter into hedging agreements and manage our counterparty credit risk could adversely affect us.
Our customer and supplier counterparties may experience deteriorating credit. These conditions could cause counterparties in the natural gas and power markets, particularly in the energy commodity derivative markets that we rely on for our hedging activities, to withdraw from participation in those markets. If multiple parties withdraw from those markets, market liquidity may be threatened, which in turn could adversely impact our business and create more volatility in our earnings. Additionally, these conditions may cause our counterparties to seek bankruptcy protection under Chapter 11 or liquidation under Chapter 7 of the Bankruptcy Code. Our credit risk may be exacerbated to the extent collateral held by us cannot be realized or is liquidated at prices not sufficient to recover the full amount of the exposure due to us. There can be no assurance that any such losses or impairments to the carrying value of our financial assets would not materially and adversely affect our financial condition, results of operations and cash flows.
Competition could adversely affect our performance.
The power generation industry is characterized by intense competition, and we encounter competition from utilities, industrial companies, marketing and trading companies and other independent power producers. In addition, many states are implementing or considering regulatory initiatives designed to increase competition in the domestic power industry. This competition has put pressure on power utilities to lower their costs, including the cost of purchased power, and increasing competition in the supply of power in the future could increase this pressure. In addition, construction during the last decade has created excess power supply and higher reserve margins in the power trading markets, putting downward pressure on prices.
In certain situations, our PPAs and other contractual arrangements, including construction agreements, commodity contracts, maintenance agreements and other arrangements, may be terminated by the counterparty and/or may allow the counterparty to seek liquidated damages.
The situations that could allow a counterparty to terminate the contract and/or seek liquidated damages include:
the cessation or abandonment of the development, construction, maintenance or operation of a power plant;
failure of a power plant to achieve construction milestones or commercial operation by agreed-upon deadlines;
failure of a power plant to achieve certain output or efficiency minimums;
our failure to make any of the payments owed to the counterparty or to establish, maintain, restore, extend the term of or increase any required collateral;
failure of a power plant to obtain material permits and regulatory approvals by agreed-upon deadlines;

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a material breach of a representation or warranty or our failure to observe, comply with or perform any other material obligation under the contract; or
events of liquidation, dissolution, insolvency or bankruptcy.
Revenue may be reduced significantly upon expiration or termination of our PPAs.
Some of the capacity from our existing portfolio is sold under long-term PPAs that expire at various times. We seek to sell any capacity not sold under long-term PPAs, on a short-term basis as market opportunities arise. Our non-contracted capacity is generally sold on the spot market at current market prices as merchant energy. When the terms of each of our various PPAs expire, it is possible that the price paid to us for the generation of power under subsequent arrangements or in short term markets may be significantly less than the price that had been paid to us under the PPA. Power plants without long-term PPAs involve risk and uncertainty in forecasting future demand load for merchant sales because they are exposed to market fluctuations for some or all of their generating capacity and output. A significant under- or over-estimation of load requirements may increase our operating costs. Without the benefit of long-term PPAs, we may not be able to sell any or all of the capacity from these power plants at commercially attractive rates and these power plants may not be able to operate profitably. Certain of our PPAs have values in excess of current market prices. We are at risk of loss of margins to the extent that these contracts expire or are terminated and we are unable to replace them on comparable terms. Additionally, our PPAs contain termination provisions standard to contracts in our industry such as negligence, performance default or prolonged events of force majeure.
The introduction or expansion of competing technologies for power generation and demand-side management tools could adversely affect our performance.
The power generation business has seen a substantial change in the technologies used to produce power. With federal and state incentives for the development and production of renewable sources of power, we have seen market penetration of competing technologies, such as wind, solar, and commercial-sized power storage. Additionally, the development of demand-side management tools and practices can impact peak demand requirements for some of our markets at certain times during the year. The continued development of subsidized, competing power generation technologies and significant development of demand-side management tools and practices could alter the market and price structure for power and negatively impact our financial condition, results of operations and cash flows.
An economic downturn could result in a reduction in our revenue and operating cash flows or result in our customers, counterparties, vendors or other service providers failing to perform under their contracts with us.
To the extent that an economic downturn returns and affects the markets in which we operate, demand for power and power prices may be depressed, and our revenues and operating cash flows could be negatively impacted. In addition, challenges affecting the economy could cause our customers, counterparties, vendors and service providers to experience