10-K 1 cpn_10kx12312014.htm CALPINE 10-K FOR YEAR-ENDED DECEMBER 31, 2014 CPN_10K_12.31.2014


 
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, 2014
 
 
[    ]
 
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
Name of each exchange on which registered:
New York Stock Exchange
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, 2014, the last business day of the registrant’s most recently completed second fiscal quarter: approximately $9,891 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: 376,193,256 shares of common stock, par value $0.001, were outstanding as of February 11, 2015.

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 2015 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, 2014
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, 2014, 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 7.5% 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
 
 
 
2023 Senior Unsecured Notes
 
The $1.25 billion aggregate principal amount of 5.375% senior unsecured notes due 2023, issued July 22, 2014
 
 
 
2024 First Lien Notes
 
The $490 million aggregate principal amount of 5.875% senior secured notes due 2024, issued October 31, 2013
 
 
 
2024 Senior Unsecured Notes
 
The $650 million aggregate principal amount of 5.5% senior unsecured notes due 2024, issued February 3, 2015
 
 
 
2025 Senior Unsecured Notes
 
The $1.55 billion aggregate principal amount of 5.75% senior unsecured notes due 2025, issued July 22, 2014
 
 
 
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) 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 agreements and (l) other extraordinary, unusual or non-recurring items
 
 
 

ii



ABBREVIATION
 
DEFINITION
AOCI
 
Accumulated Other Comprehensive Income
 
 
 
Average availability
 
Represents the total hours during the period that our plants were in-service or available for service as a percentage of the total hours in the period
 
 
 
Average capacity factor, excluding peakers
 
A measure of total actual power generation as a percent of total potential power 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
 
 
 
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 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 Corp.
 
 
 
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, and the $425 million first lien senior secured term loan entered into on February 26, 2014, 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
 
 
 
CFTC
 
U.S. Commodities Futures Trading Commission
 
 
 
Chapter 11
 
Chapter 11 of the U.S. Bankruptcy Code
 
 
 
CO2
 
Carbon dioxide
 
 
 
COD
 
Commercial operations date
 
 
 

iii



ABBREVIATION
 
DEFINITION
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 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, optimization and trading activities including natural gas transactions hedging future power sales, but excludes 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, optimization and trading activities, but excludes our mark-to-market activity
 
 
 
Company
 
Calpine Corporation, a Delaware corporation, and its subsidiaries
 
 
 
Corporate Revolving Facility
 
The $1.5 billion aggregate amount revolving credit facility credit agreement, dated as of December 10, 2010, as amended on June 27, 2013 and July 30, 2014, 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
 
 
 
CSAPR
 
Cross-State Air Pollution Rule
 
 
 
D.C. Circuit
 
U.S. Court of Appeals for the District of Columbia Circuit
 
 
 
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
 
 
 
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
 
 
 

iv



ABBREVIATION
 
DEFINITION
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 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.
 
 
 
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)
 
 
 
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
Hg
 
Mercury
 
 
 
IRC
 
Internal Revenue Code
 
 
 
IRS
 
U.S. Internal Revenue Service
 
 
 
ISO(s)
 
Independent System Operator(s)
 
 
 
ISO-NE
 
ISO New England
 
 
 
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
 
 
 
LTSA(s)
 
Long-Term Service Agreement(s)
 
 
 
Market Heat Rate(s)
 
The regional power price divided by the corresponding regional natural gas price
 
 
 
MATS
 
Mercury and Air Toxics Standard
 
 
 
MISO
 
Midwest ISO
 
 
 
MMBtu
 
Million Btu
 
 
 
MRO
 
Midwest Reliability Organization
 
 
 

v



ABBREVIATION
 
DEFINITION
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
 
 
 
NERC
 
North American Electric Reliability Council
 
 
 
NOL(s)
 
Net operating loss(es)
 
 
 
NOx
 
Nitrogen oxides
 
 
 
NPCC
 
Northeast Power Coordinating Council
 
 
 
NYISO
 
New York ISO
 
 
 
NYMEX
 
New York Mercantile Exchange
 
 
 
NYSE
 
New York Stock Exchange
 
 
 
OCI
 
Other Comprehensive Income
 
 
 
OMEC
 
Otay Mesa Energy Center, LLC, 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
 
 
 
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
 
 
 
PSD
 
Prevention of Significant Deterioration
 
 
 
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, 2014, filed with the SEC on February 13, 2015

vi



ABBREVIATION
 
DEFINITION
 
 
 
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
 
 
 
RMR Contract(s)
 
Reliability Must Run contract(s)
 
 
 
RPS
 
Renewable Portfolio Standards
 
 
 
RTO(s)
 
Regional Transmission Organization(s)
 
 
 
SEC
 
U.S. Securities and Exchange Commission
 
 
 
Securities Act
 
U.S. Securities Act of 1933, as amended
 
 
 
Senior Unsecured Notes
 
Collectively, the 2023 Senior Unsecured Notes, the 2024 Senior Unsecured Notes and the 2025 Senior Unsecured Notes
 
 
 
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 natural gas to produce it
 
 
 
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. 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


vii



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 and extent to which we hedge risks;
Laws, regulations 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, access the capital markets when necessary and to comply with covenants under our First Lien Notes, Senior Unsecured 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 water 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;
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 (such as distributed generation, power storage and other technologies);
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 that may arise from noncompliance with market rules promulgated by the SEC, CFTC, FERC and other regulatory bodies; 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 88 power plants, including one under construction, located in competitive wholesale power markets primarily in 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, while prudently managing our balance sheet.
Our capital allocation philosophy seeks to maximize levered cash returns to equity on a per share basis. We currently consider the repurchases of our own shares of common stock as an attractive investment opportunity, and we utilize the expected returns from this investment as the benchmark against which we evaluate all other capital allocation decisions. We believe this philosophy closely aligns our objectives with those of our shareholders.
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 (included in our West segment), Texas (included in our Texas segment) and the Northeast region(included in our East segment) 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 15% of all renewable energy in the state of California during 2013.
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 primarily natural gas and some fuel oil as fuel for our power plants and engage in related natural gas transportation and storage transactions. We purchase electric transmission rights to deliver power to our customers. Additionally, consistent with our Risk Management Policy, we enter into natural gas, power and other physical and financial contracts to hedge certain business risks and optimize our portfolio of power plants.
Our portfolio, including partnership interests, consists of 88 power plants, including one under construction, located throughout 18 states in the U.S. and in Canada, with an aggregate generation capacity of 26,548 MW and 309 MW under construction. Our fleet, including projects under construction, consists of 71 natural gas-fired combustion turbine-based plants, one fuel oil-fired steam-based plant, 15 geothermal steam turbine-based plants and one photovoltaic solar plant. In 2014, our fleet of power plants produced approximately 103 billion KWh of electric power for our customers. In addition, we are one of the largest consumers of natural gas in North America. In 2014, we consumed 793 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 natural gas from shale 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, we believe our power plants will be 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 capital necessary to develop a power generation portfolio that has substantially lower air emissions compared to our major competitors’ power plants that use 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 cleaner 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

3



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 existing and potential legislation or regulation addressing GHG or other emissions, water use or waste disposal, compared to our competitors who use other fossil fuels or older, less efficient technologies.
Our scale provides the opportunity to have meaningful regulatory input, 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 policy-makers 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 following five major initiatives listed below and subsequently described in further detail:
Focus on remaining a premier operating company;
Focus on managing and growing our portfolio;
Focus on our customer-oriented origination business;
Focus on advocacy and corporate responsibility; all of which culminate in
Focus on enhancing shareholder value.
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.
During 2014, our employees achieved a lost time incident rate of 0.08 lost time injuries per 100 employees which places us in the first quartile performance for power generation companies with 1,000 or more employees.
Our entire fleet achieved a forced outage factor of 1.9% and a starting reliability of 98.6% during the year ended December 31, 2014.
During 2014, our outage services subsidiary completed 14 major inspections and nine hot gas path inspections.
For the past 14 consecutive years, our Geysers Assets have reliably generated approximately six million MWh of renewable power per year.
2.
Focus on Managing and Growing our Portfolio — Our goal is to continue to grow our 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 actively seek to divest non-core assets where we can find opportunities to do so accretively. In addition, we believe that modernizations and expansions of our current assets offer proven and financially disciplined opportunities to improve our operations, capacity and efficiencies. During 2014, we strategically repositioned our portfolio by divesting positions in non-core markets and adding capacity in our core regions through the following transactions:
On February 26, 2014, we completed the purchase of a modern, natural gas-fired, combined-cycle power plant with a nameplate capacity of 1,050 MW located in Guadalupe County, Texas for approximately $625 million, excluding working capital adjustments, which increased capacity in our Texas segment. We also paid $15 million to acquire rights to an advanced development opportunity for an approximately 400 MW quick-start, natural gas-fired peaker plant. Development efforts are ongoing and we are continuing to advance entitlements (such as permits, zoning and transmission).

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In June 2014, we completed construction to expand the baseload capacity of our Deer Park and Channel Energy Centers by approximately 260 MW each. Each power plant featured an oversized steam turbine that, along with existing plant infrastructure, allowed us to add capacity and improve the power plant’s overall efficiency at a meaningful discount to the market cost of building new capacity.
On July 3, 2014, we completed the sale of six of our power plants in our East segment for a purchase price of approximately $1.57 billion in cash, excluding working capital and other adjustments. The divestiture of these power plants has better aligned our asset base with our strategic focus on competitive wholesale markets.
On November 7, 2014, we completed the purchase of Fore River Energy Center, a power plant with a nameplate capacity of 809 MW, for approximately $530 million, excluding working capital adjustments. The addition of this modern, efficient, natural gas-fired, combined-cycle power plant located in North Weymouth, Massachusetts, increased capacity in our East segment, specifically in the constrained New England market.
During the third quarter of 2014, we executed a PPA with Duke Energy Florida, Inc. related to our Osprey Energy Center with a term of 27 months which commenced in October 2014. Subsequently, we executed an asset sale agreement during the fourth quarter of 2014 for the sale of our Osprey Energy Center to Duke Energy Florida, Inc. upon the conclusion of the PPA for approximately $166 million, excluding working capital and other adjustments. The asset sale agreement is subject to federal and state regulatory approval and represents a strategic disposition of a power plant in a wholesale power market dominated by regulated utilities.
In addition, our significant ongoing projects under construction, growth initiatives and modernizations are discussed below:
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. Once complete, the power plant will feature one combustion turbine, one heat recovery steam generator and one steam turbine. Construction commenced in April 2013, and we expect COD during the second quarter of 2015. The project’s capacity has cleared each of PJM’s three most recent base residual auctions. We are in the early stages of development of a second phase (309 MW) of this project. PJM has completed the feasibility, system impact and facilities studies for this phase. The facilities study results are being internally evaluated.
York 2 Energy Center — York 2 Energy Center is a 760 MW dual fuel combined-cycle project that will be co-located with our York Energy Center in Peach Bottom Township, Pennsylvania. Once complete, the power plant will feature two combustion turbines, two heat recovery steam generators and one steam turbine. The project’s capacity cleared PJM’s 2017/2018 base residual auction and we expect COD during the second quarter of 2017. We executed a preliminary notice to proceed for the engineering, procurement and construction agreement during the fourth quarter of 2014 and are currently pursuing key permits and approvals for the project. PJM is completing a feasibility study for increasing York 2 Energy Center’s capacity by 120 MW.
Mankato Power Plant Expansion — By order dated February 5, 2015, the Minnesota Public Utilities Commission concluded a competitive resource acquisition proceeding and selected a 345 MW expansion of our Mankato Power Plant, authorizing execution of a 20-year PPA between Calpine and Xcel Energy. Commercial operation of the expanded capacity may commence as early as June 2018, subject to applicable regulatory approvals and other contract conditions.
PJM Development Opportunities — We are currently evaluating opportunities to develop additional projects in the PJM market area that feature cost advantages such as existing infrastructure and favorable transmission queue positions. These projects are continuing to advance entitlements (such as permits, zoning and transmission) for their potential future development.
Turbine Modernization We continue to move forward with our turbine modernization program. Through December 31, 2014, we have completed the upgrade of thirteen Siemens and eight GE turbines totaling approximately 210 MW and have committed to upgrade three additional turbines. In addition, we have begun a program to update our dual-fueled turbines at certain of our power plants in our East segment.
3.
Focus on our 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 2014 is as follows:
West
We entered into a new ten-year PPA, subject to approval by the CPUC, with Southern California Edison (“SCE”) to provide 225 MW of capacity and renewable energy from our Geysers Assets commencing in June 2017.

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We entered into a new ten-year PPA with the Sonoma Clean Power Authority to provide 15 MW of renewable power from our Geysers Assets commencing in January 2017.  The capacity under contract will vary by year, increasing up to a maximum of 50 MW for years 2024 through 2026.
We entered into a new three-year resource adequacy contract with SCE for our Pastoria Energy Facility commencing in January 2016. The capacity under contract will initially be 238 MW, and will increase to 476 MW during the final year of the contract.
We entered into a new two-year resource adequacy contract with SCE for our Delta Energy Center for 500 MW of capacity commencing in January 2017.
Texas
We entered into a new six-year PPA with the City of San Marcos to provide power from our Texas power plant fleet commencing in July 2015.
We entered into a new two-year PPA with Pedernales Electric Cooperative to provide approximately 70 MW of power from our Texas power plant fleet commencing in August 2016.
We entered into a new one-year PPA with Guadalupe Valley Electric Cooperative to provide approximately 270 MW of power from our Texas power plant fleet commencing in June 2016.
East
We entered into a new five-year PPA with Dairyland Power Cooperative to provide capacity and energy from our RockGen Energy Center commencing in June 2018. The capacity under contract will initially be 135 MW, and then will increase to 235 MW for the final four years of the contract.
We entered into a new PPA with a term of 27 months with Duke Energy Florida, Inc. to provide 515 MW of power and capacity from our Osprey Energy Center, which commenced in October 2014. The capacity under contract increased to 580 MW beginning in January 2015.
4.
Focus on Advocacy and Corporate Responsibility — We recognize that our business is heavily influenced by laws, regulations and rules at federal, state and local levels as well as by ISOs and RTOs that oversee the competitive markets in which we operate. We believe that being active participants in the legislative, regulatory and rulemaking processes may yield better outcomes for all stakeholders, including Calpine. Our two basic areas of focus are environmental stewardship in power generation and competitive wholesale power markets. Below are some recent examples of our advocacy efforts:
Ensuring Competitive Market Structure/Rules
Provided leadership in stakeholder processes at PJM on a new “Capacity Performance” product and at ISO-NE on its Pay-For-Performance initiatives, resulting in pending FERC approval of the PJM Capacity Performance product and implementation of the FERC approved ISO-NE Pay-For-Performance capacity structure.
Our employees participated as invited panelists at FERC technical conferences regarding price formation and “out-of-market payments” in organized markets.
Stopping Non-Competitive/Subsidized Generation
Successfully advocated for a competitive generation supply bidding process in Florida, resulting in a contract for the acquisition of our Osprey Energy Center rather than a utility self-build as the most cost effective alternative for Florida ratepayers.
Successfully advocated for a competitive generation supply bidding process in Minnesota, resulting in an order requiring the local utility to enter into a long-term PPA for new additional capacity at our Mankato Power Plant rather than a utility self-build as the most cost effective alternative for Minnesota ratepayers.
Provided leadership in the successful legal challenges against New Jersey and Maryland for discriminatory behavior affecting FERC jurisdictional capacity auctions, resulting in decisions by the U.S. Circuit Court of Appeals for the Third and Fourth Circuits striking those state actions as violative of U.S. law.
Successfully advocated against proposed legislation in California requiring investor owned utilities to contract for 500 MW of new geothermal resources that would have discriminated against our existing geothermal fleet.
Environmental
Filed a brief with the D.C. Circuit supporting the EPA’s MATS rules which were upheld by the Court.
Filed a brief with the U.S. Supreme Court supporting the EPA’s CSAPR rules which were upheld by the Court citing our brief in its opinion.

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Filed a brief with the U.S. Supreme Court supporting the EPA’s GHG air permit rules which were upheld in part by the Court citing our brief in its opinion.
5.
Focus on Enhancing Shareholder Value — We continue to make significant progress to deliver financially disciplined growth, to enhance shareholder value through disciplined capital allocation including the return of capital to shareholders and to manage the balance sheet 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, 2014 was marked by the following accomplishments:
We delivered annual TSR of 13.4%, in line with the S&P 500 Index.
We continued to return capital to our shareholders in the form of share repurchases, having cumulatively repurchased approximately $2.4 billion or 25% of our previously outstanding shares as of the filing of this Report.
Specifically during 2014, we repurchased a total of 49.7 million shares of our outstanding common stock for approximately $1.1 billion at an average price of $22.14 per share.
In 2015, through the filing of this Report, we have repurchased a total of 5.8 million shares of our outstanding common stock for approximately $125 million at an average price of $21.68 per share.
We further optimized our capital structure by refinancing or redeeming several of our debt instruments during the year ended December 31, 2014, including the following transactions:
During the first quarter of 2014, we amended our CDHI letter of credit facility to lower our fees and extend the maturity to January 2, 2018.
On July 22, 2014, we issued $1.25 billion in aggregate principal amount of 5.375% senior unsecured notes due 2023 and $1.55 billion in aggregate principal amount of 5.75% senior unsecured notes due 2025 in a public offering. We used the proceeds to repurchase secured debt with a higher fixed interest rate.
On July 30, 2014, we amended our Corporate Revolving Facility to increase the capacity by an additional $500 million to $1.5 billion.
In December 2014, we used cash on hand to redeem 10% of the original aggregate principal amount of our 2023 First Lien Notes, plus accrued and unpaid interest.
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 $388 billion in power sales in 2014 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 legislative 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 (included in our Texas segment) and the Northeast region (included in our East 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 the Southeast 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 and 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.
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

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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 and certain Midwest regional markets to address this issue. California has a bilateral capacity program. Texas does not presently have a capacity market or 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 CSAPR 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 sales 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 rational 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 in each of our markets, 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 operating 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 some 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, energy efficiency measures and the installation of small generating facilities (such as rooftop solar) at some customer sites. 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 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:
 

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2014(1)
West:
 
WECC
29.9
%
Texas:
 
TRE
15.0
%
East:
 
NPCC
23.6
%
MISO
15.0
%
PJM
25.3
%
SERC
29.3
%
FRCC
29.0
%
___________
(1)
Data source is NERC weather-normalized estimates for 2014 published in May 2014.
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 meaningful 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 may 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 562 MW of capacity from power plants where we purchase fuel oil to meet generation requirements, but generally do not expect fuel oil requirements to be material to our portfolio of power plants. In our East segment, where the supply of natural gas can be constrained under some weather circumstances, we have approximately 6,200 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 natural 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 $2.83/MMBtu, $3.73/MMBtu, and $4.26/MMBtu during 2012, 2013 and 2014, respectively. Natural gas prices in some parts of the country for parts of 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. 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). Recent forward market natural gas prices suggest that coal-to-gas-switching could increase again during 2015 (although future market conditions are uncertain and settled prices remain to be seen).
The availability of non-conventional natural gas supplies, in particular shale natural gas, has been the primary driver of reduced natural gas prices in the last few years. Access to significant deposits of shale natural gas has altered the natural gas supply landscape in the U.S. and could have a longer-term and profound impact on both the outright price of natural gas and the historical regional natural gas price relationships (basis differentials). The U.S. Department of Energy estimates that shale natural gas production has the potential of 3 trillion to 4 trillion cubic feet per year and may be sustainable for decades with enough natural gas to supply the U.S. for the next 90 years. Despite moderate increases in natural gas prices and some significant, weather induced

9



regional price spikes last 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 (included in our Texas segment) and the Northeast (included in our East segment) where natural gas-fired units set power prices during many hours. When natural gas is the price-setting fuel (i.e. natural gas prices are above coal prices in our Texas or East segments), 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 Northeast region, we have generating units capable of burning either natural gas or fuel oil. For these units, on the rare occasions when the cost of consuming natural gas is excessively high relative to fuel oil, our unhedged Commodity Margin may increase as a result of our ability to use the lower cost fuel.
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 enhance 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.
During the second half of 2014, global oil prices declined significantly. Brent crude oil (a commonly cited global oil index) spot prices fell from a 2014 high of $115 per barrel on June 19th to a price of $55 per barrel by the end of the year (per the EIA). Since U.S. power and natural gas prices are generally not linked to oil prices, the oil market shift has not been material to our financial performance. The impact going forward will also likely not be material to our financial performance. While lower oil prices may lead to lower oil extraction and lower power demand in some parts of the U.S., such as North Dakota and Texas, lower oil prices are generally considered a boon to economic growth more broadly, which typically contributes to higher electricity demand.
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 through greater utilization of our existing power plants and development of new power plants. 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
 
9,164

MW
 
132,408

MW
Texas:
 
 
 
 
 
 
TRE
 
3,045

MW
 
85,277

MW
East:
 
 
 
 
 
 
NPCC
 
7,582

MW
 
56,770

MW
MRO
 
5,041

MW
 
46,226

MW
RFC
 
25,082

MW
 
192,534

MW
SERC
 
26,714

MW
 
232,364

MW
FRCC
 
288

MW
 
60,032

MW
Total
 
76,916

MW

805,611

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, 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.
One small but growing source of competing renewable generation in some of our regional markets (primarily California) is customer-sited (primarily rooftop) solar generation. Levelized costs for solar installation have fallen significantly over the past several years, aided by federal tax subsidies and other local incentives, and are now in some regions lower than customer retail electric rates. To the extent on-site solar generation is compensated at the full retail rate (an increasingly controversial policy known as “net energy metering”), rooftop solar installations may continue to grow. Should net energy metered solar installations remain capped at relatively low levels of penetration or net energy metering policies be weakened (by rate structure reforms that charge customers fixed amounts regardless of the level of electricity consumed, thus lowering the variable portion of the rates), rooftop solar growth might diminish. Absent incentives and supportive policies, rooftop solar is currently generally not competitive with wholesale power.
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 recently as system operators evaluate their reliability (especially at high levels of

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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. Further, the way in which demand side resources might participate in the electricity markets going forward has become less clear due to the recent FERC Order No. 745 reversal (see further discussion in “— Governmental and Regulatory Matters.”)
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:
number of market participants, both in terms of physical presence as well as contribution toward financial market liquidity;
amount of generation capacity 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, customer-sited solar generation and electricity storage devices;
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 Northeast, our natural gas-fired power plants compete directly with all other sources of power. The EIA estimates that in 2014, 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, geothermal 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.

12



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. The nuclear projects that are currently under construction in the U.S. are experiencing cost overruns and delays. 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 2014 (although power plants that were “under construction” by the end of 2014 and reach commercial operations by the end of 2016 can still secure the credits), and for solar, the investment tax credit declines significantly at the end of 2016. Unless the tax credits are extended, renewables development costs decline, 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.
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 and have only hedged our fuel oil exposure through anticipatory purchases of fuel oil inventory.
We produced approximately 103 billion KWh of electricity in 2014 across North America (primarily in the U.S.). We are one of the largest consumers of natural gas in North America having consumed approximately 793 Bcf during 2014. The three primary power markets in which we conduct our operations are California (included in our West segment), Texas (included in our Texas segment) and the Northeast (included in our East segment) which have centralized markets for which power demand and prices are determined on a spot basis (day ahead and real time). 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. 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 2015

13



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 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.
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 mark-to-market 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.

14



DESCRIPTION OF OUR POWER PLANTS
    
Geographic Diversity
Dispatch Technology
 

        

15



Power Plants in Operation at December 31, 2014
We own 88 power plants, including one under construction, with an aggregate generation capacity of 26,548 MW and 309 MW under construction.
Natural Gas-Fired Fleet
Our natural gas-fired power plants primarily utilize two types of designs: 2,431 MW of simple-cycle combustion turbines and 22,663 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 17 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 Steam Adjusted Heat Rate for 2014 for the power plants we operate was 7,384 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 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 15 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 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 generate power. For the past 14 consecutive years, our Geysers Assets have continued to generate approximately six 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 94% in 2014.
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 13 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 11 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 two 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.

16



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 107 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 2014 is:
28% related to leases with the federal government via the Office of Natural Resources Revenue (formerly, the Minerals Management Service),
27% related to leases with the California State Lands Commission, and
45% 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 five to 20 years and 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 725 MW of capacity from a power plant which has 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.

17



Table of Operating Power Plants and Projects Under Construction and Advanced Development
Set forth below is certain information regarding our operating power plants and projects under construction and advanced development at December 31, 2014.
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)
 
2014
Total MWh
Generated(4)
WEST
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Geothermal
 
 
 
 
 
 
 
 
 
 
 
 
 
 
McCabe #5 & #6
 
WECC
 
CA
 
Renewable
 
100
%
 
78

 
78

 
510,172

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

 
69

 
657,705

Calistoga
 
WECC
 
CA
 
Renewable
 
100
%
 
66

 
66

 
490,052

Eagle Rock
 
WECC
 
CA
 
Renewable
 
100
%
 
66

 
66

 
576,597

Quicksilver
 
WECC
 
CA
 
Renewable
 
100
%
 
53

 
53

 
337,155

Cobb Creek
 
WECC
 
CA
 
Renewable
 
100
%
 
52

 
52

 
447,020

Lake View
 
WECC
 
CA
 
Renewable
 
100
%
 
52

 
52

 
518,660

Sulphur Springs
 
WECC
 
CA
 
Renewable
 
100
%
 
51

 
51

 
451,161

Socrates
 
WECC
 
CA
 
Renewable
 
100
%
 
50

 
50

 
392,465

Big Geysers
 
WECC
 
CA
 
Renewable
 
100
%
 
48

 
48

 
405,556

Grant
 
WECC
 
CA
 
Renewable
 
100
%
 
43

 
43

 
295,217

Sonoma
 
WECC
 
CA
 
Renewable
 
100
%
 
42

 
42

 
318,273

West Ford Flat
 
WECC
 
CA
 
Renewable
 
100
%
 
24

 
24

 
207,226

Aidlin
 
WECC
 
CA
 
Renewable
 
100
%
 
17

 
17

 
139,692

Bear Canyon (5)
 
WECC
 
CA
 
Renewable
 
100
%
 
14

 
14

 
89,366

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

 
857

 
5,186,552

Pastoria Energy Center
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
770

 
749

 
5,096,711

Hermiston Power Project
 
WECC
 
OR
 
Combined Cycle
 
100
%
 
566

 
635

 
3,100,556

Otay Mesa Energy Center
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
513

 
608

 
3,664,180

Metcalf Energy Center
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
564

 
605

 
2,511,944

Sutter Energy Center
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
542

 
578

 
1,226,069

Los Medanos Energy Center
 
WECC
 
CA
 
Cogen
 
100
%
 
518

 
572

 
3,538,271

South Point Energy Center
 
WECC
 
AZ
 
Combined Cycle
 
100
%
 
520

 
530

 
1,103,622

Russell City Energy Center
 
WECC
 
CA
 
Combined Cycle
 
75
%
 
429

 
464

 
1,668,096

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

 
309

 
252,220

Gilroy Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
141

 
29,497

Gilroy Cogeneration Plant
 
WECC
 
CA
 
Cogen
 
100
%
 
109

 
130

 
61,370

King City Cogeneration Plant
 
WECC
 
CA
 
Cogen
 
100
%
 
120

 
120

 
514,957

Greenleaf 1 Power Plant (6)
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
50

 
50

 
17,303

Greenleaf 2 Power Plant (6)
 
WECC
 
CA
 
Cogen
 
100
%
 
49

 
49

 
246,357

Wolfskill Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
48

 
18,102

Yuba City Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
26,100

Feather River Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
23,857

Creed Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
10,810

Lambie Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
10,827

Goose Haven Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
11,225

Riverview Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
18,939

King City Peaking Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
44

 
4,914

Agnews Power Plant
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
28

 
28

 
15,794

Subtotal
 
 
 
 
 
 
 
 
 
6,581

 
7,524

 
34,194,590




18



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)
 
2014
Total MWh
Generated(4)
TEXAS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deer Park Energy Center
 
TRE
 
TX
 
Cogen
 
100
%
 
1,103

 
1,204

 
6,160,473

Guadalupe Energy Center
 
TRE
 
TX
 
Combined Cycle
 
100
%
 
1,009

 
1,000

 
4,145,500

Baytown Energy Center
 
TRE
 
TX
 
Cogen
 
100
%
 
782

 
842

 
3,286,980

Channel Energy Center
 
TRE
 
TX
 
Cogen
 
100
%
 
723

 
808

 
3,319,798

Pasadena Power Plant(7)
 
TRE
 
TX
 
Cogen/Combined Cycle
 
100
%
 
763

 
781

 
4,069,518

Bosque Energy Center
 
TRE
 
TX
 
Combined Cycle
 
100
%
 
740

 
762

 
3,732,612

Freestone Energy Center
 
TRE
 
TX
 
Combined Cycle
 
75
%
 
779

 
746

 
3,065,393

Magic Valley Generating Station
 
TRE
 
TX
 
Combined Cycle
 
100
%
 
682

 
712

 
3,737,596

Brazos Valley Power Plant
 
TRE
 
TX
 
Combined Cycle
 
100
%
 
523

 
609

 
2,417,800

Corpus Christi Energy Center
 
TRE
 
TX
 
Cogen
 
100
%
 
426

 
500

 
2,056,507

Texas City Power Plant
 
TRE
 
TX
 
Cogen
 
100
%
 
400

 
453

 
1,039,057

Clear Lake Power Plant
 
TRE
 
TX
 
Cogen
 
100
%
 
344

 
400

 
411,473

Hidalgo Energy Center
 
TRE
 
TX
 
Combined Cycle
 
78.5
%
 
392

 
374

 
1,235,508

Freeport Energy Center(8)
 
TRE
 
TX
 
Cogen
 
100
%
 
210

 
236

 
1,736,482

Subtotal
 
 
 
 
 
 
 
 
 
8,876

 
9,427

 
40,414,697

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

 
1,130

 
4,703,870

Hay Road Energy Center
 
RFC
 
DE
 
Combined Cycle
 
100
%
 
1,036

 
1,130

 
4,583,913

Morgan Energy Center
 
SERC
 
AL
 
Cogen
 
100
%
 
720

 
807

 
3,869,576

Fore River Energy Center
 
NPCC
 
MA
 
Combined Cycle
 
100
%
 
750

 
731

 
554,549

Edge Moor Energy Center
 
RFC
 
DE
 
Steam Cycle
 
100
%
 

 
725

 
854,248

Osprey Energy Center
 
FRCC
 
FL
 
Combined Cycle
 
100
%
 
537

 
599

 
1,389,851

York Energy Center
 
RFC
 
PA
 
Combined Cycle
 
100
%
 
519

 
565

 
2,537,059

Westbrook Energy Center
 
NPCC
 
ME
 
Combined Cycle
 
100
%
 
552

 
552

 
1,838,910

Greenfield Energy Centre(9)
 
NPCC
 
ON
 
Combined Cycle
 
50
%
 
422

 
519

 
759,689

RockGen Energy Center
 
MRO
 
WI
 
Simple Cycle
 
100
%
 

 
503

 
65,620

Zion Energy Center
 
RFC
 
IL
 
Simple Cycle
 
100
%
 

 
503

 
63,658

Mankato Power Plant
 
MRO
 
MN
 
Combined Cycle
 
100
%
 
280

 
375

 
355,759

Pine Bluff Energy Center
 
SERC
 
AR
 
Cogen
 
100
%
 
184

 
215

 
1,051,672

Cumberland Energy Center
 
RFC
 
NJ
 
Simple Cycle
 
100
%
 

 
191

 
116,354

Kennedy International Airport Power Plant
 
NPCC
 
NY
 
Cogen
 
100
%
 
110

 
121

 
734,258

Auburndale Peaking Energy Center
 
FRCC
 
FL
 
Simple Cycle
 
100
%
 

 
117

 
12,363

Sherman Avenue Energy Center
 
RFC
 
NJ
 
Simple Cycle
 
100
%
 

 
92

 
28,716

Bethpage Energy Center 3
 
NPCC
 
NY
 
Combined Cycle
 
100
%
 
60

 
80

 
140,717

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

 
77

 
2,365

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

 
73

 
26,325

Mickleton Energy Center
 
RFC
 
NJ
 
Simple Cycle
 
100
%
 

 
67

 
13,737

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

 
60

 
2,099

Bethpage Power Plant
 
NPCC
 
NY
 
Combined Cycle
 
100
%
 
55

 
56

 
295,157

Christiana Energy Center
 
RFC
 
DE
 
Simple Cycle
 
100
%
 

 
53

 
1,326

Bethpage Peaker
 
NPCC
 
NY
 
Simple Cycle
 
100
%
 

 
48

 
123,639

Stony Brook Power Plant
 
NPCC
 
NY
 
Cogen
 
100
%
 
45

 
47

 
283,328

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

 
34

 
2,553

Tasley Energy Center
 
RFC
 
VA
 
Simple Cycle
 
100
%
 

 
33

 
2,707

Whitby Cogeneration(11)
 
NPCC
 
ON
 
Cogen
 
50
%
 
25

 
25

 
193,329

Delaware City Energy Center
 
RFC
 
DE
 
Simple Cycle
 
100
%
 

 
23

 
993

West Energy Center
 
RFC
 
DE
 
Simple Cycle
 
100
%
 

 
20

 
133


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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)
 
2014
Total MWh
Generated(4)
Bayview Energy Center
 
RFC
 
VA
 
Simple Cycle
 
100
%
 

 
12

 
3,712

Crisfield Energy Center
 
RFC
 
MD
 
Simple Cycle
 
100
%
 

 
10

 
2,242

Vineland Solar Energy Center
 
RFC
 
NJ
 
Renewable
 
100
%
 

 
4

 
5,513

Subtotal
 
 
 
 
 
 
 
 
 
6,332

 
9,597

 
24,619,940

Total operating power plants
 
87
 
 
 
 
 
 
 
21,789

 
26,548

 
99,229,227

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Power plants sold or retired during 2014
 
 
 
 
 
 
 
 
 
 
 
 
Carville Energy Center
 
SERC
 
LA
 
Cogen
 
100%

 
n/a
 
n/a
 
1,117,532

Columbia Energy Center
 
SERC
 
SC
 
Cogen
 
100%

 
n/a
 
n/a
 
224,367

Decatur Energy Center
 
SERC
 
AL
 
Combined Cycle
 
100%

 
n/a
 
n/a
 
653,780

Deepwater Energy Center
 
RFC
 
NJ
 
Steam Cycle
 
100%

 
n/a
 
n/a
 
662

Hog Bayou Energy Center
 
SERC
 
AL
 
Combined Cycle
 
100%

 
n/a
 
n/a
 
300,466

Oneta Energy Center
 
SPP
 
OK
 
Combined Cycle
 
100%

 
n/a
 
n/a
 
1,524,648

Santa Rosa Energy Center
 
SERC
 
FL
 
Combined Cycle
 
100%

 
n/a
 
n/a
 
256,046

Subtotal
 
 
 
 
 
 
 
 
 
 
 
 
 
4,077,501

Total operating, sold and retired power plants
 
 
 
 
 
 
 
 
 
 
 
 
 
103,306,728

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Projects Under Construction and Advanced Development
Projects Under Construction
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Garrison Energy Center
 
RFC
 
DE
 
Combined Cycle
 
100
%
 
273

 
309

 
n/a

Projects Under Advanced Development
 
 
 
 
 
 
 
 
 
 
 
 
 
 
York 2 Energy Center
 
RFC
 
PA
 
Combined Cycle
 
100
%
 
668

 
760

 
n/a

Total operating power plants and projects
 
 
 
 
 
 
 
 
 
22,730

 
27,617

 
 
___________
(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 February 2015; 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)
The operating lease related to these power plants will expire in July 2015.
(7)
Pasadena is comprised of 260 MW of cogen technology and 521 MW of combined cycle (non-cogen) technology.
(8)
Freeport Energy Center is owned by Calpine; however, it is contracted and operated by The Dow Chemical Company.
(9)
Calpine holds a 50% partnership interest in Greenfield LP through its subsidiaries; however, it is operated by a third party.
(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.

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We provide operations and maintenance services for all but three of the power plants in which we have an interest. Such services include the operation of power plants, geothermal steam fields, wells and well pumps and natural gas pipelines. We also supervise maintenance, materials purchasing and inventory control, manage cash flow, train staff and prepare operations and maintenance manuals for each power plant that we operate. As a power plant develops an operating history, we analyze its operation and may modify or upgrade equipment, or adjust operating procedures or maintenance measures to enhance the power plant’s reliability or profitability. Although we do not operate the Freeport Energy Center, our outage services subsidiary performs all major maintenance services for this plant under a contract with The Dow Chemical Company through April 2032.
Certain power plants in which we have an interest have been financed primarily with project financing that is structured to be serviced out of the cash flows derived from the sale of power (and, if applicable, thermal energy and capacity) produced by such power plants and generally provide that the obligations to pay interest and principal on the loans are secured solely by the capital stock or partnership interests, physical assets, contracts and/or cash flows attributable to the entities that own the power plants. The lenders under these project financings generally have no recourse for repayment against us or any of our assets or the assets of any other entity other than foreclosure on pledges of stock or partnership interests and the assets attributable to the entities that own the power plants. However, defaults under some project financings may result in cross-defaults to certain of our other debt and debt instruments, including our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. Acceleration of the maturity of a project financing following a default may also result in a cross-acceleration of such other debt.
Substantially all of the power plants in which we have an interest are located on sites which we own or lease on a long-term basis.

EMISSIONS AND OUR ENVIRONMENTAL PROFILE
Our environmental record has been widely recognized. We were an EPA Climate Leaders Partner with a stated goal to reduce GHG emissions, and we became the first power producer to earn the distinction of Climate Action LeaderTM. In 2013, our emissions of GHG amounted to approximately 45 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.

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(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.
(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 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 13 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 11 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 two 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.
Three of our power plants (Sutter Energy Center, Otay Mesa Energy Center and Fore River Energy Center) employ air cooled condensers for cooling, consuming virtually no water for cooling.
In 12 of our operating natural gas-fired 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 36 million gallons per day of valuable surface and/or groundwater for cooling.
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 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

22



HAPs from specific industrial sectors. The Clean Air Act also requires the EPA to regulate emissions of certain pollutants that affect visibility in national parks and wilderness areas (“Regional Haze”).
Ozone NAAQS
On November 25, 2014, the EPA proposed to revise the ozone NAAQS downward, to a range of 0.065-0.070 ppm. The EPA is under court order to finalize this standard by no later than October 1, 2015. Ozone is formed in the atmosphere by the reaction of NOx with volatile organic compounds (“VOC”) in the presence of sunlight, with the implication that a reduction in the ozone NAAQS generally leads to requirements to reduce emissions of NOx and VOC. Depending on the final level of the standard, additional reductions in NOx emissions from the power industry may be required in areas in which this standard is not attained or more generally in the Eastern U.S. However, given the timelines noted above, we cannot yet estimate what the impact will be on our business.
Mercury and Air Toxics Standards
On February 16, 2012, the EPA promulgated 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 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.
On April 15, 2014, the D.C. Circuit rejected all legal challenges to the EPA’s MATS regulation in the White Stallion Energy Center, LLC, et al v. EPA. case, which included challenges by over 20 states, industry groups and companies. On July 14, 2014, three petitions for a writ of certiorari were filed with the U.S. Supreme Court in conjunction with the D.C. Circuit’s action. On November 25, 2014, the U.S. Supreme Court granted the petitions on the limited issue of the consideration of costs in the determination of the regulation of HAPs. Oral arguments will be heard in the spring of 2015.
Multi-Pollutant Programs — CAIR and CSAPR
Pursuant to authority granted under the CAA, the EPA promulgated 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 was 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, but ultimately allowed CAIR to take effect and continue to apply while the EPA designed a replacement rule. CAIR was in effect from January 1, 2009 through December 31, 2014.
On July 6, 2011, the EPA finalized CSAPR as the replacement program for CAIR. CSAPR requires 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. The reduction requirements in CSAPR are similar in magnitude to those in CAIR. CSAPR has been in litigation since before its original implementation, with the rule being declared invalid by the D.C. Circuit and stayed while appeals to the U.S. Supreme Court were heard.
On April 29, 2014, the U.S. Supreme Court in EME Homer City Generation v. EPA ruled in favor of the EPA by reversing and remanding the decision of the D.C. Circuit invalidating CSAPR. On October 23, 2014, the D.C. Circuit lifted the stay so that CSAPR can be fully implemented. On December 3, 2014, the EPA issued ministerial rules and a Notice of Data Availability that clearly defined how CSAPR is to be implemented. As a result of the U.S. Supreme Court ruling and the EPA’s subsequent rulemaking, CSAPR took effect on January 1, 2015. All of the original provisions of CSAPR were included, with a three year delay of the original rule timelines. Remaining legal issues are scheduled for oral argument before the D.C. Circuit on February 25, 2015.

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CSAPR and MATS primarily impact coal-fired power plants, and therefore judicial decisions related to these rules do not directly affect our business. However, we believe that well-founded regulations protecting health and the environment could benefit our competitive position by better recognizing the value of our investments in clean power generation technology.
Regional Haze
The EPA first issued the Regional Haze Rule in 1999, with a focus on emissions of SO2, NOx, and particulate matter, particularly PM2.5. Such emissions can affect visibility regionally, with the result that in the eastern U.S., regional NOx and SO2 programs like CSAPR and CAIR are considered to achieve much of the required emission reductions that would be required to reduce regional haze. However, individual facilities may still be required to install Best Available Retrofit Technology (“BART”) if they are found to have a significant individual effect on visibility in areas of interest. On November 24, 2014, the EPA proposed to partially approve and partially disapprove Texas’ Regional Haze program. This proposal includes a federal implementation plan that would impose SO2 emission controls on 15 units at eight coal-fired power plants in Texas as part of a long-term strategy for making reasonable progress at three Class I areas in Texas and Oklahoma, set new reasonable progress goals for the Big Bend, the Guadalupe Mountains, and Wichita Mountains Class I areas, and substitute CSAPR for CAIR to satisfy BART requirements. The federal implementation plan would be effective until Texas replaces it with an approvable state implementation plan. While this will not directly affect our fleet, it does have the potential to affect the power market in Texas because the affected facilities will either have to further reduce emissions or retire.
GHG Emissions
In response to the 2007 decision of the U.S. Supreme Court in Massachusetts v. EPA and the Tailpipe Rule, which set GHG emission standards for cars and light trucks, the EPA issued two rules phasing in GHG regulation of stationary sources under the PSD and Title V programs of the CAA. First, pursuant to the Timing Rule, the EPA delayed when major stationary sources of GHGs would otherwise be subject to PSD and Title V, limiting their application to the effective date of the Tailpipe Rule. Second, pursuant to the Tailoring Rule, the EPA limited the initial applicability of the GHG regulations to sources exceeding a specified carbon threshold.
These rules were the subject of more than sixty petitions for review by industry and the states, and after consolidation at the D.C. Circuit, were upheld. The U.S. Supreme Court heard the case on appeal, and on June 23, 2014, rejected the Tailoring Rule, but upheld the EPA’s authority to impose GHG limits on large new or modified sources if such sources were required to obtain permits for other pollutants. We are still assessing the overall impact of this ruling, but we do not expect a significant negative impact on our business as a result of this narrowing of the EPA’s authority.
In January 2014, the EPA proposed New Source Performance Standards (“NSPS”) for GHG emissions from new power plants, which are to be finalized within a reasonable period. In June 2014, the EPA proposed the Clean Power Plan which requires a reduction in GHG emissions from existing power plants of 30% from 2005 levels by 2030. According to the EPA, the Clean Power Plan is to be finalized by June 2015 with state plans to implement these guidelines to be finalized by June 2016 with a possible extension to 2017. The Clean Power Plan provides states flexibility in meeting the requirements including increasing energy efficiency measures, adding renewable generation and increasing dispatch of natural gas-fired generation. In June 2014, the EPA also proposed GHG NSPS provisions for modified and reconstructed sources (the “Modification/Reconstruction Rule”). In January 2015, the EPA announced that the GHG NSPS, the Modification/Reconstruction Rule and the Clean Power Plan would be finalized by summer 2015. We believe that our competitive position is enhanced by regulations that ensure all power plants take the necessary steps to reduce their pollutant emissions.
Demand Response Resources under NESHAPs
FERC’s Order No. 745 regarding compensation of demand response in the energy market was appealed to the D.C. Circuit. In May 2014, the D.C. Circuit issued an order vacating and remanding Order No. 745 on the basis that the FERC does not have jurisdiction to regulate demand response in the energy market. On January 15, 2015, the FERC and several other entities filed petitions for certiorari with the U.S. Supreme Court, asking for review of the D.C. Circuit’s decision. Also, on October 20, 2014, the D.C. Circuit granted the FERC’s request for a stay of the decision. The stay will remain in place until final disposition by the U.S. Supreme Court.
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

24



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 VOC, 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 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.
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 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 have been amended by the CARB several times since then.
Under the Cap-and-Trade Regulation, the first compliance period for covered entities like Calpine began on January 1, 2013 and ended on December 31, 2014. The second and third compliance periods, wherein the program applies to a broader scope of entities, including transportation fuels and natural gas distribution, run through the end of 2017 and 2020, respectively.
On January 1, 2014, the California Cap-and-Trade market was officially linked to the GHG Cap-and-Trade market in Quebec. The first joint GHG allowance auction occurred on November 25, 2014. Joint auctions of allowances issued by both jurisdictions will be held quarterly.
On May 22, 2014, the CARB approved its “First Update to the Climate Change Scoping Plan: Building on the Framework” pursuant to AB 32. The updated scoping plan states that California is on track to meet its 2020 emissions target and makes recommendations for how to achieve the goal of reducing statewide GHG emissions to 80% below 1990 levels by 2050, including recommending the establishment of a mid-term emissions target for 2030. Legislation has been introduced for consideration in 2015 concerning the development of such goals. The CARB has also begun considering how the Cap-and-Trade Regulation might be relied upon as a component of any state plan that would be required pursuant to the EPA-proposed Clean Power Plan.
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.

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Northeast: CO2 – RGGI
On January 1, 2009, ten states in the Northeast implemented a Cap-and-Trade program, RGGI, which affects our power plants in Maine, Massachusetts, 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. Depending on the final level of the revised ozone NAAQS, allowable NOx emissions under this program could be reduced at some point in the future, which could cause us to incur additional compliance costs. However, we cannot estimate such costs until such time as the standard is finalized, nonattainment levels are determined and compliance programs are put in place.
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 retired our 158 MW Deepwater Energy Center in 2014. We provided notice to PJM that we plan to retire our 34 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. Due to current generator capacity concerns in the PJM service area for the winter of 2015/2016, 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. In addition, PJM has proposed a new Capacity Performance Program intended to improve electric reliability within PJM during extreme weather conditions, and this program could potentially affect the retirement date of a number of sources within PJM, including ours, subject to regulatory approvals.
We are installing emissions controls equipment at our 73 MW Carll’s Corner Energy Center and 67 MW Mickleton Energy Center to comply with the emission limits in the HEDD Rule, as these power plants cleared PJM’s 2015/2016 base residual auction. We expect that the implementation of the HEDD rule, and our method of compliance, whether retirement of, or installation of emissions controls at these facilities will not have a material impact on our financial condition, results of operations or cash flows.
Renewable Portfolio Standards
Policymakers have been considering variations of an RPS at the federal and state level. Generally, an RPS requires each retail seller of electricity to include in its resource portfolio (the resources procured by the retail seller to supply its retail customers) a certain amount of power generated from renewable or clean energy resources by a certain date.
Federal RPS
Although there is currently no national RPS, President Obama has stated his goal is to have 80% of the nation’s electricity provided from clean energy resources, which includes natural gas resources, by 2035, and some U.S. Congressional members have expressed interest in national renewable or clean energy standard legislation. It is too early to determine whether or not the enactment of a national RPS will have a positive or negative impact on us. Depending on the RPS structure, an RPS could enhance the value of our existing Geysers Assets. However, an RPS would likely initially drive up the number of wind and solar resources, which could negatively impact the dispatch of our natural gas-fired power plants, primarily in Texas and California. Conversely, our natural gas power plants could benefit by providing complementary/back-up service for these intermittent renewable resources or by being included in a clean energy standard.

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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. In his recent inaugural address, the Governor articulated the goal of producing half of California’s electricity from renewables by 2030. It is unclear whether the primary vehicle to achieve this goal will be a higher RPS.
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.
On August 15, 2014, the EPA published the final Cooling Water Intake Structure Rule, which regulates the design and operation of such structures at power plants and other sources in order to minimize adverse environmental impacts. We are only subject to the provisions of this rule at one of our power plants, and we do not expect the rule to have a material direct 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

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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. The EPA announced the finalization of this rule on December 19, 2014 which determined that storage and disposal of CCRs will be regulated as nonhazardous waste under Subtitle D of RCRA. The rule establishes technical requirements for CCR landfills and surface impoundments (ponds) intended to ensure impoundment integrity and protection of surface, groundwater and air quality. We do not use coal, so the final CCR rule, 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 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 the 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. The FERC governs, among other things, the disposition of certain utility property, the issuance of securities by public utilities, the rates, the terms and conditions for the transmission or wholesale sale of power in interstate commerce, the interlocking directorates, and the uniform system of accounts and reporting requirements for public utilities.
The majority of our power plants are subject to FERC’s jurisdiction; however, certain power plants qualify for available exemptions. FERC’s jurisdiction over EWGs under the FPA applies to the majority of our power plants because they are EWGs or are owned by EWGs, except our EWGs located in ERCOT. Power plants located in ERCOT are exempt from many FERC regulations under the FPA. Many of our power plants that are not EWGs are operated as QFs under PURPA. Several of our affiliates have been granted authority to engage in sales at market-based rates and blanket authority to issue securities, and have also been granted certain waivers of FERC reporting and accounting regulations available to non-traditional public utilities; however, we cannot assure that such authorities or waivers will not be revoked for these affiliates or will be granted in the future to other affiliates.

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FERC has the right to review books and records of “holding companies,” as defined in PUHCA 2005, that are determined by FERC to be relevant to the companies’ respective FERC-jurisdictional rates. We are considered a holding company, as defined in PUHCA 2005, by virtue of our control of the outstanding voting securities of our subsidiaries that own or operate power plants used for the generation of power for sale, or that are themselves holding companies. However, we are exempt from FERC’s books and records inspection rights pursuant to one of the limited exemptions under PUHCA 2005 as we are a holding company due solely to our owning one or more QFs, EWGs and Foreign Utility Companies (“FUCOs”). If any of our entities were not a QF, EWG or FUCO, then we and our holding company 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 the 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 the 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.
Power Regions
The following is a brief overview of the most significant regulatory issues affecting our business in our core power regions — CAISO, ERCOT, PJM and ISO-NE. The CAISO market is in our West segment. The ERCOT market is in our Texas segment. The PJM and ISO-NE markets are in our East segment.
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, 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 offer price cap for energy and capacity services 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 price formation. ERCOT successfully launched the Operating Reserve Demand Curve (“ORDC”) functionality on June 1, 2014. This application produces

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a price “adder” to the clearing price of energy that increases as reserve capacity declines. As follow up to the ORDC, stakeholders have approved a rule change that will create a reliability deployment adder and will reflect the value of ISO out of merit actions and correct real time price reversals which is scheduled to be implemented prior to the 2015 peak summer season. The PUCT continues to consider the appropriate reliability standard that should be used to set ERCOT’s planning reserve margin. As these proceedings are ongoing and the timing of these changes is uncertain, 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.
PJM experienced several unusual cold weather events during January 2014. PJM maintained system reliability, but the system was challenged. In order to address some of these challenges, PJM has filed proposed capacity market rule changes that, if approved by the FERC, would significantly change PJM’s Reliability Pricing Model. PJM’s proposed changes include stronger performance incentives and more significant penalties for failure to perform during peak power system conditions. We support PJM’s proposed changes and believe that, overall, they enhance the competitiveness of the PJM power market; however, we cannot predict whether the FERC will approve all of PJM’s changes, what their ultimate impact may be, nor the impact on our financial condition, results of operations or cash flows.
ISO-NE
We have two power plants in our East segment located in Massachusetts and Maine for which ISO-NE is the RTO. ISO-NE has broad authority over the day-to-day operation of the transmission system and operates a day-ahead and real-time wholesale energy market, a forward capacity market and an ancillary services markets.
ISO-NE continues to express concern related to the adequacy of natural gas transmission infrastructure and, for the past two years, has taken various out-of-market actions to ensure winter reliability over the near term. Over the longer term, the FERC has approved significant changes to the operation of the region’s capacity market beginning with the 2015 Forward Capacity Auction (“FCA”). The ISO’s new “Pay for Performance” construct will result in significantly higher penalties for assets that fail to perform during shortage events beginning with the 2018-2019 commitment period. The FERC also approved a two-year extension of the “lock-in” period for new generation, allowing new generating assets that clear an FCA to lock in their cleared price for a total of seven years.
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 own a pipeline in Texas that is subject to the Texas Railroad Commission regulation as a Texas gas utility.
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.

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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.
EMPLOYEES
At December 31, 2014, we employed 2,052 full-time employees, of whom 162 were represented by collective bargaining agreements. Four collective bargaining agreements, representing a total of 100 employees, will 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;
weather conditions, particularly unusually mild summers or warm winters in our market areas;

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quarterly and seasonal fluctuations;
an economic downturn which could negatively impact demand for power;
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
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 risks related to commodity price movements, deviations in weather and 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.

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In addition, we have various internal policies and procedures designed to monitor hedging activities and positions. These policies and procedures are designed, in part, to prevent unauthorized purchases or sales of products by our employees. We cannot assure, however, that these steps will detect and prevent all violations of our Risk Management Policy, particularly if deception or other intentional misconduct is involved. A significant policy violation that is not detected could result in a material financial loss for us.
Our ability to enter into hedging agreements and manage our counterparty credit risk could adversely affect us.