CALPINE CORP - FORM 10-K - February 11, 2016

Attached files

file	filename
EX-32.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER - CALPINE CORP	cpn_exhibit321x12312015.htm
EX-23.1 - CONSENT OF PRICEWATERHOUSECOOPERS - CALPINE CORP	cpn_exhibit231x12312015.htm
EX-31.2 - SECTION 302 CERTIFICATION OF CFO - CALPINE CORP	cpn_exhibit312x12312015.htm
EX-12.1 - COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES - CALPINE CORP	cpn_exhibit121x12312015.htm
EX-21.1 - SUBSIDIARIES OF THE COMPANY - CALPINE CORP	cpn_exhibit211x12312015.htm
EX-31.1 - SECTION 302 CERTIFICATION OF CEO - CALPINE CORP	cpn_exhibit311x12312015.htm
EX-10.1.19 - AMENDMENT NO. 3 TO THE CREDIT AGREEMENT, DATED AS OF FEBRUARY 8, 2016 - CALPINE CORP	cpn_exhibit10119-calpiner.htm

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, 2015

[ ]		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, 2015, the last business day of the registrant’s most recently completed second fiscal quarter: approximately $6,445 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: 356,660,646 shares of common stock, par value $0.001, were outstanding as of February 10, 2016.

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 2016 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, 2015

TABLE OF CONTENTS




		Page
	PART I
Item 1.	Business	3
Item 1A.	Risk Factors	33
Item 1B.	Unresolved Staff Comments	45
Item 2.	Properties	45
Item 3.	Legal Proceedings	45
Item 4.	Mine Safety Disclosures	45

	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	46
Item 6.	Selected Financial Data	48
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	49
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	86
Item 8.	Financial Statements and Supplementary Data	86
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	87
Item 9A.	Controls and Procedures	87
Item 9B.	Other Information	88

	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	89
Item 11.	Executive Compensation	90
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	90
Item 13.	Certain Relationships and Related Transactions, and Director Independence	90
Item 14.	Principal Accounting Fees and Services	90

	PART IV
Item 15.	Exhibits, Financial Statement Schedule	91
Signatures		99
Power of Attorney		100
Index to Consolidated Financial Statements		101

DEFINITIONS

As used in this annual report for the year ended December 31, 2015, 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, and repaid in a series of transactions on November 7, 2012, October 31, 2013 and December 2, 2013

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, in each case repaid on May 28, 2015

2019 First Lien Notes		The $400 million aggregate principal amount of 8.0% senior secured notes due 2019, issued May 25, 2010, and repaid in a series of transactions on November 7, 2012, December 2, 2013 and July 22, 2014

2019 First Lien Term Loan		The $835 million first lien senior secured term loan, dated October 9, 2012, among Calpine Corporation, as borrower, the lenders party thereto, 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, and repaid in a series of transactions on November 7, 2012, December 2, 2013 and July 22, 2014

2020 First Lien Term Loan		The $390 million first lien senior secured term loan, dated October 23, 2013, among Calpine Corporation, as borrower, the lenders party thereto, 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, and repaid in a series of transactions on November 7, 2012, December 2, 2013 and July 22, 2014

2022 First Lien Notes		The $750 million aggregate principal amount of 6.0% senior secured notes due 2022, issued October 31, 2013

2022 First Lien Term Loan		The $1.6 billion first lien senior secured term loan, dated May 28, 2015, among Calpine Corporation, as borrower, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent

2023 First Lien Notes		The $1.2 billion aggregate principal amount of 7.875% senior secured notes due 2023, issued January 14, 2011, and partially repaid in a series of transactions on November 7, 2012, December 2, 2013, December 4, 2014 and December 7, 2015

2023 First Lien Term Loan		The $550 million first lien senior secured term loan, dated December 15, 2015, among Calpine Corporation, as borrower, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent

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



ABBREVIATION		DEFINITION

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, modification 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

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

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 and repaid on June 3, 2013

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

iii



ABBREVIATION		DEFINITION

CDHI		Calpine Development Holdings, Inc., an indirect, wholly-owned subsidiary of Calpine

CFTC		Commodities Futures Trading Commission

Champion Energy		Champion Energy Marketing, LLC, which owns a retail electric provider that serves residential, governmental, commercial and industrial customers in deregulated electricity markets in Texas, Illinois, Pennsylvania, Ohio, New Jersey, Maryland, Massachusetts and New York

Chapter 11		Chapter 11 of the U.S. Bankruptcy Code

CO₂		Carbon dioxide

COD		Commercial operations date

Cogeneration		Using a portion or all of the steam generated in the power generating process to supply a customer with steam for use in the customer's operations

Commodity expense		The sum of our expenses from fuel and purchased energy expense, fuel transportation expense, transmission expense, environmental compliance expense and realized settlements from our marketing, hedging and optimization activities including natural gas and fuel oil 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, 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 $1.7 billion aggregate amount revolving credit facility credit agreement, dated as of December 10, 2010, as amended on June 27, 2013, July 30, 2014 and February 8, 2016, 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



ABBREVIATION		DEFINITION


Equity Plan		The Amended and Restated Calpine Corporation 2008 Equity Incentive Plan

ERCOT		Electric Reliability Council of Texas

EWG(s)		Exempt wholesale generator(s)

Exchange Act		U.S. Securities Exchange Act of 1934, as amended

FASB		Financial Accounting Standards Board

FDIC		U.S. Federal Deposit Insurance Corporation

FERC		U.S. Federal Energy Regulatory Commission

First Lien Notes		Collectively, the 2022 First Lien Notes, the 2023 First Lien Notes and the 2024 First Lien Notes

First Lien Term Loans		Collectively, the 2019 First Lien Term Loan, the 2020 First Lien Term Loan, the 2022 First Lien Term Loan and the 2023 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 14 operating power plants

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 Inc., an independent nonprofit RTO serving states in the New England area, including Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont

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



ABBREVIATION		DEFINITION


MISO		Midwest ISO

MMBtu		Million Btu

MRO		Midwest Reliability Organization

MW		Megawatt(s), a measure of plant capacity

MWh		Megawatt hour(s), a measure of power produced, purchased or sold

NAAQS		National Ambient Air Quality Standards

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



ABBREVIATION		DEFINITION

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, 2015, filed with the SEC on February 12, 2016

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 Standard

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

Steamboat		Calpine Steamboat Holdings, LLC, an indirect, wholly-owned subsidiary of Calpine Corporation

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)

vii



ABBREVIATION		DEFINITION


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

viii

Forward-Looking Statements

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 comply with covenants under our Senior Unsecured Notes, First Lien Notes, First Lien Term Loans, Corporate Revolving Facility, 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 renewable sources of power and 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 revenue may not occur at expected levels;


•	Natural disasters, such as hurricanes, earthquakes, droughts, wildfires and floods, acts of terrorism or cyber attacks that may impact our power plants or the markets our power plants or retail operations serve and our corporate headquarters;


•	Disruptions in or limitations on the transportation of natural gas or fuel oil and the 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.

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 as soon as reasonably practicable after such materials are filed with or furnished to the SEC. Our SEC filings, including exhibits filed therewith, are also available on 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.

PART I


Item 1.	Business

BUSINESS AND STRATEGY

Business

We are a premier power producer with 84 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 through our disciplined approach to capital allocation that includes investing in growth, returning money to shareholders, and prudently managing our balance sheet.

Our capital allocation philosophy seeks to maximize levered cash returns to equity on a per share basis while maintaining a strong balance sheet. We 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 and Mid-Atlantic regions (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 flexible and reliable 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. as well as the largest single producing power generation asset of all renewable energy in the state of California.

We sell 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 and other governmental entities, power marketers as well as retail commercial, industrial and residential customers. Effective after the October 1, 2015 acquisition, we entered the retail market in scale through our retail subsidiary, Champion Energy. 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, environmental product, fuel oil and other physical and financial contracts to hedge certain business risks and optimize our portfolio of power plants. Seasonality and weather can have a significant impact on our results of operations and are also considered in our hedging and optimization activities.

Subsequent to the completion of our purchase of Granite Ridge Energy Center on February 5, 2016, our portfolio, including partnership interests, consists of 84 power plants, including one under construction, located throughout 19 states in the U.S. and in Canada, with an aggregate current generation capacity of 27,282 MW and 760 MW under construction. Our fleet, including projects under construction, consists of 68 natural gas-fired combustion turbine-based plants, one fuel oil-fired steam-based plant, 14 geothermal steam turbine-based plants and one photovoltaic solar plant. In 2015, our fleet of power plants produced approximately 115 billion KWh of electric power for our customers. In addition, we are one of the largest consumers of natural gas in North America. In 2015, we consumed 878 Bcf or approximately 9% of the total estimated natural gas consumed for power generation in the U.S. We are actively working to build a pipeline of development and growth options for our generation capacity including both natural gas and renewables including geothermal. We also are actively seeking to continue to grow our wholesale and retail sales efforts.

We believe our unique fleet compares favorably with those of our major competition on the basis of environmental stewardship, scale and geographical diversity. The discovery and exploitation of natural gas from shale combined with our modern and efficient combined-cycle power 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 recent years 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 of coal ash or nuclear plant waste. We believe that the Clean Power Plan, which requires a 32% reduction in GHG emissions from existing power plants, including our natural gas-fired power plants, from 2005 levels by 2030, will impact our competitors who use other fossil fuels or older, less efficient technologies, providing us with a net competitive advantage.

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 and retail affiliate 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 relationships;

•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 2015, our employees achieved a total recordable incident rate of 0.73 recordable 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 2.3% and a starting reliability of 98.3% during the year ended December 31, 2015.


•	During 2015, our outage services subsidiary completed 15 major inspections and nine hot gas path inspections.


•	For the past 15 years on average, our Geysers Assets have reliably generated approximately six million MWh of renewable power per year.

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 to our current assets offer proven and financially disciplined opportunities to improve our operations, capacity and efficiencies. During 2015 and through the filing of this Report, we strategically repositioned

our portfolio by adding capacity in our core regions and by divesting positions in non-core markets through the following transactions:


•	In June 2015, our Garrison Energy Center commenced commercial operations, bringing online approximately 309 MW of combined-cycle, natural gas-fired capacity with dual-fuel capability.


•	During the second quarter of 2015, we began construction of our 760 MW York 2 Energy Center and expect commercial operations to commence during the second quarter of 2017.

•

In July 2015, the sale of our Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million, excluding working capital and other adjustments, was approved by the FERC and the Florida Public Service Commission. In accordance with the asset sale agreement, the sale will be consummated in January 2017 upon the conclusion of a 27-month PPA. This sale represents a strategic disposition of a power plant in a wholesale power market dominated by regulated utilities.


•	On October 1, 2015, we acquired Champion Energy for approximately $240 million, excluding working capital adjustments. The addition of this well-established retail sales organization is consistent with our stated goal of getting closer to our end-use customers and provides us a valuable sales channel for directly reaching a much greater portion of the load we seek to serve.

•

On February 5, 2016, we completed the purchase of Granite Ridge Energy Center, a power plant with a nameplate capacity of 745 MW (summer peaking capacity of 695 MW), for approximately $500 million, excluding working capital adjustments. The addition of this modern, efficient, natural gas-fired, combined-cycle power plant will increase capacity in our East segment, specifically the constrained New England market.

In addition, our significant ongoing projects under construction, growth initiatives and modernizations are discussed below:


•	Garrison Energy Center — We are in the early stages of development of a second phase of the Garrison Energy Center that will add approximately 430 MW of dual-fuel, combined-cycle capacity to our existing Garrison Energy Center. PJM has completed its feasibility study of the project and the system impact study is underway.

•

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 and 2018/2019 base residual auctions. The project is now under construction, and we expect COD during the second quarter of 2017. PJM has completed the interconnection study process for an additional 68 MW of planned capacity at the York 2 Energy Center. This incremental 68 MW of planned capacity cleared the 2018/2019 base residual auction.

•

Guadalupe Peaking Energy Center — In April 2015, we executed an agreement with Guadalupe Valley Electric Cooperative (“GVEC”) that will facilitate the construction of a 418 MW natural gas-fired peaking power plant to be co-located with our Guadalupe Energy Center. Under the terms of the agreement, construction of the Guadalupe Peaking Energy Center (“GPEC”) may commence at our discretion, so long as the power plant reaches COD by June 1, 2019. When the power plant begins commercial operation, GVEC will purchase a 50% ownership interest in GPEC. Once built, GPEC will feature two fast-ramping combustion turbines capable of responding to peaks in power demand. This project represents a mutually beneficial response to our customer’s desire to have direct access to peaking generation resources, as it leverages the benefits of our existing site and development rights and our construction and operating expertise, as well as our customer’s ability to fund its investment at attractive rates, all while affording us the flexibility of timing the plant’s construction in response to market pricing signals.

•

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. The PPA was executed in April 2015 and remains subject to approval by the North Dakota Public Service Commission. Commercial operation of the expanded capacity may commence as early as 2019, subject to requisite regulatory approvals and applicable contract conditions.

•

PJM and ISO-NE Development Opportunities — We are currently evaluating opportunities to develop additional projects in the PJM and ISO-NE market areas 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 when economical.


•	Turbine Modernization — We continue to move forward with our turbine modernization program. Through December 31, 2015, we have completed the upgrade of 13 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 Relationships — We continue to focus on providing products and services that are beneficial to our customers. A summary of certain significant customer metrics and contracts entered into in 2015 are as follows:

Champion Energy


•	In 2015, Champion Energy, our retail electric provider, served approximately 22 million MWh of customer load consisting of approximately 2.1 million annualized residential customer equivalents at December 31, 2015, concentrated in Texas, the Northeast and Mid-Atlantic where Calpine has a substantial power generation presence.

West


•	We entered into a new PPA with Marin Clean Energy to provide up to 65 MW of power from our Delta Energy Center and other northern California power plants commencing in April 2015 and extending through December 2017.


•	Our ten-year PPA with Southern California Edison for 225 MW of capacity and renewable energy from our Geysers Assets commencing in June 2017 was approved by the CPUC in the first quarter of 2015.


•	We entered into a new ten-year PPA with Southern California Edison for 50 MW of capacity and renewable energy from our Geysers Assets commencing in January 2018. The PPA remains subject to approval by the CPUC.


•	We entered into a new one-year resource adequacy contract with SCE for 238 MW from our Pastoria Energy Center commencing in January 2018.


•	We entered into a new three-year PPA with the San Francisco Public Utilities Commission to provide, on average, approximately 43 MW of energy and renewable energy annually commencing in May 2016.

Texas


•	We entered into a new three-year PPA with Brazos Electric Power Cooperative to provide 300 MW of energy from our Texas power plant fleet commencing in January 2016.


•	We entered into a new three-year PPA with Pedernales Electric Cooperative to provide approximately 140 MW of energy from our Texas power plant fleet commencing in January 2017.


•	We entered into a new two-year PPA with Guadalupe Valley Electric Cooperative to provide approximately 270 MW of energy from our Texas power plant fleet commencing in June 2017. The execution of this PPA will facilitate the construction of a 418 MW natural gas-fired peaking power plant to be co-located with our Guadalupe Energy Center.


•	We extended our existing PPA with the South Texas Electric Cooperative to supply the Magic Valley Electric Cooperative’s full load requirements for ten years beyond 2021. Magic Valley Electric Cooperative’s peak summer load in 2015 was 490 MW.

East


•	We entered into a new 20-year PPA with Xcel Energy to provide up to 345 MW of capacity and energy from our Mankato Power Plant expansion when commercial operations commence and transmission-related upgrades have been completed.


•	We entered into a new ten-year PPA with the Tennessee Valley Authority to provide 615 MW of energy and capacity from our Morgan Energy Center commencing in February 2016.

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 rules of the 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 competitive wholesale power markets and environmental stewardship in power generation. 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 implementation of the FERC approved PJM Capacity Performance product and 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 navigated 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 and succeeded in obtaining an order requiring the local utility to enter into a long-term PPA for new additional capacity at our Mankato Power Plant.

•

Provided leadership in the successful legal challenges against New Jersey for discriminatory behavior affecting FERC jurisdictional capacity auctions, resulting in a decision by the U.S. Circuit Court of Appeals for the Third Circuit striking New Jersey’s action as being in violation of U.S. law. Petitions for certiorari were filed with the U.S. Supreme Court, asking for review of the Third Circuit’s decision. In October 2015, the U.S. Supreme Court granted certiorari but has not scheduled the case for oral argument.


•	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 in a decision citing our brief.


•	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.


•	Filed a brief with the D.C. Circuit supporting the EPA’s opposition to motions for stay of the Clean Power Plan; the D.C. Circuit denied the motions.

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. We are committed to remaining financially disciplined in our capital allocation decisions. The year ended December 31, 2015 was marked by the following accomplishments:


•	We continued to return capital to our shareholders in the form of share repurchases, having cumulatively repurchased approximately $2.8 billion or 29% of our previously outstanding shares as of the filing of this Report.


•	Specifically during 2015, we repurchased a total of 26.6 million shares of our outstanding common stock for approximately $529 million at an average price of $19.87 per share.

We further optimized our capital structure by refinancing, redeeming or amending several of our debt instruments during the year ended December 31, 2015, and through the filing of this Report, including the following transactions:


•	In February 2015, we issued $650 million in aggregate principal amount of 5.5% senior unsecured notes due 2024 in a public offering and used the net proceeds to replenish cash on hand used for the acquisition of Fore River Energy Center in the fourth quarter of 2014, to repurchase approximately $147 million of our 2023 First Lien Notes and for general corporate purposes.


•	In May 2015, we repaid our 2018 First Lien Term Loans with the proceeds from the 2022 First Lien Term Loan which extended the maturity and reduced the interest rate on approximately $1.6 billion of corporate debt.


•	In November 2015, we refinanced and upsized our Steamboat project debt which lowered the interest rate and extended the maturity by two years to November 22, 2019.


•	In December 2015, 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.


•	In December 2015, we entered into our 2023 First Lien Term Loan and will use the proceeds to fund a portion of the purchase price for the Granite Ridge Energy Center, to repay project and corporate debt and for general corporate purposes.


•	In December 2015, we entered into an agreement with one of the two lessors of our Pasadena Power Plant to purchase their 50% interest, which will result in a reduction of our project debt of approximately $50 million. The transaction is expected to close during the second quarter of 2016.

•

On February 8, 2016, we amended our Corporate Revolving Facility, extending the maturity by two years to June 27, 2020, and increasing the capacity by an additional $178 million to $1,678 million through June 27, 2018, reverting back to $1,520 million through the maturity date. Further, we increased the letter of credit sublimit by $250 million to $1.0 billion and extended the maturity by two years to June 27, 2020.

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 $390 billion in power sales in 2015 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 and Mid-Atlantic regions (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 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.

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First, we are a provider of power to utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities and other governmental entities, power marketers as well as retail commercial, industrial and residential customers. Effective after the October 1, 2015 acquisition, we entered the retail market in scale through our retail subsidiary, Champion Energy. 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. We also sell “full requirements” electricity for wholesale and retail customers, whereby we utilize our power plants as well as market purchases to serve the total electricity demand of the customer even as it varies across time.

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Second, we provide capacity for sale to utilities, independent electric system operators and retail power providers. In various markets, retail power providers (or independent electric system operators on their behalf) are required to demonstrate adequate resources to meet their power sales commitments. To meet this obligation, they procure a market product known as capacity from power plant owners or resellers. Most electricity market administrators have acknowledged that an energy only market does not provide sufficient revenues to enable existing merchant generators to recover all of their costs or to encourage the construction of new power plants. Capacity auctions have been implemented in the Northeast, Mid-Atlantic 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.

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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 have varied across our regional markets. Key trends include lower weather normalized load growth in some regions due to increased energy efficiency as well as rooftop solar installations, new renewable and natural gas-fired supply additions, and significant retirements of older, less efficient fossil-fueled plants. Reserve margins by NERC regional assessment area for each of our segments are listed below:



	2015⁽¹⁾
West:
WECC	29.7	%
Texas:
TRE	16.2	%
East:
NPCC	24.4	%
MISO	18.0	%
PJM	19.3	%
SERC	27.7	%
FRCC	28.5	%

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(1)	Data source is NERC weather-normalized estimates for 2015 published in May 2015.

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 ours. 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 96% 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 391 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 6,500 MW of dual-fueled capable power plants. Additionally, we have 4 MW of capacity from solar power generation technology with no fuel requirement.

We procure natural gas from multiple suppliers and transportation and storage sources. Although availability is generally not an issue, localized shortages (especially in extreme weather conditions in and around population centers), transportation availability and supplier financial stability issues can and do occur. When natural gas supply interruptions do occur, some of our power plants benefit from the ability to operate on fuel oil instead of natural gas.

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.

Lower natural gas prices over the past six 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 to $13/MMBtu during 2008 to an average natural gas price of $3.73/MMBtu, $4.26/MMBtu and $2.63/MMBtu during 2013, 2014 and 2015, respectively. Natural gas prices in some parts of the country were low enough that modern, combined-cycle, natural gas-fired generation was often 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. 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 will continue in 2016 (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 several 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 regional price spikes in the winter of 2014, 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.

Much of our generating capacity is located in California (included in our West segment), Texas (included in our Texas segment) and the Northeast and Mid-Atlantic (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 and Mid-Atlantic regions, 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 coal and nuclear resources to continue operating economically.

During the second half of 2014 and throughout 2015, 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 in June 2014 to a 2015 low of $35 per barrel in December 2015 (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 in a cost effective manner. However, unplanned outages during periods when Commodity Margin is positive could result in a loss of that opportunity. We generally measure our fleet performance based on our availability factors, operating Heat Rate and plant operating expense. 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.

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:

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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. In October 2015, the EPA promulgated the Clean Power Plan which requires future reductions in GHG emissions from existing power plants of 32% from 2005 levels by 2030. 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	9,107	MW	131,421	MW
Texas:
TRE	3,909	MW	86,089	MW
East:
NPCC	8,873	MW	57,218	MW
MRO	4,460	MW	45,524	MW
RFC	21,202	MW	185,137	MW
SERC	25,684	MW	227,730	MW
FRCC	275	MW	59,707	MW
Total	73,510	MW	792,826	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 power 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. The Consolidated Appropriations Act which extended the production tax credit for wind through the end of 2016 with gradual decreases thereafter until the tax credit expires completely in 2019 and extended the 30% investment tax credit for solar through the end of 2019 with gradual decreases through 2021 after which the investment tax credit declines to 10% was enacted in December 2015. In October 2015, the EPA promulgated the Clean Power Plan which requires future reductions in GHG emissions from existing power plants and provides flexibility in meeting the emissions reduction requirements including adding renewable generation. Increased renewable penetration has a particularly negative impact on inflexible baseload units and may lead to retirement of additional baseload units, which would benefit us; however, our energy margin may also decrease due to lower market clearing prices. To the extent market structures evolve to appropriately compensate units for providing flexible capacity to ensure reliability, our capacity revenue may increase.

•

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 ERCOT, PJM and ISO-NE 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 penetration) and environmental authorities deal with the implications of relying on smaller, less environmentally efficient generation sources during periods of peak demand when air quality is already challenged.


•	Environmental permitting requirements for new power plants, transmission lines and pipelines continue to increase in stringency and complexity, resulting in prolonged, expensive development cycles and high capital investments.

We believe these trends are overall positive for our existing fleet. For a discussion of federal, state and regional legislative and regulatory initiatives and how they might affect us, see “— Governmental and Regulatory Matters.”

It is very difficult to predict the continued evolution of our markets due to the uncertainty of the following:


•	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, including solar and wind capacity;


•	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, the Northeast and Mid-Atlantic, our natural gas-fired power plants compete directly with all other sources of power. The EIA estimates that in 2015, 32% of the power generated in the U.S. was fueled by natural gas, 34% by coal, 20% by nuclear facilities and the remaining 14% 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, GHG, 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, many states are considering or have already mandated that certain percentages of power delivered to end users in their jurisdictions be produced from renewable resources, such as geothermal, wind and solar energy.

Competition from nuclear energy 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.

Competition from renewable generation could increase in the future. Federal and state financial incentives and RPS requirements continue to foster renewables development. The Consolidated Appropriations Act which extended the production tax credit for wind through the end of 2016 with gradual decreases thereafter until the tax credit expires completely in 2019 and extended the 30% investment tax credit for solar through the end of 2019 with gradual decreases through 2021 after which the investment tax credit declines to 10% was enacted in December 2015. In October 2015, the EPA promulgated the Clean Power Plan which requires future reductions in GHG emissions from existing power plants and provides flexibility in meeting the

emissions reduction requirements including adding renewable generation. 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, while subsidized renewables growth is likely to continue, natural gas units will likely be needed as baseload and “back-up” generation in the long-term.

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 that is 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. On October 1, 2015, we completed the acquisition of Champion Energy, a leading retail electric provider, which also provides us with an additional outlet to transact hedging activities related to our wholesale power plant portfolio.

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 the Northeast 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 exposure and our hedging activities related to our fuel oil exposure are not material to our financial condition, results of operations or cash flows.

We produced approximately 115 billion KWh of electricity in 2015 across North America (primarily in the U.S.). We are one of the largest consumers of natural gas in North America having consumed approximately 878 Bcf during 2015. The 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 and Mid-Atlantic (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, buying and selling environmental and capacity products, natural 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 2016 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.

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 geographic area and sales in excess of 10% of our annual consolidated revenues to two of our customers.

DESCRIPTION OF OUR POWER PLANTS



Geographic Diversity	Dispatch Technology

Power Plants in Operation at December 31, 2015

Subsequent to the completion of our purchase of Granite Ridge Energy Center on February 5, 2016, we own 84 power plants, including one under construction, with an aggregate generation capacity of 27,282 MW and 760 MW under construction.

Natural Gas-Fired Fleet

Our natural gas-fired power plants primarily utilize two types of designs: 2,260 MW of simple-cycle combustion turbines and 23,568 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 fuel 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, our retail customers or an intermediary such as a marketing company. At 16 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 2015 for the power plants we operate was 7,306 Btu/KWh which results in a power conversion efficiency of approximately 47%. The power conversion efficiency is a measure of how efficiently a fossil fuel power plant converts thermal energy to electrical energy. Our 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 14 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 15 years on average, our Geysers Assets have reliably generated 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 of approximately 90% in 2015.

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 12 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 one 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.

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 2015. 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 2073. In reaching this conclusion, our evaluation, consistent with the due diligence study of 2015, 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 2015 is:


•	27% related to leases with the federal government via the Office of Natural Resources Revenue (formerly, the Minerals Management Service),


•	30% related to leases with the California State Lands Commission, and


•	43% related to leases with private landowners/leaseholders.

In general, our geothermal leases grant us the exclusive right to drill for, produce and sell geothermal resources from these properties and the right to use the surface for all related purposes. Each lease requires the payment of annual rent until commercial quantities of geothermal resources are established. After such time, the leases require the payment of minimum advance royalties or other payments until production commences, at which time production royalties are payable on a monthly basis from 10 to 31 days (depending upon the lease terms) following the close of the production month. Such royalties and other payments are payable to landowners, state and federal agencies and others, and vary widely as to the particular lease. In general, royalties payable are calculated based upon a percentage of total gross revenue received by us associated with our geothermal leases. Each lease’s royalty calculation is based upon its percentage of revenue as calculated by its steam generated relative to the total steam generated by our Geysers Assets as a whole.

Our geothermal leases are generally for initial terms varying from 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.

Five of our 14 geothermal power plants were damaged by a wildfire in September 2015; however, once repairs are completed, we expect generation capacity at our Geyser Assets to be restored to pre-fire levels.

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.

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, 2015 (excludes our acquisition of the 695 MW Granite Ridge Energy Center, which closed on February 5, 2016).



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⁾	2015 Total MWh Generated⁽⁴⁾
WEST
Geothermal
McCabe #5 & #6	WECC	CA	Renewable	100	%	85	85	733,817
Ridge Line #7 & #8	WECC	CA	Renewable	100	%	78	78	647,824
Calistoga	WECC	CA	Renewable	100	%	66	66	469,987
Eagle Rock	WECC	CA	Renewable	100	%	64	64	588,334
Big Geysers	WECC	CA	Renewable	100	%	60	60	446,403
Quicksilver⁽⁵⁾	WECC	CA	Renewable	100	%	53	53	265,947
Cobb Creek	WECC	CA	Renewable	100	%	51	51	416,738
Lake View	WECC	CA	Renewable	100	%	49	49	478,348
Socrates⁽⁵⁾	WECC	CA	Renewable	100	%	49	49	283,432
Sulphur Springs	WECC	CA	Renewable	100	%	47	47	450,791
Grant⁽⁵⁾	WECC	CA	Renewable	100	%	41	41	219,535
Sonoma⁽⁵⁾	WECC	CA	Renewable	100	%	37	37	270,290
West Ford Flat⁽⁵⁾	WECC	CA	Renewable	100	%	27	27	137,667
Aidlin	WECC	CA	Renewable	100	%	18	18	132,136
Natural Gas-Fired
Delta Energy Center	WECC	CA	Combined Cycle	100	%	835	857	4,636,426
Pastoria Energy Center	WECC	CA	Combined Cycle	100	%	770	749	4,784,605
Hermiston Power Project	WECC	OR	Combined Cycle	100	%	566	635	4,083,146
Otay Mesa Energy Center	WECC	CA	Combined Cycle	100	%	513	608	3,622,896
Metcalf Energy Center	WECC	CA	Combined Cycle	100	%	564	605	3,164,916
Sutter Energy Center⁽⁶⁾	WECC	CA	Combined Cycle	100	%	542	578	1,197,608
Los Medanos Energy Center	WECC	CA	Cogen	100	%	518	572	2,603,601
South Point Energy Center⁽⁷⁾	WECC	AZ	Combined Cycle	100	%	520	530	1,750,660
Russell City Energy Center	WECC	CA	Combined Cycle	75	%	429	464	2,167,563
Los Esteros Critical Energy Facility	WECC	CA	Combined Cycle	100	%	243	309	350,672
Gilroy Energy Center	WECC	CA	Simple Cycle	100	%	—	141	39,140
Gilroy Cogeneration Plant	WECC	CA	Cogen	100	%	109	130	138,225
King City Cogeneration Plant	WECC	CA	Cogen	100	%	120	120	440,336
Wolfskill Energy Center	WECC	CA	Simple Cycle	100	%	—	48	26,280
Yuba City Energy Center	WECC	CA	Simple Cycle	100	%	—	47	25,291
Feather River Energy Center	WECC	CA	Simple Cycle	100	%	—	47	26,649
Creed Energy Center	WECC	CA	Simple Cycle	100	%	—	47	12,406
Lambie Energy Center	WECC	CA	Simple Cycle	100	%	—	47	11,188
Goose Haven Energy Center	WECC	CA	Simple Cycle	100	%	—	47	11,351
Riverview Energy Center	WECC	CA	Simple Cycle	100	%	—	47	22,411
King City Peaking Energy Center	WECC	CA	Simple Cycle	100	%	—	44	6,998
Agnews Power Plant	WECC	CA	Combined Cycle	100	%	28	28	31,948
Subtotal						6,482	7,425	34,695,565



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⁾	2015 Total MWh Generated⁽⁴⁾
TEXAS
Deer Park Energy Center	TRE	TX	Cogen	100	%	1,103	1,204	6,997,603
Guadalupe Energy Center	TRE	TX	Combined Cycle	100	%	1,009	1,000	5,986,946
Baytown Energy Center	TRE	TX	Cogen	100	%	782	842	3,805,707
Channel Energy Center	TRE	TX	Cogen	100	%	723	808	4,734,785
Pasadena Power Plant⁽⁸⁾	TRE	TX	Cogen/Combined Cycle	100	%	763	781	4,751,419
Bosque Energy Center	TRE	TX	Combined Cycle	100	%	740	762	4,675,194
Freestone Energy Center	TRE	TX	Combined Cycle	75	%	779	746	4,299,772
Magic Valley Generating Station	TRE	TX	Combined Cycle	100	%	682	712	3,238,466
Brazos Valley Power Plant	TRE	TX	Combined Cycle	100	%	523	609	3,393,599
Corpus Christi Energy Center	TRE	TX	Cogen	100	%	426	500	2,355,305
Texas City Power Plant	TRE	TX	Cogen	100	%	400	453	960,200
Clear Lake Power Plant⁽⁹⁾	TRE	TX	Cogen	100	%	344	400	458,386
Hidalgo Energy Center	TRE	TX	Combined Cycle	78.5	%	392	374	2,215,602
Freeport Energy Center⁽¹⁰⁾	TRE	TX	Cogen	100	%	210	236	1,503,967
Subtotal						8,876	9,427	49,376,951
EAST
Bethlehem Energy Center	RFC	PA	Combined Cycle	100	%	1,047	1,130	5,327,297
Hay Road Energy Center	RFC	DE	Combined Cycle	100	%	1,039	1,130	4,236,880
Morgan Energy Center	SERC	AL	Cogen	100	%	720	807	4,986,537
Fore River Energy Center	NPCC	MA	Combined Cycle	100	%	750	731	3,801,372
Edge Moor Energy Center	RFC	DE	Steam Cycle	100	%	—	725	591,150
Osprey Energy Center⁽¹¹⁾	FRCC	FL	Combined Cycle	100	%	537	599	2,058,660
York Energy Center	RFC	PA	Combined Cycle	100	%	519	565	1,976,923
Westbrook Energy Center	NPCC	ME	Combined Cycle	100	%	552	552	1,847,954
Greenfield Energy Centre⁽¹²⁾	NPCC	ON	Combined Cycle	50	%	422	519	1,105,915
RockGen Energy Center	MRO	WI	Simple Cycle	100	%	—	503	142,682
Zion Energy Center	RFC	IL	Simple Cycle	100	%	—	503	132,434
Mankato Power Plant	MRO	MN	Combined Cycle	100	%	280	375	460,338
Garrison Energy Center	RFC	DE	Combined Cycle	100	%	273	309	527,798
Pine Bluff Energy Center	SERC	AR	Cogen	100	%	184	215	1,308,713
Cumberland Energy Center	RFC	NJ	Simple Cycle	100	%	—	191	106,107
Kennedy International Airport Power Plant	NPCC	NY	Cogen	100	%	110	121	713,225
Auburndale Peaking Energy Center	FRCC	FL	Simple Cycle	100	%	—	117	49,643
Sherman Avenue Energy Center	RFC	NJ	Simple Cycle	100	%	—	92	37,385
Bethpage Energy Center 3	NPCC	NY	Combined Cycle	100	%	60	80	331,488
Carll’s Corner Energy Center	RFC	NJ	Simple Cycle	100	%	—	73	15,300
Mickleton Energy Center	RFC	NJ	Simple Cycle	100	%	—	67	3,277
Bethpage Power Plant	NPCC	NY	Combined Cycle	100	%	55	56	323,968
Christiana Energy Center	RFC	DE	Simple Cycle	100	%	—	53	1,084
Bethpage Peaker	NPCC	NY	Simple Cycle	100	%	—	48	168,412
Stony Brook Power Plant	NPCC	NY	Cogen	100	%	45	47	277,882
Tasley Energy Center	RFC	VA	Simple Cycle	100	%	—	33	2,433
Whitby Cogeneration⁽¹³⁾	NPCC	ON	Cogen	50	%	25	25	204,284
Delaware City Energy Center	RFC	DE	Simple Cycle	100	%	—	23	90
West Energy Center	RFC	DE	Simple Cycle	100	%	—	20	104

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⁾

2015

Total MWh

Generated⁽⁴⁾

Bayview Energy Center

RFC

Simple Cycle

100

—

4,592

Crisfield Energy Center

RFC

Simple Cycle

100

—

1,542

Vineland Solar Energy Center

RFC

Renewable

100

—

5,400

Subtotal

6,618

9,735

30,750,869

Total operating power plants

21,976

26,587

114,823,385

Power plants retired or returned to owner during 2015

Greenleaf 1 Power Plant

WECC

Combined Cycle

100%

n/a

18,720

Greenleaf 2 Power Plant

WECC

Cogen

100%

n/a

104,210

Middle Energy Center

RFC

Simple Cycle

100%

n/a

Missouri Avenue Energy Center

RFC

Simple Cycle

100%

n/a

209

Cedar Energy Center

RFC

Simple Cycle

100%

n/a

Bear Canyon

WECC

Renewable

100%

n/a

17,314

Subtotal

140,564

Total operating, retired and returned to owner power plants

114,963,949

Projects Under Construction and Advanced Development

Projects Under Construction

York 2 Energy Center⁽¹⁴⁾

RFC

Combined Cycle

100

668

760

n/a

Projects Under Advanced Development

Guadalupe Peaking Energy Center

TRE

Combined Cycle

100

—

418

n/a

Mankato Power Plant Expansion

MRO

Combined Cycle

100

280

345

n/a

Total operating power plants and projects

22,924

28,110

___________


(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)	These geothermal power plants were impacted by a wildfire in September 2015.


(6)	We intend to suspend operations at our Sutter Energy Center for 2016 to assess the future of the facility.


(7)	South Point Unit 2 experienced a combustion turbine outage in the Fall of 2015 and we are currently evaluating the timing of repairs.


(8)	Pasadena is comprised of 260 MW of cogen technology and 521 MW of combined cycle (non-cogen) technology.


(9)	We suspended operations on one of the units at our Clear Lake Power Plant which reduced the baseload and peaking operating capacities by 102 MW and 92 MW, respectively. However, this unit can be restored at our discretion based on market conditions.


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


(11)	We have entered into an asset sale agreement with Duke Energy Florida, Inc. for the sale of Osprey Energy Center in January 2017.


(12)	Calpine holds a 50% partnership interest in Greenfield LP through its subsidiaries; however, it is operated by a third party.


(13)	Calpine holds a 50% partnership interest in Whitby Cogeneration through its subsidiaries; however, it is operated by Atlantic Packaging Products Ltd.


(14)	PJM has completed the interconnection study process for an additional 68 MW of planned capacity at the York 2 Energy Center and this incremental capacity cleared the 2018/2019 base residual auction.

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 either 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 Leader^TM. In 2014, 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	1.77	0.124	93.0%
Acid rain, smog and fine particulate formation
Sulfur Dioxide, SO₂	2.93	0.0053	99.8%
Acid rain and fine particulate formation
Mercury Compounds⁽³⁾	0.00002	—	100%
Neurotoxin
Carbon Dioxide, CO₂	1,761	860	51.2%
Principal GHG—contributor to climate change

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(1)	The average U.S. coal-, oil- and natural gas-fired power plants’ emission rates were obtained from the U.S. Department of Energy’s Electric Power Annual Report for 2013. Emission rates are based on 2013 emissions and net generation. The U.S. Department of Energy has not yet released 2014 information.


(2)	Our natural gas-fired, combined-cycle power plant estimated emission rates are based on our 2013 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 2013. Emission rates are based on 2013 emissions and net generation from U.S. Department of Energy’s Electric Power Annual Report for 2013.

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 97.2% less CO2. There are 16 active geothermal power plants located in The Geysers region of northern California. We own and operate 14 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 12 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 one 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 Air Emissions Regulations

CAA

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. In addition to regulation of air emissions at the federal level, a number of states in which we do business implement regulations that go beyond federal environmental requirements. We continue to monitor and actively participate in federal and state 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 HAPs from specific industrial sectors. The EPA also regulates emissions of certain pollutants that affect visibility in national parks and wilderness areas (“Regional Haze”). Finally, the EPA has begun regulating GHG emissions from various industries, including the power sector.

CAA regulations primarily impact higher-emitting units in the national power generating fleet. Our commitment to environmental stewardship is reflected in our history of investing in low-emitting power plant technologies. As a result, these regulations generally do not have a meaningful, direct adverse impact on our generating fleet, although they may impose significant costs on the power industry overall. As a result, 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.

NAAQS — Ozone

As part of its ongoing CAA obligation to periodically review NAAQS to ensure that air quality is protective of human health and the environment, on October 1, 2015, the EPA set a new standard for ground-level of ozone of 70 parts per billion, down from the standard set in 2008 of 75 parts per billion. This is significant to the power sector because ground-level ozone is a product of complex chemical reactions contributed to by nitrogen oxides, or NOx, which are one of the primary emissions of concern from power plants.

Air quality in the Houston area, where seven of our power plants are located, has improved over the last two decades. As a result, the Houston area was determined by the EPA to be attaining the 1-hour ozone standard, effective November 19, 2015, and the 1997 8-hour ozone standard, effective January 29, 2016. Nevertheless, the Houston area remains in nonattainment relative to the 2008 ozone standard. The area’s status has not yet been determined for the 2015 ozone standard, but is likely to be in nonattainment as well, which could lead to further, more stringent regulation of NOx emissions from mobile sources and a number of industry sources, particularly the power industry.

Pursuant to authority granted under the CAA, the TCEQ adopted regulations to attain the earlier NAAQS for ozone including 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. Due to the more stringent ozone standard promulgated in 2015, 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 program changes are proposed and finalized.

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 required further investments in emissions controls on some of our peaking power plants in the state and retirement of others for which investments were not economic. Specifically, we retired our 34 MW Cedar Energy Center, 60 MW Missouri Avenue Energy Center and 77 MW Middle Energy Center in 2015, and we installed emissions controls equipment at our 73 MW Carll’s Corner Energy Center and 67 MW Mickleton Energy Center. The implementation of the HEDD rule, and the method of compliance described above did not have a material impact on our financial condition, results of operations or cash flows.

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 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. MATS required existing coal-fired units without emissions controls 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, which many sources have successfully requested. Further, 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. Very few of these “second year” extensions have been issued. None of our facilities are subject to MATS.

MATS has been heavily litigated since its promulgation in 2012, and has been argued multiple times in the D.C. Circuit and the U.S. Supreme Court. Most recently, on June 29, 2015, the U.S. Supreme Court reversed the decision of the D.C. Circuit and remanded the case for further action. On December 15, 2015, the D.C. Circuit ruled that MATS will remain in place while the EPA corrects defects made in the rulemaking process; thus, power plants must continue to comply with MATS. Many of the announced retirements and emissions control installations undertaken to comply with MATS have already occurred.

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.

After extended litigation over several years, CSAPR became effective on January 1, 2015 as originally proposed, but with delayed compliance timelines. The D.C. Circuit heard oral arguments regarding additional remaining legal issues on February 25, 2015. On July 28, 2015, the D.C. Circuit rejected several of the broader challenges to CSAPR, and also held that some portions of CSAPR were invalid, remanding those portions of the rule to the EPA and leaving the rules in place while the EPA crafts a remedy. The court did not set a timeline for the EPA to address the invalid provisions. At this time, the ultimate outcome of this case on remand cannot be determined. However, CSAPR took effect on January 1, 2015 and remains in effect until further action by the D.C. Circuit. On December 3, 2015, the EPA published a proposal to update CSAPR budgets for NOx during the ozone season in order to address the D.C. Circuit’s remand and also to support the 2008 ozone standard. These new budgets reflect a 37% total reduction in NOx from 2014 emissions and are proposed to take effect in 2017. These revised budgets are not expected to significantly affect our fleet of power plants.

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. In the eastern U.S., regional NOx and SO2 programs like

CSAPR are considered in State Implementation Plans (“SIP”) to achieve much of the emission reductions required to reduce regional haze. However, SIPs are subject to EPA approval, and if not received, individual facilities may still be required to install additional controls under a Federal Implementation Plan (“FIP”). On January 4, 2016, the EPA finalized its rule partially disapproving Texas’ Regional Haze SIP and imposing a FIP that requires installation of SO2 emission controls on 16 units at nine coal-fired power plants in Texas. The FIP will be effective until Texas replaces it with an approvable SIP. 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

EPA’s regulation of GHG in response to the 2007 decision of the U.S. Supreme Court in Massachusetts v. EPA has been controversial and heavily litigated at every step of the regulatory process. Within the power industry, the EPA first proposed to regulate GHG emissions through the PSD and Title V programs, the two major permitting programs of the CAA.

These permitting rules were the subject of more than 60 petitions for review by industry and the states. The U.S. Supreme Court ultimately heard the case, and on June 23, 2014, rejected the PSD and Title V permitting rules in part 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. Our clean portfolio and additions thereto already meet the technology required by these rules. Therefore, we believe we are well-positioned to benefit from this regulatory development.

In January 2014, the EPA proposed New Source Performance Standards (“NSPS”) for GHG emissions from new power plants. 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. In June 2014, the EPA also proposed GHG NSPS provisions for modified and reconstructed sources.

On October 23, 2015, the EPA published the final NSPS for GHG emissions from new, modified and reconstructed power plants and the Clean Power Plan. The final Clean Power Plan requires a reduction in GHG emissions from existing power plants of 32% from 2005 levels by 2030. The Clean Power Plan provides states flexibility in meeting the emission reduction requirements including adding renewable generation and increasing dispatch of natural gas-fired generation. The Clean Power Plan will first take effect in 2022 with more modest interim reduction requirements, which will increase to the final requirements by 2030. The Clean Power Plan is structured as a set of requirements for states to implement, with such state rulemakings required in the 2016-2018 time frame. At the same time, the EPA proposed a “Federal Plan,” which is a set of regulations the EPA will impose in the event the states do not act timely. Litigation challenging the Clean Power Plan has been filed by at least 25 states and a number of industry opponents. In addition to litigation challenging the rule on the merits, several motions for stay of the rule and for expedited consideration of the appeals were also filed. On January 21, 2016, the D.C. Circuit denied the motions for stay but agreed to the expedited consideration on the merits with oral arguments scheduled for June 2, 2016. The opponents then asked the U.S. Supreme Court to issue a stay of the Clean Power Plan. On February 9, 2016, the U.S. Supreme Court issued a stay of the Clean Power Plan until the D.C. Circuit issues a ruling on the merits and through final determination in any further appeal to the U.S. Supreme Court from the D.C. Circuit decision.

Overall, we support the Clean Power Plan and believe we are well positioned to comply with its provisions. We expect the Clean Power Plan to be beneficial to Calpine.

Several states and regional organizations have developed state-specific or regional initiatives to reduce GHG emissions through mandatory programs. The most advanced programs include California’s suite of GHG policies promulgated pursuant to AB 32, including its Cap-and-Trade program, and RGGI in the Northeast. 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 PPAs, and through bilateral or exchange transactions.

NESHAP

On January 30, 2013, the EPA finalized amendments to the NESHAP for Reciprocating Internal Combustion Engines (“RICE”). The final rule created exemptions 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” (the “100-Hour Rule”)

and up to 50 hours per year in certain non-emergency situations as part of a financial arrangement with another entity (the “50-Hour Rule”).

On May 1, 2015, the D.C. Circuit vacated the RICE NESHAP 100-Hour Rule and further modified its original ruling on July 21, 2015. The EPA sought a stay of the mandate until May 1, 2016, which was granted by the D.C. Circuit on August 18, 2015. Accordingly, the 100-Hour Rule remains in effect until May 1, 2016. On September 23, 2015, at the request of the EPA, the D.C. Circuit remanded the 50-Hour rule without vacatur; therefore, the 50-Hour rule remains in effect while the EPA revises the rules to address concerns raised in the litigation. At this time we cannot predict the ultimate outcome of this court case or the EPA rulemaking.

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 one power plant in California that is located within a designated nonattainment area subject to Section 185. The relevant agency issued a regulation in 2012 to address Section 185 fee collection that exempts our facility from the obligation to pay such fees.

State Air Emissions Regulations

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 since been amended by the CARB several times.

Under the Cap-and-Trade Regulation, the first compliance period for covered entities like us 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. Covered entities must surrender compliance instruments, which include both allowances and offset credits, in an amount equivalent to their GHG emissions.

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, which can be used interchangeably, are held quarterly.

On May 22, 2014, the CARB approved its first update to the Climate Change Scoping Plan 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 the state can achieve the goal established by a 2005 executive order of reducing statewide GHG emissions to 80% below 1990 levels by 2050, including recommending the establishment of a mid-term emissions target for 2030. On April 29, 2015, California Governor Jerry Brown issued an executive order that establishes a new interim GHG reduction target of 40% below 1990 levels by 2030 and orders the CARB to update the Climate Change Scoping Plan to express the 2030 target in tons of GHG emissions.

Legislation that would enact both the 2030 and 2050 goals into law, known as Senate Bill (“SB”) 32, failed to pass in the first year of the two-year legislative session, but is expected to be reconsidered by the California Legislature in 2016. Although SB 32 has not yet been enacted into law, another bill, SB 350, which was enacted into law in 2015, requires the CPUC to adopt a process for each load-serving entity to file an integrated resource plan to ensure they meet greenhouse gas emissions reduction targets established by the CARB, in coordination with the CPUC and the California Energy Commission, for the electricity sector and each load-serving entity, which reflect the electricity sector’s percentage in achieving the economy-wide greenhouse gas emissions reductions of 40% from 1990 levels by 2030. At this time, the CARB is considering how to implement this requirement and whether the law requires it to set reduction targets for individual load-serving entities.

In April 2015, the Canadian province of Ontario announced that it would develop a Cap-and-Trade program with the aim of joining the linked California-Quebec market. Proposed regulations are expected in 2016. In December 2015, the province of Manitoba announced its intent to join the California-Quebec market. The California governor will need to make findings regarding the equivalence and enforceability of Ontario and Manitoba’s GHG emission reduction programs, and the CARB would need to adopt an amendment to the Cap-and-Trade Regulation. The governor of New York also has proposed linking RGGI, a carbon market operating in several Northeastern states, with the California program.

Overall, we support AB 32 and expect the net impact of the Cap-and-Trade Regulation to be beneficial to Calpine. We also believe we are well positioned to comply with the Cap-and-Trade Regulation.

Northeast GHG Regulation: RGGI

Nine states in the Northeast participate in RGGI, a Cap-and-Trade program, which affects our power plants in Maine, Massachusetts, New Hampshire, New York and Delaware (together emitting about 5.4 million tons of CO₂ annually).

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 2013, and is being reviewed again in 2016. The 2013 program review led to a number of changes, most significant of which was a reduction of the aggregate RGGI cap 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. At this time, it is not possible to predict the outcome of the 2016 program review.

Other Environmental Regulations

RPS

We are subject to an RPS in multiple states in which we do business. 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.

California RPS

As recently expanded by SB 350, California’s RPS requires retail power providers to generate or procure 33% and 50% of the power they sell to retail customers from renewable resources by 2020 and 2030, respectively, with intermediate targets leading up to 2020 and 2030. Behind-the-meter solar generally does not count towards California’s RPS requirements. Under California’s RPS, there are limits on different “buckets” of procurement that can be used to satisfy the RPS. Load-serving entities must satisfy a growing fraction of their compliance obligations with renewable power from resources located in California or delivered into California within the hour, such as our Geysers Assets. While the RPS generally depresses wholesale energy prices, the intermittency of many renewable resources presents operational flexibility challenges that present opportunities for natural gas-fired generation to provide capacity and ancillary services products.

Other States

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. Our retail subsidiary, Champion Energy, operates in states that have an RPS in place and is required to procure a certain amount of power from renewable sources or purchase renewable energy credits in order to comply with the RPS requirements.

Miscellaneous

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

The federal Clean Water Act establishes requirements relating to the discharge of pollutants into waters of the U.S., including from cooling water intake structures. We are required to obtain wastewater and storm water discharge permits for wastewater and runoff, respectively, for some of our power plants. We are subject to the requirements for cooling water intake

structures at one 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.

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.

Clean Water Act — Waters of the United States

On June 29, 2015, the EPA published the “Clean Water Rule: Definition of Waters of the United States Under the Clean Water Act,” which redefined and broadened the scope of Clean Water Act jurisdiction. The rule became effective on August 28, 2015. We do not anticipate that compliance with the provisions of the Clean Water Rule will have a material impact on our business.

Clean Water Act — Effluent Limit Guidelines

The EPA is required by the Clean Water Act to issue and periodically update Effluent Limit Guidelines (“ELG”) for different categories of industrial sources, including power plants. The EPA last issued power plant ELGs in the early 1980s. The EPA proposed new ELGs for the power sector in April 2013. The proposed rules would primarily be significant for coal-fired power plants, particularly wastewater from coal combustion residuals and air quality control processes. The EPA finalized the revised ELGs on September 30, 2015. These rules target waste streams from coal-fired power plants (fly ash and bottom ash transport water; wastewater from flue-gas mercury control, flue-gas desulfurization, and coal gasification processes; and leachates from combustion residual landfills and ponds) and are expected to have no direct impact on our fleet of power plants.

Safe Drinking Water Act

Part C of the Safe Drinking Water Act establishes the underground injection control program that regulates the disposal of wastes by means of deep well injection. Although geothermal production wells, which are wells that bring steam to the surface, are exempt under the Energy Policy Act of 2005 (“EPAct 2005”), we use geothermal re-injection wells to inject reclaimed wastewater back into the steam reservoir, which are subject to the underground injection control program. We believe that we are in compliance with Part C of the Safe Drinking Water Act.

Resource Conservation and Recovery Act

The Resource Conservation and Recovery Act (“RCRA”), regulates the management of solid and hazardous waste. With respect to our solid waste disposal practices at our power plants and steam fields located in The Geysers region of northern California, we are also subject to certain solid waste requirements under applicable California laws. We believe that our operations are in compliance with RCRA and related state laws.

The EPA published its final rule governing coal combustion residuals (“CCRs”) under RCRA on April 17, 2015, and the rule became effective on October 19, 2015. The rule regulates the storage and disposal of CCRs 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.

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 Reliabilit