10-K 1 cpn_10kx12312016.htm CALPINE 10-K FOR YEAR-ENDED DECEMBER 31, 2016 Document


 
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, 2016
 
 
[    ]
 
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
______________________
cpnimage1a03.jpg
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, 2016, the last business day of the registrant’s most recently completed second fiscal quarter: approximately $4,694 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: 359,054,117 shares of common stock, par value $0.001, were outstanding as of February 8, 2017.
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 2017 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, 2016
TABLE OF CONTENTS
 
 
 
 
 
 
Page
 
 
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
 
 
 
 
 
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
 
 
 
 
 
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
 
 
 
 
 
Item 15.
Item 16.
 

i



DEFINITIONS
As used in this annual report for the year ended December 31, 2016, 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 Term Loan
 
The $550 million first lien senior secured term loan, dated December 1, 2016, among Calpine Corporation, as borrower, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent and MUFG Union Bank, N.A., as collateral agent
 
 
 
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, repaid on May 31, 2016
 
 
 
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, repaid on May 31, 2016
 
 
 
2022 First Lien Notes
 
The $750 million aggregate principal amount of 6.0% senior secured notes due 2022, issued October 31, 2013
 
 
 
2023 First Lien Notes
 
The $1.2 billion aggregate principal amount of 7.875% senior secured notes due 2023, issued January 14, 2011, and partially repaid in a series of transactions on November 7, 2012, December 2, 2013, December 4, 2014, February 3, 2015, December 7, 2015 and December 19, 2016
 
 
 
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 First Lien Term Loans
 
Collectively, the 2023 First Lien Term Loan and the New 2023 First Lien Term Loan
 
 
 
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 First Lien Term Loan
 
The $1.6 billion first lien senior secured term loan, dated May 28, 2015 (as amended December 21, 2016), 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
 
 
 
2024 Senior Unsecured Notes
 
The $650 million aggregate principal amount of 5.5% senior unsecured notes due 2024, issued February 3, 2015
 
 
 
2025 Senior Unsecured Notes
 
The $1.55 billion aggregate principal amount of 5.75% senior unsecured notes due 2025, issued July 22, 2014
 
 
 
2026 First Lien Notes
 
The $625 million aggregate principal amount of 5.25% senior secured notes due 2026, issued May 31, 2016
 
 
 

ii



ABBREVIATION
 
DEFINITION
 
 
 
AB 32
 
California Assembly Bill 32
 
 
 
Accounts Receivable Sales Program
 
Receivables purchase agreement between Calpine Solutions, formerly Noble Solutions, and Calpine Receivables, formerly Noble Americas Treasury Solutions LLC, and the purchase and sale agreement between Calpine Receivables and an unaffiliated financial institution, both which allows for the revolving sale of up to $250 million in certain trade accounts receivables to third parties
 
 
 
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
 
 
 
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
 
 
 
Calpine Receivables
 
Calpine Receivables, LLC, formerly Noble Americas Treasury Solutions LLC, an indirect, wholly-owned subsidiary of Calpine, which was established as bankruptcy remote, special purpose subsidiary and is responsible for administering the Accounts Receivable Sales Program
 
 
 
Calpine Solutions
 
Calpine Energy Solutions, LLC, formerly Noble Solutions, an indirect, wholly-owned subsidiary of Calpine, which is the third largest supplier of power to commercial and industrial retail customers in the United States with customers in 19 states, including presence in California, Texas, the Mid-Atlantic and the Northeast
 
 
 
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

iii



ABBREVIATION
 
DEFINITION
 
 
 
 
 
 
CCFC Term Loans
 
Collectively, the $900 million first lien senior secured term loan and the $300 million first lien senior secured term loan entered into on May 3, 2013, and the $425 million first lien senior secured term loan entered into on February 26, 2014, between CCFC, as borrower, and Goldman Sachs Lending Partners, LLC, as administrative agent and as collateral agent, and the lenders party thereto
 
 
 
CDHI
 
Calpine Development Holdings, Inc., an indirect, wholly-owned subsidiary of Calpine
 
 
 
CFTC
 
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, New York, Delaware, Maine, Connecticut, California and the District of Columbia
 
 
 
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 $1.8 billion aggregate amount revolving credit facility credit agreement, dated as of December 10, 2010, as amended on June 27, 2013, July 30, 2014, February 8, 2016 and December 1, 2016 among Calpine Corporation, the Bank of Tokyo-Mitsubishi UFJ, Ltd., as successor administrative agent, MUFG Union Bank, N.A., as successor 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
 
 
 

iv



ABBREVIATION
 
DEFINITION
 
 
 
EBITDA
 
Net income (loss) attributable to Calpine before net (income) loss attributable to the noncontrolling interest, interest, taxes, depreciation and amortization
 
 
 
EIA
 
Energy Information Administration of the U.S. Department of Energy
 
 
 
EPA
 
U.S. Environmental Protection Agency
 
 
 
Equity Plan
 
The Amended and Restated Calpine Corporation 2008 Equity Incentive Plan
 
 
 
ERCOT
 
Electric Reliability Council of Texas
 
 
 
EWG(s)
 
Exempt wholesale generator(s)
 
 
 
Exchange Act
 
U.S. Securities Exchange Act of 1934, as amended
 
 
 
FASB
 
Financial Accounting Standards Board
 
 
 
FDIC
 
U.S. Federal Deposit Insurance Corporation
 
 
 
FERC
 
U.S. Federal Energy Regulatory Commission
 
 
 
First Lien Notes
 
Collectively, the 2022 First Lien Notes, the 2023 First Lien Notes, the 2024 First Lien Notes and the 2026 First Lien Notes
 
 
 
First Lien Term Loans
 
Collectively, the 2017 First Lien Term Loan, the 2019 First Lien Term Loan, the 2020 First Lien Term Loan, the 2023 First Lien Term Loans and the 2024 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 13 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
 
 
 
IPP(s)
 
Independent Power Producers
 
 
 
IPP Peers
 
Dynegy Inc. and NRG Energy, Inc.
 
 
 
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

v



ABBREVIATION
 
DEFINITION
 
 
 
 
 
 
KWh
 
Kilowatt hour(s), a measure of power produced, purchased or sold
 
 
 
LIBOR
 
London Inter-Bank Offered Rate
 
 
 
LTSA(s)
 
Long-Term Service Agreement(s)
 
 
 
Market Heat Rate(s)
 
The regional power price divided by the corresponding regional natural gas price
 
 
 
MATS
 
Mercury and Air Toxics Standard
 
 
 
MISO
 
Midwest ISO
 
 
 
MMBtu
 
Million Btu
 
 
 
MRO
 
Midwest Reliability Organization
 
 
 
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
 
 
 
North American Power
 
North American Power & Gas, LLC, an indirect, wholly-owned subsidiary of Calpine, which was acquired on January 17, 2017 and is a growing retail energy supplier for homes and small businesses primarily concentrated in the Northeast U.S.
 
 
 
NERC
 
North American Electric Reliability Council
 
 
 
New 2019 First Lien Term Loan
 
The $400 million first lien senior secured term loan, dated February 3, 2017, among Calpine Corporation, as borrower, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent and MUFG Union Bank, N.A., as collateral agent
 
 
 
New 2023 First Lien Term Loan
 
The $562 million first lien senior secured term loan, dated May 31, 2016, among Calpine Corporation, as borrower, the lenders party thereto, Citibank, N.A., as administrative agent and MUFG Union Bank, N.A., as collateral agent
 
 
 
Noble Solutions
 
Noble Americas Energy Solutions LLC, which was legally renamed Calpine Energy Solutions, LLC on December 1, 2016 following the completion of its acquisition by an indirect, wholly-owned subsidiary of Calpine Corporation
 
 
 
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
 
 
 

vi



ABBREVIATION
 
DEFINITION
 
 
 
OTC
 
Over-the-Counter
 
 
 
PG&E
 
Pacific Gas & Electric Company
 
 
 
PJM
 
PJM Interconnection is a RTO that coordinates the movement of wholesale electricity in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia
 
 
 
PPA(s)
 
Any term power purchase agreement or other contract for a physically settled sale (as distinguished from a financially settled future, option or other derivative or hedge transaction) of any power product, including power, capacity and/or ancillary services, in the form of a bilateral agreement or a written or oral confirmation of a transaction between two parties to a master agreement, including sales related to a tolling transaction in which the purchaser provides the fuel required by us to generate such power and we receive a variable payment to convert the fuel into power and steam
 
 
 
PSD
 
Prevention of Significant Deterioration
 
 
 
PUCT
 
Public Utility Commission of Texas
 
 
 
PUHCA 2005
 
U.S. Public Utility Holding Company Act of 2005
 
 
 
PURPA
 
U.S. Public Utility Regulatory Policies Act of 1978
 
 
 
QF(s)
 
Qualifying facility(ies), which are cogeneration facilities and certain small power production facilities eligible to be “qualifying facilities” under PURPA, provided that they meet certain power and thermal energy production requirements and efficiency standards. QF status provides an exemption from the books and records requirement of PUHCA 2005 and grants certain other benefits to the QF
 
 
 
REC(s)
 
Renewable energy credit(s)
 
 
 
Report
 
This Annual Report on Form 10-K for the year ended December 31, 2016, filed with the SEC on February 10, 2017
 
 
 
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
 
 
 

vii



ABBREVIATION
 
DEFINITION
 
 
 
SO2
 
Sulfur dioxide
 
 
 
Spark Spread(s)
 
The difference between the sales price of power per MWh and the cost of natural gas to produce it
 
 
 
Steam Adjusted Heat Rate
 
The adjusted Heat Rate for our natural gas-fired power plants, excluding peakers, calculated by dividing (a) the fuel consumed in Btu reduced by the net equivalent Btu in steam exported to a third party by (b) the KWh generated. Steam Adjusted Heat Rate is a measure of fuel efficiency, so the lower our Steam Adjusted Heat Rate, the lower our cost of generation
 
 
 
TCEQ
 
Texas Commission on Environmental Quality
 
 
 
TRE
 
Texas Reliability Entity, Inc.
 
 
 
TSR
 
Total shareholder return
 
 
 
U.S. GAAP
 
Generally accepted accounting principles in the U.S.
 
 
 
VAR
 
Value-at-risk
 
 
 
VIE(s)
 
Variable interest entity(ies)
 
 
 
WECC
 
Western Electricity Coordinating Council
 
 
 
Whitby
 
Whitby Cogeneration Limited Partnership, a 50% partnership interest between certain of our subsidiaries and a third party which operates Whitby, a 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada


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. We believe that the forward-looking statements are based upon reasonable assumptions and expectations. However, 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 from renewable sources of power, interference by states in competitive power markets through subsidies or similar support for new or existing power plants, and other 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 affect 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 counterparty and customer exposure and credit risk, including our commodity positions;
Our ability to attract, motivate and retain key employees;
Present and possible future claims, litigation and enforcement actions that may arise from noncompliance with market rules promulgated by the SEC, CFTC, FERC and other regulatory bodies; and
Other risks identified in this Report.

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

1



Where You Can Find Other Information
Our website is www.calpine.com. Information contained on our website is not part of this Report. Information that we furnish or file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to, or exhibits included in, these reports are available for download, free of charge, on our website 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.

2



PART I

Item 1.
Business
BUSINESS AND STRATEGY
Business
We are a premier competitive power company with 80 power plants primarily in the U.S. We sell the power and related services we produce to our wholesale customers who include commercial and industrial end-users, state and regional wholesale market operators, and our retail affiliates who serve retail customers. 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 customer and commercial activity, as well as through our disciplined approach to capital allocation.
Our capital allocation philosophy seeks to maximize levered cash returns to equity while maintaining a strong balance sheet. We seek to enhance shareholder value through a diverse and balanced capital allocation approach that includes portfolio management, organic or acquisitive growth, returning capital to shareholders and debt reduction. The mix of this activity shifts over time given the external market environment and the opportunity set. In the current environment, we believe that paying down debt and strengthening our balance sheet is a high return investment for our shareholders. We also 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 continue to focus on getting closer to our customers through expansion of our retail platform which began with the acquisition of Champion Energy in 2015 and was followed by the acquisitions of Calpine Solutions in late 2016 and North American Power in early 2017. Our retail portfolio has been established to provide an additional source of liquidity for our generation fleet as we hedge retail load from our wholesale generation assets as appropriate.
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, governmental and residential customers. 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 also purchase power for sale to our customers and 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 commodity contracts to hedge certain business risks and optimize our portfolio of power plants. Seasonality and weather can have a significant effect on our results of operations and are also considered in our hedging and optimization activities.
Subsequent to the completion of the sale of Osprey Energy Center on January 3, 2017 and the retirement of the Clear Lake Power Plant on February 1, 2017, our portfolio, including partnership interests, consists of 80 power plants, including one under construction, with an aggregate current generation capacity of 25,908 MW and 828 MW under construction. Inclusive of our power generation portfolio and our retail sales platforms, we serve customers in 25 states in the U.S. and in Canada and Mexico. Our fleet, including projects under construction, consists of 65 natural gas-fired combustion turbine-based plants, one fuel oil-fired steam-based plant, 13 geothermal steam turbine-based plants and one photovoltaic solar plant. In 2016, our fleet of power plants produced approximately 110 billion KWh of electric power for our customers. In addition, we are one of the largest consumers of natural gas in North America. In 2016, we consumed 839 Bcf or approximately 8% of the total estimated natural gas consumed

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for power generation in the U.S. Our retail affiliates provided approximately 65 billion KWh to customers in 2016. We 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 competitors on the basis of environmental stewardship, scale and geographical diversity. The discovery and exploitation of natural gas from shale combined with our modern, efficient and flexible 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 Eastern coal types and oil 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 and the flexibility needed to support the integration of intermittent renewable resources.
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 affecting 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.
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 effect of weather, regulatory and regional economic differences across our markets to provide more consistent financial performance.
To optimize the price received for the products that we produce, we utilize both wholesale and retail customer sales channels which include an active wholesale origination function, a residential retail channel (primarily focused in Texas and the Northeast and Mid-Atlantic regions), and channels that serve commercial and industrial end users through both brokered and direct sales.
Our principal offices are located in Houston, Texas with the principal offices of our retail affiliates located in Houston, Texas and San Diego, California. We also have 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 competitive power company in the U.S. as viewed by our employees, shareholders, customers and policy-makers as well as the communities in which our facilities are located. We seek to deliver long-term shareholder value through operational excellence at our power plants and in our customer and commercial activity, as well as through our disciplined approach to capital allocation. Our strategy to achieve this is reflected in the following five major initiatives listed below and subsequently described in further detail:
Focus on being a premier operating company;
Focus on expanding our customer sales channels;
Focus on optimizing our portfolio;
Focus on advocacy and corporate responsibility; and
Focus on disciplined capital allocation.
1.
Focus on Being 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. We operate and maintain our fleet with the objective of ensuring that our plants remain among the most flexible in the sector and are best positioned to capture value in response to grid needs, especially in light of the continued integration of intermittent renewable resources.

4



During 2016, our employees achieved a total recordable incident rate of 0.55 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 2.8% and a starting reliability of 97.9% during the year ended December 31, 2016.
During 2016, our outage services subsidiary completed 17 major inspections and eight hot gas path inspections.
For the past 16 years, our Geysers Assets have reliably generated, on average, approximately six million MWh of renewable power per year.
2.
Focus on Expanding our Customer Sales Channels — We continue to focus on getting closer to our customers through expansion of our retail platform which began with the acquisition of Champion Energy in 2015 and was followed by the acquisitions of Calpine Solutions in late 2016 and North American Power in early 2017. Our retail platform geographically and strategically complements our wholesale generation fleet by providing forward liquidity with sufficient margins. The combination of our wholesale origination and retail platforms provides Calpine access to both direct and mass market sales channels. Our direct sales efforts aim to provide our larger customers with customized products, leveraging both our successful wholesale origination efforts and Calpine Solutions’ presence among large commercial and industrial organizations to secure new contracts. Our mass market approach relies upon our expanded Champion Energy retail platform to serve the needs of both residential and smaller commercial and industrial customers across the country. We believe that our retail platform is strategically complete and are now focused on integrating it into our business and optimizing its financial performance. A summary of our more significant customer sales channel efforts and retail growth in 2016 and through the filing of this Report is as follows:
Wholesale
Our ten-year PPA with Southern California Edison for 50 MW of capacity and renewable energy from our Geysers Assets commencing in January 2018 was approved by the CPUC in the second quarter of 2016.
We entered into a new five-year PPA with USS-POSCO Industries to provide 50 MW of energy and steam from our Los Medanos Energy Center commencing in January 2017 which also provides for annual extensions through 2024.
We entered into a new five-year steam agreement, subject to certain conditions precedent, with a wholly-owned subsidiary of The Dow Chemical Company to provide steam from our Texas City Power Plant through 2021.
We entered into a new five-year PPA with a third party to provide 50 MW of capacity from our RockGen Energy Center commencing in June 2017, which increases to 100 MW of capacity commencing in June 2019.
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.
Retail
In 2016, our retail subsidiaries served approximately 65 million MWh of customer load consisting of approximately 6.5 million annualized residential customer equivalents at December 31, 2016.
During the third quarter of 2016, Champion Energy was ranked highest in customer satisfaction among Texas retail electric providers according to the J.D. Power 2016 Electric Provider Retail Customer Satisfaction Study. This is the sixth time Champion Energy has received the top ranking in the past seven years.
During 2016, Champion Energy expanded its service territory to include commercial and industrial customers in Maine, Connecticut and California.
On December 1, 2016, we completed the purchase of Calpine Solutions, formerly Noble Solutions, along with a swap contract for approximately $800 million plus approximately $350 million of net working capital at closing. We recovered approximately $250 million in cash subsequent to closing and expect to recover an additional approximately $200 million through collateral synergies and the runoff of acquired legacy hedges, substantially within the first year. Calpine Solutions is a commercial and industrial retail electricity provider with customers in 19 states in the U.S., including presence in California, Texas, the Mid-Atlantic and Northeast, where our wholesale power generation fleet is primarily concentrated. The acquisition of this best-in-class direct energy sales platform is consistent with our stated goal of getting closer to our end-use customers and expands our retail customer base, complementing our existing retail business while providing us a valuable sales channel for reaching a much greater portion of the load we seek to serve.

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On January 17, 2017, we completed the purchase of North American Power for approximately $105 million, excluding working capital and other adjustments. North American Power is a growing retail energy supplier for homes and small businesses and is primarily concentrated in the Northeast U.S. where Calpine has a substantial power generation presence and where Champion Energy has a substantial retail sales footprint that will be enhanced by the addition of North American Power, which will be integrated into our Champion Energy retail platform.
3.
Focus on Optimizing our Portfolio — Our goal is 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. During 2016 and through the filing of this Report, we strategically repositioned our portfolio by adding capacity in our core regions, divesting positions in non-core markets and retiring uneconomic plants through the following transactions:
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 and other adjustments. The addition of this modern, efficient, natural gas-fired, combined-cycle power plant increased capacity in our East segment, specifically the constrained New England market.
On April 1, 2016, we entered into an asset sale agreement for the sale of substantially all of the assets comprising our South Point Energy Center to Nevada Power Company d/b/a NV Energy for approximately $76 million plus the assumption by the purchaser of existing transmission capacity contracts with a future net present value payment obligation of approximately $112 million, approximately $9 million in remaining tribal lease costs and approximately $21 million in near-term repairs, maintenance and capital improvements to restore the power plant to full capacity. The sale is subject to certain conditions precedent, as well as federal and state regulatory approvals. This transaction supports our effort to divest non-core assets outside our strategic concentration. In December 2016, the Nevada Public Utility Commission issued an order rejecting the asset sale agreement. In January 2017, Nevada Power Company filed a motion for reconsideration of this order. In February 2017, the FERC approved Nevada Power Company’s acquisition of the South Point Energy Center. However, on February 8, 2017, the Nevada Public Utility Commission denied Nevada Power Company’s purchase of the South Point Energy Center. Nevada Power Company has the right to appeal this decision. We are also currently assessing our options; however, we do not anticipate that the denial of the sale by the Nevada Public Utility Commission will have a material effect on our financial condition, results of operations or cash flows.
During the third quarter of 2016, we filed with ERCOT to retire our 400 MW Clear Lake Power Plant. ERCOT subsequently approved our plan to discontinue operations. Built in 1985, Clear Lake utilizes an older technology. Due to growing maintenance costs and lack of adequate compensation in Texas, we retired the power plant on February 1, 2017. The book value associated with our Clear Lake Power Plant is immaterial.
On October 26, 2016, we completed the sale of our Mankato Power Plant, a 375 MW natural gas-fired, combined-cycle power plant and 345 MW expansion project under advanced development located in Minnesota, to Southern Power Company, a subsidiary of Southern Company, for $396 million, excluding working capital and other adjustments. This transaction supports our effort to divest non-core assets outside our strategic concentration.
On January 3, 2017, we completed the sale of our Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million, excluding working capital and other adjustments. This transaction supports our effort to divest non-core assets outside our strategic concentration.
In addition, our significant ongoing projects under construction and growth initiatives are discussed below:
York 2 Energy Center — York 2 Energy Center is an 828 MW dual-fuel, combined-cycle project that is 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 is under construction and the initial 760 MW of capacity cleared PJM’s last three base residual auctions with the 68 MW of incremental capacity clearing the last two base residual auctions. Due to construction delays, we are now targeting COD in late 2017.
Guadalupe Peaking Energy Center — In April 2015, we executed an agreement with Guadalupe Valley Electric Cooperative (“GVEC”) related to 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

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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.
4.
Focus on Advocacy and Corporate Responsibility — We recognize that our business is heavily influenced by laws, regulations and rules at federal, state and local levels as well as by 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 three basic areas of focus are competitive wholesale power markets, competitive retail power markets and environmental stewardship in power generation. Below are some recent examples of our advocacy efforts:
Ensuring Competitive Market Structure/Rules
Successfully advocated for the PUCT to evaluate the performance of the Operating Reserve Demand Curve, and to pursue improvements as necessary. The PUCT received several rounds of comments from Calpine and other market participants, and we are currently awaiting a decision from the agency.
Worked individually and with trade groups to remove language in the proposed federal energy bill that would have resulted in rules that could potentially undermine the PJM and ISO-NE capacity markets.
Stopping Non-Competitive/Subsidized Generation
Participated with a coalition of generators and others opposed to the sole source PPAs between regulated utilities and their unregulated generation affiliates in Ohio. In response to this opposition, the FERC decided that the contracts were not exempt from their Edgar Standard review regarding affiliate power sales restrictions and directed both utilities to submit the PPAs for review and approval prior to transacting under the contracts. As a result, both of the regulated utilities dropped their efforts.
Worked with other generators to stop legislation in Connecticut that would have provided out-of-market subsidies to the Millstone nuclear power plant. We expect this legislation to be reintroduced this year and will continue to oppose.
5.
Focus on Disciplined Capital Allocation — We seek to enhance shareholder value through optimizing our portfolio, prudently managing our balance sheet and returning capital to shareholders. We continue our disciplined approach to capital allocation, benchmarking each decision against the opportunity to repurchase shares of our own common stock. In the current environment, we believe that paying down debt and strengthening our balance sheet is a high return investment for our shareholders. We further optimized our capital structure by refinancing, redeeming or amending several of our debt instruments during the year ended December 31, 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.
In May 2016, we repaid our 2019 and 2020 First Lien Term Loans with the proceeds from our New 2023 First Lien Term Loan and 2026 First Lien Notes which extended the maturity on approximately $1.2 billion of corporate debt.
On December 1, 2016, we amended our Corporate Revolving Facility to increase the aggregate revolving loan commitments available thereunder by approximately $112 million to $1,790 million for the full term through the maturity date of June 27, 2020.
In December 2016, we used cash on hand to redeem $120 million of our 2023 First Lien Notes, plus accrued and unpaid interest.
In December 2016, we repriced our 2023 First Lien Term Loans by lowering the margin over LIBOR by 0.25% to 2.75% and extended the maturity of our 2024 First Lien Term Loan from May 2022 to January 2024.
As part of our stated goal to reduce debt and interest expense, on February 3, 2017, we issued a notice of redemption to repay the remaining $453 million of our outstanding 2023 First Lien Notes using cash on hand along with the proceeds from the New 2019 First Lien Term Loan which contains a substantially lower variable rate of LIBOR plus 1.75% per annum. We intend to repay the New 2019 First Lien Term Loan in full by the end of 2018. This accelerates debt reduction and achieves substantial annual interest savings of more than $20 million.

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THE MARKET FOR POWER
Our Power Markets and Market Fundamentals
The power industry represents one of the largest industries in the U.S. and affects nearly every aspect of our economy, with an estimated end-user market of approximately $380 billion in power sales in 2016 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.
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, governmental and residential customers. We continue to focus on getting closer to our customers through expansion of our retail platform which began with the acquisition of Champion Energy in 2015 and was followed by the acquisitions of Calpine Solutions in late 2016 and North American Power in early 2017. 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.
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.
Third, we sell RECs from our Geysers Assets in northern California. California has an RPS that requires load serving entities to have RECs for a certain percentage of their demand for the purpose of guaranteeing a certain level of renewable generation in the state 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. We also purchase RECs from other sources for resale to our customers.
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.

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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 retail channels and sell power into shorter term 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 affect 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 effect 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: 
 
2016(1)
West:
 
WECC
26.0
%
Texas:
 
TRE
15.5
%
East:
 
NPCC
22.9
%
MISO
18.0
%
PJM
28.9
%
SERC
25.8
%
FRCC
24.3
%
___________
(1)
Data source is NERC weather-normalized estimates for 2016 published in May 2016.
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, demand response may 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.

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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 6,100 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 effect 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 effect 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 $4.26/MMBtu, $2.63/MMBtu and $2.55/MMBtu during 2014, 2015 and 2016, respectively.
The availability of non-conventional natural gas supplies, in particular shale natural gas, has been the primary driver of reduced natural gas prices. Access to significant deposits of shale natural gas has altered the natural gas supply landscape in the U.S. and has had a profound effect 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 effect 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.
Beginning in the second half of 2014 and continuing 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 low of $35

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per barrel in December 2015 while moderately recovering to an average price of $44 per barrel in 2016 (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 effect 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 effect 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 affected by relatively cool summers or mild winters. However, our geographically diverse portfolio mitigates the effect 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 effect on our Commodity Margin.
Regulatory and Environmental Trends
We believe that that our fleet is generally favored by regulatory requirements for the industry to reduce air and water emissions, including those described below, given the characteristics of our power plant portfolio. Many of these trends, but not all, are positive for our portfolio of power plants:
Economic pressures continue to increase for coal-fired power generation as natural gas prices remain low and 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. Depending on how the new presidential administration approaches existing and proposed rules, 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., may need to install expensive air pollution controls or reduce or discontinue operations. 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
 
9,212

MW
 
132,279

MW
Texas:
 
 
 
 
 
 
TRE
 
4,225

MW
 
87,047

MW
East:
 
 
 
 
 
 
NPCC
 
8,503

MW
 
56,471

MW
MRO
 
4,428

MW
 
45,008

MW
RFC
 
20,408

MW
 
185,251

MW
SERC
 
24,796

MW
 
224,903

MW
FRCC
 
844

MW
 
60,818

MW
Total
 
72,416

MW

791,777

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 earn premium compensation for that flexibility;

11



however, risks also exist that renewables have the ability to lower overall wholesale power prices which could negatively affect 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. Increased renewable penetration has a particularly negative effect 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 which result from the growth of zero marginal cost renewables supply in the market. 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 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. However, certain states have taken or are considering subsidizing or otherwise providing economic support to existing, uneconomic power plants such as nuclear power plants. These efforts, if successful, could reduce the number of nuclear unit retirements that would result from currently low market prices. 
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. Performance standards for demand side resources have been made more stringent 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 many of these trends, but not all, are 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 various risk factors which could affect our business. A description of these risk factors is included under Item 1A. “Risk Factors.”
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 2016, 34% of the power generated in the U.S. was fueled by natural gas, 30% by coal, 20% by nuclear facilities and the remaining 16% 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. While the new presidential administration’s plans have not yet been announced, existing and proposed regulations continue to target lower air pollutant

12



emissions such as NOX, SO2, GHG, Hg and acid gases and also limit the use of once-through cooling and some methods of 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 increases 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 and a stable and affordable supply of natural gas, 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 is currently seen as unlikely to increase in the future. 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. Further, low power prices are challenging the economics of existing nuclear facilities, resulting in the retirement or potential retirement of certain existing nuclear generating units and triggering efforts on the part of nuclear power plant owners and stakeholders to seek out-of-market subsidies to maintain operations.
Competition from renewable generation is likely to 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, although the ultimate implementation of this rule is uncertain given the change in presidential administration. 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.
Retail electricity and natural gas is similarly a commodity-driven business with numerous industry participants. We compete against other integrated power companies, regulated utilities, other retail power providers, brokers, trading companies including those owned by financial institutions, retail load aggregators, municipalities and cooperatives to supply power and power-related products to our customers in major markets in the U.S. and Canada.
We believe our ability to compete in both wholesale and retail markets 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;
effectively utilize our sales channels to reach our customers;
accurately assess and effectively manage our risks; and
accomplish all of the above with an environmental effect 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. Our retail subsidiaries also provide us with a hedging outlet for 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

13



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 110 billion KWh of electricity in 2016 across North America and consumed approximately 839 Bcf of natural gas, making us one of the largest producers of electricity and consumers of natural gas in North America. Our retail affiliates provided approximately 65 billion KWh to customers in 2016. Our retail portfolio has been established to provide an additional source of liquidity for our generation fleet as we hedge retail load from our wholesale generation assets as appropriate.
The primary power markets in which we conduct our wholesale power 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 including our retail affiliates, commercial and industrial wholesale and retail end users, financial institutions, power trading and marketing companies, residential end users (through our retail subsidiaries) and other third parties. Our retail affiliates conduct business in 20 states including California, Texas, the Mid-Atlantic and Northeast where our wholesale power generation fleet is concentrated.
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, retail power sales including through our retail affiliates, steam sales, buying and selling standard physical power and natural gas 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 as well as retail load supply obligations, where appropriate, mostly through power and natural gas forward physical and financial transactions including retail power sales; however, we currently remain susceptible to significant price movements for 2017 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 actively managing hedge positions to lock in margin. We 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 hedging instruments to adjust the mix between our fixed and variable rate debt. To the extent eligible, our interest rate hedging instruments 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 effect 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.

14



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 significant customer information for the years ended December 31, 2016, 2015 and 2014.

15



DESCRIPTION OF OUR POWER PLANTS
cpnusmapcapture.jpg
Geographic Diversity
Dispatch Technology
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16



Power Plants in Operation
Subsequent to the completion of the sale of Osprey Energy Center on January 3, 2017 and the retirement of the Clear Lake Power Plant on February 1, 2017, we own 80 power plants, including one under construction, with an aggregate generation capacity of 25,908 MW and 828 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 22,194 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 15 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 2016 for the power plants we operate was 7,324 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 16 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: General Electric 7FA, General Electric 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 13 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 16 years, our Geysers Assets have reliably generated, on average, 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 2016.
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 14 million gallons of reclaimed water per day into the geothermal steam reservoir at The Geysers where the water is naturally heated by the Earth, creating additional steam to fuel our Geysers Assets. Approximately 12 million gallons per day are received from the Santa Rosa Geysers Recharge Project, which we developed jointly with the City of Santa Rosa, and we receive, on average, approximately two million gallons a day from The Lake County Recharge Project from Lake County. As a result of these recharge projects, MWh production has been relatively constant. We expect that, as a result of the water injection program, the reservoir at our Geysers Assets will be able to supply economic quantities of steam for the foreseeable future.

17



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 2016 is:
26% related to leases with the federal government via the Office of Natural Resources Revenue,
30% related to leases with the California State Lands Commission and
44% related to leases with private landowners/leaseholders.
In general, our geothermal leases grant us the exclusive right to drill for, produce and sell geothermal resources from these properties and the right to use the surface for all related purposes. Each lease requires the payment of annual rent until commercial quantities of geothermal resources are established. After such time, the leases require the payment of minimum advance royalties or other payments until production commences, at which time production royalties are payable on a monthly basis from 10 to 31 days (depending upon the lease terms) following the close of the production month. Such royalties and other payments are payable to landowners, state and federal agencies and others, and vary widely as to the particular lease. In general, royalties payable are calculated based upon a percentage of total gross revenue received by us associated with our geothermal leases. Each lease’s royalty calculation is based upon its percentage of revenue as calculated by its steam generated relative to the total steam generated by our Geysers Assets as a whole.
Our geothermal leases are generally for initial terms varying from five to 20 years and for so long as geothermal resources are produced and sold. A few of our geothermal leases were signed in excess of 30 years ago. Our federal leases are, in general, for an initial 10-year period with renewal clauses for an additional 40 years for a maximum of 50 years. The 50-year term expires in 2024 for the majority of our federal leases. However, our federal leases allow for a preferential right to renewal for a second 40-year term on such terms and conditions as the lessor deems appropriate if, at the end of the initial 40-year term, geothermal steam is being produced or utilized in commercial quantities. The majority of our other leases run through the economic life of our Geysers Assets and provide for renewals so long as geothermal resources are being produced or utilized, or are capable of being produced or utilized, in commercial quantities from the leased land or from land unitized with the leased land. Although we believe that we will be able to renew our leases through the economic life of our Geysers Assets on terms that are acceptable to us, it is possible that certain of our leases may not be renewed, or may be renewable only on less favorable terms.
In addition, we hold 40 geothermal leases comprising approximately 43,840 acres of federal geothermal resource lands in the Glass Mountain area in northern California, which is separate from The Geysers region. Four test production wells were drilled prior to our acquisition of these leases and we have drilled one test well since their acquisition, which produced commercial quantities of steam during flow tests. However, the properties subject to these leases have not been developed and there can be no assurance that these leases will ultimately be developed.
Other Power Generation Technologies
We also have 725 MW of older, less efficient technology at our Edge Moor Energy Center which has conventional steam turbine technology. We also have 4 MW of capacity from solar power generation technology at our Vineland Solar Energy Center in New Jersey.

18



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 February 1, 2017.
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)
 
2016
Total MWh
Generated(4)
WEST
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Geothermal
 
 
 
 
 
 
 
 
 
 
 
 
 
 
McCabe #5 & #6
 
WECC
 
CA
 
Renewable
 
100
%
 
84

 
84

 
696,123

Ridge Line #7 & #8
 
WECC
 
CA
 
Renewable
 
100
%
 
76

 
76

 
659,244

Calistoga
 
WECC
 
CA
 
Renewable
 
100
%
 
69

 
69

 
557,650

Eagle Rock
 
WECC
 
CA
 
Renewable
 
100
%
 
68

 
68

 
585,585

Big Geysers
 
WECC
 
CA
 
Renewable
 
100
%
 
61

 
61

 
603,910

Lake View
 
WECC
 
CA
 
Renewable
 
100
%
 
54

 
54

 
502,494

Quicksilver
 
WECC
 
CA
 
Renewable
 
100
%
 
53

 
53

 
254,294

Sonoma
 
WECC
 
CA
 
Renewable
 
100
%
 
53

 
53

 
242,481

Cobb Creek
 
WECC
 
CA
 
Renewable
 
100
%
 
51

 
51

 
439,944

Socrates
 
WECC
 
CA
 
Renewable
 
100
%
 
50

 
50

 
240,569

Sulphur Springs
 
WECC
 
CA
 
Renewable
 
100
%
 
47

 
47

 
487,859

Grant
 
WECC
 
CA
 
Renewable
 
100
%
 
41

 
41

 
158,948

Aidlin
 
WECC
 
CA
 
Renewable
 
100
%
 
18

 
18

 
125,287

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

 
857

 
3,434,343

Pastoria Energy Center
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
770

 
749

 
4,366,356

Hermiston Power Project
 
WECC
 
OR
 
Combined Cycle
 
100
%
 
566

 
635

 
3,179,622

Otay Mesa Energy Center
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
513

 
608

 
2,668,269

Metcalf Energy Center
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
564

 
605

 
2,709,083

Sutter Energy Center(5)
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
542

 
578

 

Los Medanos Energy Center
 
WECC
 
CA
 
Cogen
 
100
%
 
518

 
572

 
2,889,852

South Point Energy Center(6)
 
WECC
 
AZ
 
Combined Cycle
 
100
%
 
520

 
530

 

Russell City Energy Center
 
WECC
 
CA
 
Combined Cycle
 
75
%
 
429

 
464

 
585,552

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

 
309

 
153,482

Gilroy Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
141

 
18,167

Gilroy Cogeneration Plant
 
WECC
 
CA
 
Cogen
 
100
%
 
109

 
130

 
141,394

King City Cogeneration Plant
 
WECC
 
CA
 
Cogen
 
100
%
 
120

 
120

 
416,343

Wolfskill Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
48

 
16,429

Yuba City Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
30,535

Feather River Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
26,088

Creed Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
8,502

Lambie Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
9,299

Goose Haven Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
8,742

Riverview Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
18,119

King City Peaking Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
44

 
4,391

Agnews Power Plant
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
28

 
28

 
16,924

Subtotal
 
 
 
 
 
 
 
 
 
6,482

 
7,425

 
26,255,880




19



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)
 
2016
Total MWh
Generated(4)
TEXAS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deer Park Energy Center
 
TRE
 
TX
 
Cogen
 
100
%
 
1,103

 
1,204

 
6,697,711

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

 
1,000

 
5,277,381

Baytown Energy Center
 
TRE
 
TX
 
Cogen
 
100
%
 
782

 
842

 
4,563,333

Channel Energy Center
 
TRE
 
TX
 
Cogen
 
100
%
 
723

 
808

 
4,264,358

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

 
781

 
4,865,887

Bosque Energy Center
 
TRE
 
TX
 
Combined Cycle
 
100
%
 
740

 
762

 
4,586,639

Freestone Energy Center
 
TRE
 
TX
 
Combined Cycle
 
75
%
 
779

 
746

 
4,466,975

Magic Valley Generating Station
 
TRE
 
TX
 
Combined Cycle
 
100
%
 
682

 
712

 
3,198,311

Brazos Valley Power Plant
 
TRE
 
TX
 
Combined Cycle
 
100
%
 
523

 
609

 
2,858,695

Corpus Christi Energy Center
 
TRE
 
TX
 
Cogen
 
100
%
 
426

 
500

 
2,478,834

Texas City Power Plant
 
TRE
 
TX
 
Cogen
 
100
%
 
400

 
453

 
875,156

Hidalgo Energy Center
 
TRE
 
TX
 
Combined Cycle
 
78.5
%
 
392

 
374

 
2,168,654

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

 
236

 
1,230,677

Subtotal
 
 
 
 
 
 
 
 
 
8,532

 
9,027

 
47,532,611

EAST
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Bethlehem Energy Center
 
RFC
 
PA
 
Combined Cycle
 
100
%
 
1,062

 
1,130

 
5,343,008

Hay Road Energy Center
 
RFC
 
DE
 
Combined Cycle
 
100
%
 
1,039

 
1,130

 
3,858,419

Morgan Energy Center
 
SERC
 
AL
 
Cogen
 
100
%
 
720

 
807

 
4,154,885

Fore River Energy Center
 
NPCC
 
MA
 
Combined Cycle
 
100
%
 
750

 
731

 
3,840,808

Edge Moor Energy Center
 
RFC
 
DE
 
Steam Cycle
 
100
%
 

 
725

 
869,844

Granite Ridge Energy Center
 
NPCC
 
NH
 
Combined Cycle
 
100
%
 
745

 
695

 
3,221,204

York Energy Center
 
RFC
 
PA
 
Combined Cycle
 
100
%
 
519

 
565

 
1,552,415

Westbrook Energy Center
 
NPCC
 
ME
 
Combined Cycle
 
100
%
 
552

 
552

 
2,183,066

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

 
519

 
873,687

RockGen Energy Center
 
MRO
 
WI
 
Simple Cycle
 
100
%
 

 
503

 
394,661

Zion Energy Center
 
RFC
 
IL
 
Simple Cycle
 
100
%
 

 
503

 
435,494

Garrison Energy Center
 
RFC
 
DE
 
Combined Cycle
 
100
%
 
273

 
309

 
1,565,129

Pine Bluff Energy Center
 
SERC
 
AR
 
Cogen
 
100
%
 
184

 
215

 
1,205,874

Cumberland Energy Center
 
RFC
 
NJ
 
Simple Cycle
 
100
%
 

 
191

 
115,967

Kennedy International Airport Power Plant
 
NPCC
 
NY
 
Cogen
 
100
%
 
110

 
121

 
686,542

Auburndale Peaking Energy Center
 
FRCC
 
FL
 
Simple Cycle
 
100
%
 

 
117

 
22,004

Sherman Avenue Energy Center
 
RFC
 
NJ
 
Simple Cycle
 
100
%
 

 
92

 
48,823

Bethpage Energy Center 3
 
NPCC
 
NY
 
Combined Cycle
 
100
%
 
60

 
80

 
284,539

Carlls Corner Energy Center
 
RFC
 
NJ
 
Simple Cycle
 
100
%
 

 
73

 
19,265

Mickleton Energy Center
 
RFC
 
NJ
 
Simple Cycle
 
100
%
 

 
67

 
6,102

Bethpage Power Plant
 
NPCC
 
NY
 
Combined Cycle
 
100
%
 
55

 
56

 
299,586

Christiana Energy Center
 
RFC
 
DE
 
Simple Cycle
 
100
%
 

 
53

 
103

Bethpage Peaker
 
NPCC
 
NY
 
Simple Cycle
 
100
%
 

 
48

 
202,980

Stony Brook Power Plant
 
NPCC
 
NY
 
Cogen
 
100
%
 
45

 
47

 
285,091

Tasley Energy Center
 
RFC
 
VA
 
Simple Cycle
 
100
%
 

 
33

 
1,575

Whitby Cogeneration(10)
 
NPCC
 
ON
 
Cogen
 
50
%
 
25

 
25

 
198,526

Delaware City Energy Center
 
RFC
 
DE
 
Simple Cycle
 
100
%
 

 
23

 
57

West Energy Center
 
RFC
 
DE
 
Simple Cycle
 
100
%
 

 
20

 
352


20



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)
 
2016
Total MWh
Generated(4)
Bayview Energy Center
 
RFC
 
VA
 
Simple Cycle
 
100
%
 

 
12

 
3,933

Crisfield Energy Center
 
RFC
 
MD
 
Simple Cycle
 
100
%
 

 
10

 
1,467

Vineland Solar Energy Center
 
RFC
 
NJ
 
Renewable
 
100
%
 

 
4

 
5,666

Subtotal
 
 
 
 
 
 
 
 
 
6,561

 
9,456

 
31,681,072

Total operating power plants
 
79
 
 
 
 
 
 
 
21,575

 
25,908

 
105,469,563

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Power plants sold or retired during 2016 and early 2017
 
 
 
 
 
 
 
 
 
 
Mankato Power Plant
 
MRO
 
MN
 
Combined Cycle
 
100%

 
n/a

 
n/a

 
799,611

Osprey Energy Center
 
FRCC
 
FL
 
Combined Cycle
 
100%

 
n/a

 
n/a

 
2,953,901

Clear Lake Power Plant
 
TRE
 
TX
 
Cogen
 
100%

 
n/a

 
n/a

 
343,900

Subtotal
 
 
 
 
 
 
 
 
 
 
 
 
 
4,097,412

Total operating, sold and retired power plants
 
 
 
 
 
 
 
 
 
 
 
 
 
109,566,975

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Projects Under Construction and Advanced Development
Projects Under Construction
 
 
 
 
 
 
 
 
 
 
 
 
 
 
York 2 Energy Center
 
RFC
 
PA
 
Combined Cycle
 
100
%
 
736

 
828

 
n/a

Projects Under Advanced Development
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Guadalupe Peaking Energy Center(11)
 
TRE
 
TX
 
Simple Cycle
 
100
%
 

 
418

 
n/a

Total operating power plants and projects
 
 
 
 
 
 
 
 
 
22,311

 
27,154

 
 
___________
(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)
We suspended operations at our Sutter Energy Center to assess the future of the facility.
(6)
We have entered into an agreement to sell South Point Energy Center. South Point Unit 2 experienced a combustion turbine outage in the Fall of 2015 and we are currently evaluating the timing of repairs in light of the impending sale. Further, the balance of the facility is not currently operating, however, it can be operated at our discretion based on market conditions.
(7)
Pasadena is comprised of 260 MW of cogen technology and 521 MW of combined cycle (non-cogen) technology.
(8)
Freeport Energy Center is owned by Calpine; however, it is contracted and operated by The Dow Chemical Company.
(9)
Calpine holds a 50% partnership interest in Greenfield LP through its subsidiaries; however, it is operated by a third party.
(10)
Calpine holds a 50% partnership interest in Whitby Cogeneration through its subsidiaries; however, it is operated by Atlantic Packaging Products Ltd.
(11)
In accordance with a power purchase agreement, a third party will purchase a 50% ownership interest in this power plant upon achieving commercial operation.
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

21



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 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 LeaderTM. In 2015, our emissions of GHG amounted to approximately 50 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 NOx, 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
 
1.49
 
0.121
 
91.9%
Acid rain, smog and fine particulate formation
 
 
 
 
 
 
Sulfur Dioxide, SO2
 
2.08
 
0.0052
 
99.8%
Acid rain and fine particulate formation
 
 
 
 
 
 
Mercury Compounds(3)
 
0.00002
 
 
100%
Neurotoxin
 
 
 
 
 
 
Carbon Dioxide, CO2
 
1,657
 
860
 
48.1%
Principal GHG — contributor to climate change
 
 
 
 
 
 
___________
(1)
The average U.S. coal-, oil- and natural gas-fired power plants’ emission rates were obtained from the U.S. Department of Energy’s Electric Power Annual Report for 2015. Emission rates are based on 2015 emissions and net generation. The U.S. Department of Energy has not yet released 2016 information.
(2)
Our natural gas-fired, combined-cycle power plant estimated emission rates are based on our 2015 emissions and power generation data from our natural gas-fired, combined-cycle power plants (excluding combined heat power plants) as measured under the EPA reporting requirements.

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(3)
The U.S. coal-, oil- and natural gas-fired power plant air emissions of mercury compounds were obtained from the EPA Toxics Release Inventory for 2014. Emission rates are based on 2015 emissions and net generation from U.S. Department of Energy’s Electric Power Annual Report for 2015.
Geothermal Generation
Our 725 MW fleet of geothermal turbine-based power plants utilizes a natural, renewable energy source, steam from the Earth’s interior, to generate power. Since these power plants do not burn fossil fuel, they are able to produce power with negligible CO2 (the principal GHG), NOX and SO2 emissions. Compared to the average U.S. coal-, oil- and natural gas-fired power plant, our Geysers Assets emit 99.9% less NOx, 100% less SO2 and 96.5% less CO2. There are 15 active geothermal power plants located in The Geysers region of northern California. We own and operate 13 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 effect of our operations on water as a natural resource:
We receive and inject an average of approximately 14 million gallons of reclaimed water per day into the geothermal steam reservoir at The Geysers where the water is naturally heated by the Earth, creating additional steam to fuel our Geysers Assets. Approximately 12 million gallons per day are received from the Santa Rosa Geysers Recharge Project, which we developed jointly with the City of Santa Rosa, and we receive, on average, approximately two million gallons a day from The Lake County Recharge Project from Lake County. 
In our combined-cycle power plants, we use mechanical draft cooling towers, which use up to 90% less water than conventional once-through cooling systems.
Three of our power plants (Sutter Energy Center, Otay Mesa Energy Center and Fore River Energy Center) employ air cooled condensers for cooling, consuming virtually no water for cooling.
In 12 of our operating natural gas-fired power plants equipped with cooling towers, we reuse treated water from municipal treatment systems for cooling. By reusing water in these cooling towers, we avoid the usage of as much as 38 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 have an effect on our business. Some of the more significant governmental and regulatory matters that affect our business are discussed below.
Environmental Matters
In November 2016, the United States held elections which resulted in the Republican presidential candidate, Donald Trump, being elected as the 45th President of the United States and the Republican Party maintaining control of both houses of the U.S. Congress. At this time, we cannot predict the effect the result of the election will have on current or pending environmental regulations promulgated by the EPA. However, we intend to continue to advocate for reasonable regulations protecting the environment which positively benefit our competitive market position by recognizing the value of our investments in clean and efficient power generation technology.
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 have implemented regulations that go beyond current federal environmental requirements. We continue to monitor and actively participate in federal and state initiatives which further our environmental and business objectives and where we anticipate an effect on our business.

23



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 affect 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 effect on our generating fleet, although they may impose significant costs on the power industry overall.
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 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. The Houston area remains in nonattainment relative to the 2008 ozone standard, and in fact, was downgraded in overall status relative to that standard on December 14, 2016. 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.
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. On June 13, 2016, the U.S. Supreme Court denied a request to stay MATS which effectively ends the legal challenges to stop MATS from being implemented. On April 25, 2016, the EPA published in the Federal Register the final, revised “necessary and appropriate” determination to address the narrow issue for which the U.S. Supreme Court, and subsequently the D.C. Circuit, had remanded the MATS rule to the EPA for further action. This effectively addresses previous litigation related to MATS, although this action itself is now the subject of further litigation.

24



Multi-Pollutant Programs — CSAPR
Pursuant to authority granted under the CAA, the EPA has promulgated a series of regulations to reduce region-wide emissions of NOx and SO2 in the eastern U.S. The most recent of these regulations is CSAPR, which became effective on January 1, 2015. The purpose of CSAPR and predecessor regulations is to facilitate attainment of ozone and fine particulates NAAQS. These regulations have required reductions of SO2 emissions in affected states by over 70%, and NOX emissions by over 60% from 2003 levels by 2015 through Cap-and-Trade programs. Further region-wide reductions in NOx and SO2 will be required by a CSAPR update published on October 26, 2016.
CSAPR and prior regional multipollutant regulations have been heavily litigated since their inception beginning in 2002. This litigation has played out with the regional program largely remaining in place as written, with some modifications required by the courts. Specifically, the court vacated the CSAPR SO2 budgets for four states, including Alabama and Texas, and remanded the CSAPR SO2 program for those states to the EPA for correction. This action didn’t affect the CSAPR SO2 program in other states, or the CSAPR NOx program in these four states.
MATS and CSAPR primarily affect coal-fired power plants; therefore, these rules do not directly affect our 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. The Regional Haze program includes two major components: demonstration of Reasonable Further Progress, and installation of Best Achievable Retrofit Technology (“BART”). States submit State Implementation Plans (“SIP”) to the EPA for approval. These SIPs delineate all of the relevant emission controls programs in the state, and demonstrate that the state is making reasonable progress toward the Regional Haze program visibility goals. In addition, states must require the installation of a minimum level of controls that are considered cost-effective on coal- and oil-fired power plants within the state. In the eastern U.S., regional NOx and SO2 programs like CSAPR are relied upon in Regional Haze SIPs to achieve much of the required emission reductions, and are also allowed by EPA policy to substitute for the installation of BART. If the EPA does not approve a SIP, it may instead issue a Federal Implementation Plan (“FIP”), which will specify the control requirements for sources in a state. 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 at several coal-fired power plants in Texas. Litigation ensued, and the SIP disapproval and FIP are currently stayed by court action. Because the CSAPR SO2 program for Texas was vacated, the requirement to install BART for SO2 emissions is now applicable. Accordingly, the EPA proposed a FIP for BART controls on December 9, 2016. This FIP would require installation or upgrade of SO2 controls on 16 units at seven coal-fired power plants in Texas. While the ultimate outcome of these actions will not directly affect our fleet, it does have the potential to affect the power market in Texas because the affected facilities would either have to further reduce emissions or retire, although the ultimate implementation of this rule is uncertain given the change in presidential administration.
GHG Emissions
Over the past several years, the EPA has proposed and issued rules related to GHG emissions within the power sector. The new presidential administration, however, has not indicated support for some of these rules, including, most notably, the Clean Power Plan.
The 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 required 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. Litigation challenging the Clean Power Plan has been filed by at least 25 states and a number

25



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 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. Oral arguments were held on September 27, 2016 in the D.C. Circuit. 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, although the ultimate implementation of this rule is uncertain given the change in presidential administration.
In addition to federal GHG rules, 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 effect 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.
State Air Emissions Regulations
California: GHG - Cap-and-Trade Regulation
AB 32 requires the state to reduce statewide GHG emissions in reference to 1990 levels. To meet this mandate, 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.
The California Cap-and-Trade market has been linked to the GHG Cap-and-Trade market in Québec since 2014. Joint auctions of allowances issued by both jurisdictions, which can be used interchangeably, are held quarterly. The Canadian province of Ontario also began implementing its own Cap-and-Trade Program in 2017, with the goal of linking with the California- Québec market as soon as 2018. The Governor of New York has also previously announced that New York would explore the possibility of linking RGGI, a carbon market operating in nine northeastern states, with the California-Québec and Ontario markets.
In addition to the 2020 goal, California also has a long-term goal established by a 2005 executive order to reduce statewide GHG emissions to 80% below 1990 levels by 2050. Additionally, in 2015, California Governor Jerry Brown issued an executive order that establishes an interim GHG reduction target of 40% below 1990 levels by 2030 and orders the CARB to update its Climate Change Scoping Plan to express the 2030 target in tons of GHG emissions.
The 2030 target was enacted into law on September 8, 2016, when Governor Brown signed Senate Bill 32 (“SB 32”). SB 32 amends AB 32 by requiring the CARB to ensure that statewide GHG emissions are reduced to at least 40% below 1990 levels by 2030. SB 32 was joined to companion legislation, Assembly Bill 197 (“AB 197”), which Governor Brown also signed into law on September 8, 2016. AB 197 amends AB 32 to specify that CARB must prioritize emission reduction rules and regulations that result in direct emission reductions from sources of GHG emissions. While the author of AB 197 confirmed in an accompanying statement that AB 197 does not preclude the CARB from adopting market-based compliance mechanisms pursuant to AB 32, neither SB 32, nor AB 197, expressly affirms the CARB’s authority to extend the Cap-and-Trade Regulation beyond 2020.
The CARB has proposed amendments to the Cap-and-Trade Regulation that would extend the program beyond 2020 and add provisions so that its implementation can be relied upon to satisfy the requirements of the federal Clean Power Plan regulation. Due to uncertainty created by litigation currently pending at the California Court of Appeals challenging the Cap-and-Trade Regulation’s auctions as an unlawful tax and potential claims that might be brought challenging the CARB’s adoption of the proposed amendments to the Cap-and-Trade Regulation, Governor Brown proposed as part of his release of the proposed budget on January 10, 2017, legislation confirming the CARB’s authority to continue implementing the Cap-and-Trade Program’s auctions. The Governor previously announced that, if such legislation should not pass in 2017, he would seek authorization for continuation of the Cap-and-Trade Program through the voter initiative process.

26



The CARB is currently developing an update to its AB 32 Scoping Plan, laying out the strategies California will utilize to achieve the 2030 target established by SB 32, including continuation of the Cap-and-Trade Program. The CARB is also considering two alternatives to its proposed Scoping Plan scenario, one which would not include continuation of the Cap-and-Trade Program and one which would rely upon implementation of a carbon tax in lieu of the Cap-and-Trade Program.
Overall, we support AB 32 and expect the net effect of the Cap-and-Trade Regulation to be beneficial to Calpine, particularly by increasing the appeal of our Geysers Assets. 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 effect 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 in the process of being reviewed again. 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 effect to our business from this change in regulations. At this time, it is not possible to predict the outcome of the current program review.
Massachusetts: Global Warming Solutions Act
On December 16, 2016, the Massachusetts Department of Environmental Protection proposed regulations that would impose new GHG limits on power plants and other sources. These regulations are notable because they are structured as declining caps on emissions from regulated facilities with a limited allowance trading program. We are engaged in the rulemaking process, but are unable to predict the outcome of these regulations at this time. Although we view the regulations as proposed as likely to result in market distortions impeding the efficient operation of both power and emissions markets, we believe that we will be able to comply with its provisions if this regulation is finalized.
Maryland: Greenhouse Gas Emissions Reduction Act
On April 4, 2016, the Governor of Maryland signed into law the Reauthorization of the Greenhouse Gas Emissions Reduction Act which builds on the 2009 Greenhouse Gas Emissions Reduction Act that required a 25% reduction of GHG emissions from 2006 levels by 2020. The legislation requires the Maryland Department of the Environment (“MDE”), in coordination with other Maryland agencies, to develop plans, adopt regulations and implement programs to reduce GHGs. The legislation includes several “off ramps” designed to protect manufacturers and electric generators. Under the bill, the State must demonstrate MDE’s compliance plans will have a positive effect on Maryland’s economy and will protect existing manufacturing jobs.
Ontario: Climate Change Mitigation and Low-Carbon Economy Act
Ontario is implementing a new GHG law with an associated Cap-and-Trade program which became effective January 1, 2017. This program requires power generators to either acquire related CO2 allowances on their own behalf or, in most cases, the natural gas pipeline supplying the power generation facility will procure such allowances and bill the power generator in the form of a CO2 surcharge on its natural gas transportation invoice. Greenfield LP has a long-term Clean Energy Supply Contract with the IESO, successor to the Ontario Power Authority. We believe the contract contemplates and provides for the full pass-through of CO2 cost, although there have been communications from the IESO which indicate an alternative view. Greenfield LP is currently negotiating to remedy this matter. On a related note, Whitby has a PPA with the Ontario Electricity Financial Corporation, successor to Ontario Hydro. Whitby is also seeking to recover related CO2 cost being applied to its natural gas transportation invoice. As this issue is ongoing, we cannot predict the ultimate effect on our financial condition, results of operations or cash flows.
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.

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California RPS
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 raises 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 an enforceable RPS in the future. Our retail subsidiaries operate in states that have an RPS in place and are 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 effect on our operations, as none of our power plants in California utilize once-through cooling systems.
Safe Drinking Water Act
Part C of the Safe Drinking Water Act establishes the underground injection control program that regulates the disposal of wastes by means of deep well injection. Although geothermal production wells, which are wells that bring steam to the surface, are exempt under the Energy Policy Act of 2005 (“EPAct 2005”), we use geothermal re-injection wells to inject reclaimed wastewater back into the steam reservoir, which are subject to the underground injection control program. We believe that we are in compliance with Part C of the Safe Drinking Water Act.
Resource Conservation and Recovery Act
The Resource Conservation and Recovery Act (“RCRA”), regulates the management of solid and hazardous waste. With respect to our solid waste disposal practices at our power plants and steam fields located in The Geysers region of northern California, we are also subject to certain solid waste requirements under applicable California laws. We believe that our operations are in compliance with RCRA and related state laws.

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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 effect 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 approximately $1.2 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.
Pursuant to EPAct 2005, NERC has been certified by the FERC as the Electric Reliability Organization to develop and enforce reliability standards and critical infrastructure protection standards, which protect the bulk power system against potential

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disruptions from cyber and physical security breaches. The NERC standards are applicable throughout the U.S. and are subject to FERC review and approval. FERC-approved reliability standards may be enforced by FERC independently, or, alternatively, by NERC and the regional reliability organizations with frontline responsibility for auditing, investigating and otherwise ensuring compliance with reliability standards, subject to FERC oversight. The critical infrastructure protection standards focus on controlling access to critical physical and cybersecurity assets, including supervisory control and data acquisition systems for the electric grid. Compliance with these standards is mandatory. Monetary penalties of approximately $1.2 million per day per violation may be assessed for violations of the reliability and critical infrastructure protection standards.
The composition of the FERC commissioners will change as a result of the new presidential administration. Cheryl LaFleur, a Democrat, was recently named Acting Chairman of the FERC, replacing Norman Bay, another Democrat. Shortly after the LaFleur announcement, Norman Bay announced that he would resign from the FERC, effective February 3, 2017. This leaves only two commissioners at the FERC which results in a lack of quorum that is required for the commissioners to issue orders. It is expected that Chairman LaFleur will delegate authority to the FERC staff to manage some issues, but it is expected that much of the FERC’s work will be delayed until additional commissioners are named by the President and confirmed by the U.S. Senate. With new commissioners, the FERC’s focus and direction will likely change, resulting in possible changes in the FERC’s policies and rules in the future, but we cannot predict at this time the effect those changes may have on our business.
State Regulation of Power
State Public Utility Commissions, or PUC(s), have historically had broad authority to regulate both the rates charged by, and the financial activities of, electric utilities operating in their states and to promulgate regulation for implementation of PURPA. Since all of our affiliates are either QFs or EWGs, none of our affiliates are currently subject to direct rate regulation by a state PUC. However, states may assert jurisdiction over the siting and construction of power generating facilities including QFs and EWGs and, with the exception of QFs, over the issuance of securities and the sale or other transfer of assets by these facilities. State PUCs also maintain extensive control over the procurement of wholesale power by the utilities that they regulate. Many of these utilities are our customers, and agreements between us and these counterparties often require approval by state PUCs.
Power Regions
The following is a brief overview of the most significant regulatory issues affecting our business in our core power regions – CAISO, ERCOT, PJM, ISO-NE and NYISO. The CAISO market is in our West segment. The ERCOT market is in our Texas segment. The PJM, ISO-NE and NYISO markets are in our East segment.
CAISO
The majority of our power plants in our West segment are located in California, in the CAISO region. We also own one power plant in Arizona and one in Oregon.
CAISO is responsible for ensuring the safe and reliable operation of the transmission grid within the bulk of California and providing open, nondiscriminatory transmission services. CAISO maintains various markets for wholesale sales of power, differentiated by time and type of electrical service, into which our subsidiaries may sell power from time to time. These markets are subject to various controls, such as price caps and mitigation of bids when transmission constraints arise. The controls and the markets themselves are subject to regulatory change at any time.
The CPUC and CAISO continue to evaluate capacity procurement policies and products for the California power market. With the expectation of significant increases in renewables, both entities are evaluating the need for operational flexibility, including the ability to start and ramp quickly as well as the ability to operate efficiently at low output levels or cycle off. We are an active participant in these discussions and support products and policies that would provide appropriate compensation for the required attributes. As these proceedings are ongoing, we cannot predict the ultimate effect on our financial condition, results of operations or cash flows, although we believe our fleet offers many features that can, and do, provide operational flexibility to the power markets.
In July 2016, we filed a protest with the FERC in response to a complaint filed against the CAISO on June 17, 2016, by the owner of a natural gas-fired power plant located in Kern County, California (“La Paloma”). Our protest requested the FERC to reject the relief sought in the complaint as a one-off solution to a larger problem and, rather, to convene a technical conference to consider whether the California wholesale power market allows modern, efficient natural gas-fired power plants that are needed for reliability and flexibility to recover their costs, including a return of, and on, capital and to consider necessary changes to the market structure to ensure revenue adequacy. On October 3, 2016, the FERC denied our request for a technical conference but encouraged the CAISO to continue an investigation into possible compensation for generation units that are needed but otherwise uneconomic to operate. The CAISO is increasingly concerned with the premature retirement of uneconomic generation resources. It is evaluating the viability of units it deems at risk of retirement in local, reliability constrained areas through its transmission

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planning process. It is also considering modifications to the review and approval of compensation for units threatened by economic retirement, but needed for reliability under the Capacity Procurement Mechanism portion of its tariff.
ERCOT
ERCOT is the ISO that manages approximately 85% of Texas’ load and an electric grid covering about 75% of the state, overseeing transactions associated with Texas’ competitive wholesale and retail power markets. FERC does not regulate wholesale sales of power in ERCOT. The PUCT exercises regulatory jurisdiction over the rates and services of any electric utility conducting business within Texas. Our subsidiaries that own power plants in Texas have power generation company status at the PUCT, and are either EWGs or QFs and are exempt from PUCT rate regulation. ERCOT ensures resource adequacy through an energy-only model. In ERCOT, there is a market offer price cap for energy and capacity services purchased by ERCOT. Under certain market conditions, the offer cap could be lower. Our subsidiaries are subject to the offer cap rules, but only for sales of power and capacity services to ERCOT.
The PUCT is considering changes regarding its approach to resource adequacy, including price formation and scarcity pricing as operating reserves decline. ERCOT successfully launched the Operating Reserve Demand Curve (“ORDC”) functionality on June 1, 2014. This application produces a price “adder” to the clearing price of energy that increases as reserve capacity declines. The PUCT requested a review of the effectiveness of the ORDC and requested input from ERCOT and market participants, including any recommendations to improve the ORDC. The PUCT continues to consider the appropriate reliability standard that should be used to set ERCOT’s planning reserve margin. As these proceedings are ongoing and the timing of these changes is uncertain, we cannot predict the ultimate effect on our financial condition, results of operations or cash flows.
PJM
PJM operates wholesale power markets, a locationally based energy market, a forward capacity market and ancillary service markets. PJM also performs transmission planning and operation for the region. The rules and regulations affecting PJM power markets and transmission are subject to change at any time.
PJM experienced several unusual cold weather events during January 2014. PJM maintained system reliability, but the system was challenged. In order to address some of these challenges, PJM filed proposed capacity market rule changes in December 2014 which include much stronger performance incentives and more significant penalties for failure to perform during emergency power system conditions. The FERC approved PJM’s proposed changes with minor alterations. Additional risk premiums associated with the capacity market rule changes are expected to produce commensurately higher capacity market prices and appear to have done so to date. Several entities have appealed the FERC’s orders approving PJM’s capacity market rule changes. The appellate case is pending. We support PJM’s capacity market rule changes and believe that, overall, they enhance the competitiveness and reliability of the PJM power market.
In Ohio, after FirstEnergy Corp. (“FE”) submitted various proposals to the Public Utility Commission of Ohio (“PUCO”) to enhance its generation company revenue, the PUCO approved a Distribution Modernization Rider (“DMR”) for the FE utilities that results in approximately $200 million per year for three years of ratepayer subsidized payments to FE. The PUCO’s order approving the DMR has been challenged by several parties. Appeals to the Ohio Supreme Court remain pending. In a related move, the Ohio Utilities, led by American Electric Power, Inc. and FE, have indicated their intentions to advocate for some form of re-regulation in this year’s legislative session which began on January 3, 2017. Re-regulation will require enabling legislation, and to date no proposal has been made public by the utilities.
Over significant opposition, the Illinois legislature voted to approve an out-of-market nuclear subsidy scheme put forward by Exelon Corporation (“Exelon”). Zero emission credits are to be paid to Exelon’s nuclear units beginning with the planning year commencing June 1, 2017. It is expected that the legislation will be challenged in court, although we cannot predict the outcome of any possible litigation. If left unchecked, we believe these subsidies will adversely affect the power markets in PJM by artificially suppressing prices.
ISO-NE
We have three power plants in our East segment located in Massachusetts, Maine and New Hampshire, all of which participate in the regional wholesale market in which ISO-NE is the RTO. ISO-NE has broad authority over the day-to-day operation of the transmission system and, among other responsibilities, operates a day-ahead and real-time wholesale energy market, a forward capacity market and an ancillary services market.
ISO-NE has requested that the FERC approve a revised Cost of New Entry (“Net CONE”) parameter for Forward Capacity Auctions beginning in 2018 which is lower than the previous Net CONE. The potential effect on our business is currently unknown.

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In 2016, Massachusetts passed legislation mandating the issuance of Requests for Proposals for up to 2,800 MW of renewable generation including hydro and offshore wind that would be procured under long-term contracts. Massachusetts is also considering the procurement of up to 600 MW of storage resources under the provisions of the 2016 energy bill. As the provisions of the legislation are still being finalized, we cannot predict the ultimate effect on our financial condition, results of operations or cash flows.
NYISO
We have five power plants in our East segment located in New York where NYISO is the RTO which manages the transmission system in New York and operates the state’s wholesale power markets. NYISO manages both day-ahead and real-time energy markets using a locationally based marginal pricing mechanism that pays each generator the zonal marginally accepted bid price for the energy it produces.
On August 1, 2016, the New York State Public Service Commission (“PSC”) approved the Clean Energy Standard which requires 50% of the state’s generation to be produced by renewable resources by 2030. In addition, the Clean Energy Standard provides for out-of-market financial subsidies for some of the state’s existing nuclear generation facilities. In October 2016, a group of generators and our trade association, the Electric Power Supply Association, filed a lawsuit in federal court challenging the PSC’s ruling on constitution grounds. We cannot predict the outcome of that litigation, but if left unchecked, we believe these subsidies will adversely affect the power markets in NYISO by artificially suppressing prices.
Regulation of Transportation and Sale of Natural Gas
Since the majority of our power generating capacity is derived from natural gas-fired power plants, we are broadly affected by federal regulation of natural gas transportation and sales. Furthermore, one of our natural gas transportation pipelines in Texas is subject to dual jurisdiction by the FERC and the Texas Railroad Commission. This pipeline is an intrastate pipeline within the meaning of Section 2(16) of the Natural Gas Policy Act (“NGPA”). FERC regulates the rates charged by this pipeline for transportation services performed under Section 311 of the NGPA, and the Texas Railroad Commission regulates the rates and services provided by this pipeline as a gas utility in Texas. We also own a pipeline in Texas that is subject to the Texas Railroad Commission regulation as a Texas gas utility.
We also operate a proprietary pipeline system in California, which is regulated by the U.S. Department of Transportation and the Pipeline and Hazardous Materials Safety Administration with regard to safety matters. Additionally, some of our power plants own and operate short pipeline laterals that connect the natural gas-fired power plants to the North American natural gas grid. Some of these laterals are subject to state and/or federal safety regulations.
The FERC has civil penalty authority for violations of the Natural Gas Act (“NGA”) and NGPA, as well as any rule or order issued thereunder. The FERC’s regulations specifically prohibit the manipulation of the natural gas markets by making it unlawful for any entity in connection with the purchase or sale of natural gas, or the purchase or sale of transportation service under the FERC’s jurisdiction, to engage in fraudulent or deceptive practices. Similar to its penalty authority under the FPA described above, the FERC is authorized to assess a maximum civil penalty of approximately $1.2 million per violation for each day that the violation continues. The NGA and NGPA also provide for the assessment of criminal fines and imprisonment time for violations.
Federal Regulation of Futures and Other Derivatives
CFTC Regulation of Futures Transactions
The CFTC has regulatory oversight of the futures markets, including trading on NYMEX for energy, and licensed futures professionals such as brokers, clearing members and large traders. In connection with its oversight of the futures markets and NYMEX, the CFTC regularly investigates market irregularities and potential manipulation of those markets. Recent laws also give the CFTC certain powers with respect to broker-type markets referred to as “exempt commercial markets” or ECMs, including the Intercontinental Exchange. The CFTC monitors activities in the OTC, ECM and physical markets that may be undertaken for the purpose of influencing futures prices. With respect to ECMs, the CFTC exercises only light-handed regulation primarily related to trade reporting, price dissemination and record retention (including retention of fraudulent claims and allegations).
The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
CFTC Regulation of Derivatives Transactions
The Dodd-Frank Act, which was signed into law on July 21, 2010, contains a variety of provisions designed to regulate financial markets, including credit and derivatives transactions. Title VII of the Dodd-Frank Act addresses regulatory reform of the OTC derivatives market in the U.S. and significantly changes the regulatory framework of this market. Certain Title VII

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regulations have been finalized and are effective though some regulations remain subject to a delayed compliance schedule. Other key regulations have not been finalized as of this time or remain in draft form. Until all of these regulations have been finalized, the extent to which the provisions of Title VII might affect our derivatives activities cannot be completely known.
While we are closely monitoring this rulemaking process from the CFTC (including related no-action relief, interpretations and orders), we have reviewed and assessed the effect of the CFTC’s Title VII regulations on our business and related processes, and we have adjusted our internal procedures where necessary to comply with the applicable statutory law and related Title VII regulations which are effective at this time. We will continue to monitor all relevant developments and rulemaking initiatives and expect to successfully implement any new applicable requirements.
EMPLOYEES
At December 31, 2016, we employed 2,372 full-time employees, of whom 184 were represented by collective bargaining agreements. Two collective bargaining agreements, representing a total of 44 employees, will expire within one year. We have never experienced a work stoppage or a strike.
Item 1A.
Risk Factors
Commercial Operations
Our financial performance is affected by price fluctuations in the wholesale power and natural gas markets and other market factors that are beyond our control.
Market prices for power, generation capacity, ancillary services, natural gas and fuel oil are unpredictable and fluctuate substantially. Unlike most other commodities, power can only be stored on a very limited basis and generally must be produced concurrently with its use. As a result, power prices are subject to significant volatility due to supply and demand imbalances, especially in the day-ahead and spot markets. Long- and short-term power and natural gas prices may also fluctuate substantially due to other factors outside of our control, including:
increases and decreases in generation capacity in our markets, including the addition of new supplies of power as a result of the development of new power plants, expansion of existing power plants or additional transmission capacity;
changes in power transmission or fuel transportation capacity constraints or inefficiencies;
power supply disruptions, including power plant outages and transmission disruptions;
weather conditions, particularly unusually mild summers or warm winters in our market areas;
quarterly and seasonal fluctuations;
an economic downturn which could negatively affect demand for power;
changes in the supply of commodities, including but not limited to coal, natural gas and fuel oil;
changes in the demand for power or in patterns of power usage, including the potential development of demand-side management tools and practices;
development of new fuels or new technologies for the production or storage of power;
federal and state regulations and actions of the ISOs;
federal and state power, market and environmental regulation and legislation, including mandating an RPS or creating financial incentives, each resulting in new renewable energy generation capacity creating oversupply;
changes in prices related to RECs and other environmental allowance products; and
changes in capacity prices and capacity markets.
These factors have caused our operating results to fluctuate in the past and will continue to cause them to do so in the future.
Our revenues and results of operations depend on market rules, regulation and other forces beyond our control.
Our revenues and results of operations are influenced by factors that are beyond our control, including:
rate caps, price limitations and bidding rules imposed by ISOs, RTOs and other market regulators that may impair our ability to recover our costs and limit our return on our capital investments;
regulations promulgated by the FERC and the CFTC;

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sufficient liquidity in the forward commodity markets to conduct our hedging activities;
some of our competitors (mainly utilities) receive entitlement-guaranteed rates of return on their capital investments, with returns that exceed market returns and may affect our ability to sell our power at economical rates;
structure and operating characteristics of our capacity markets such as our PJM capacity auctions and our NYISO markets; and
regulations and market rules related to our RECs.
Accounting for our hedging activities may increase the volatility in our quarterly and annual financial results.
We engage in commodity-related marketing and price-risk management activities in order to economically hedge our exposure to market risk with respect to power sales from our power plants, fuel utilized by those assets and emission allowances. We generally attempt to balance our fixed-price physical and financial purchases, and sales commitments in terms of contract volumes and the timing of performance and delivery obligations through the use of financial and physical derivative contracts. These derivatives are accounted for under U.S. GAAP, which requires us to record all derivatives on the balance sheet at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. As a result, we are unable to accurately predict the effect that our risk management decisions may have on our quarterly and annual financial results.
The use of hedging agreements may not work as planned or fully protect us and could result in financial losses.
We typically enter into hedging agreements, including contracts to purchase or sell commodities at future dates and at fixed prices, in order to manage our commodity price risks. These activities, although intended to mitigate price volatility, expose us to risks related to commodity price movements, deviations in weather and other risks. When we sell power forward, we may be required to post significant amounts of cash collateral or other credit support to our counterparties, and we give up the opportunity to sell power at higher prices if spot prices are higher in the future. Further, if the values of the financial contracts change in a manner that we do not anticipate, or if a counterparty or customer fails to perform under a contract, it could harm our financial condition, results of operations and cash flows.
We do not typically hedge the entire exposure of our operations against commodity price volatility. To the extent we do not hedge against commodity price volatility, our financial condition, results of operations and cash flows may be diminished based upon adverse movement in commodity prices.
In addition, we have various internal policies and procedures designed to monitor hedging activities and positions. These policies and procedures are designed, in part, to prevent unauthorized purchases or sales of products by our employees. We cannot assure, however, that these steps will detect and prevent all violations of our Risk Management Policy, particularly if deception or other intentional misconduct is involved. A significant policy violation that is not detected could result in a material financial loss for us.
Our ability to enter into hedging agreements and manage our counterparty and customer credit risk could adversely affect us.
Our wholesale counterparties, retail customers and suppliers may experience deteriorating credit. These conditions could cause counterparties in the natural gas and power markets, particularly in the energy commodity derivative markets that we rely on for our hedging activities, to withdraw from participation in those markets. If multiple parties withdraw from those markets, market liquidity may be threatened, which in turn could adversely affect our business and create more volatility in our earnings. Additionally, these conditions may cause our counterparties or customers to seek bankruptcy protection under Chapter 11 or liquidation under Chapter 7 of the U.S. Bankruptcy Code. Our credit risk may be exacerbated to the extent collateral held by us cannot be realized or is liquidated at prices not sufficient to recover the full amount of the exposure due to us. There can be no assurance that any such losses or impairments to the carrying value of our financial assets would not materially and adversely affect our financial condition, results of operations and cash flows.
Competition in the power generation industry could adversely affect our performance.
The power generation industry is characterized by intense competition, and we encounter competition from utilities, industrial companies, marketing and trading companies and other independent power producers. This competition has put pressure on power utilities to lower their costs, including the cost of purchased power, and increasing competition in the supply of power in the future could increase this pressure. In addition, construction during the last decade has created excess power supply and higher reserve margins in the power trading markets, putting downward pressure on prices.

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Other companies we compete with may have greater liquidity, greater access to credit and other financial resources, lower cost structures, greater ability to incur losses, longer-standing relationships with customers, greater potential for profitability from ancillary services or greater flexibility in the timing of their sale of generation capacity and ancillary services than we do.
In certain situations, our PPAs and other contractual arrangements, including construction agreements, commodity contracts, maintenance agreements and other arrangements, may be terminated by the counterparty or customer and/or may allow the counterparty or customer to seek liquidated damages.
The situations that could allow a counterparty or customer to terminate the contract and/or seek liquidated damages include:
the cessation or abandonment of the development, construction, maintenance or operation of a power plant;
failure of a power plant to achieve construction milestones or commercial operation by agreed-upon deadlines;
failure of a power plant to achieve certain output or efficiency minimums;
our failure to make any of the payments owed to the counterparty or to establish, maintain, restore, extend the term of or increase any required collateral;
failure of a power plant to obtain material permits and regulatory approvals by agreed-upon deadlines;
a material breach of a representation or warranty or our failure to observe, comply with or perform any other material obligation under the contract; or
events of liquidation, dissolution, insolvency or bankruptcy.
Revenue may be reduced significantly upon expiration or termination of our PPAs.
Some of the capacity from our existing portfolio is sold under long-term PPAs that expire at various times. We seek to sell any capacity not sold under long-term PPAs, on a short-term basis as market opportunities arise. Our non-contracted capacity is generally sold on the spot market at current market prices as merchant energy. When the terms of each of our various PPAs expire, it is possible that the price paid to us for the generation of power under subsequent arrangements or in short-term markets may be significantly less than the price that had been paid to us under the PPA. Power plants without long-term PPAs involve risk and uncertainty in forecasting future demand load for merchant sales because they are exposed to market fluctuations for some or all of their generating capacity and output. A significant under- or over-estimation of load requirements may increase our operating costs. Without the benefit of long-term PPAs, we may not be able to sell any or all of the capacity from these power plants at commercially attractive rates and these power plants may not be able to operate profitably. Certain of our PPAs have values in excess of current market prices. We are at risk of loss of margins to the extent that these contracts expire or are terminated and we are unable to replace them on comparable terms. Additionally, our PPAs contain termination provisions standard to contracts in our industry such as negligence, performance default or prolonged events of force majeure.
Our retail subsidiaries may experience customer attrition or may not be able to originate new business at the same levels as in the past which could adversely affect our performance.
There is extensive competition in the retail power markets in which our retail subsidiaries operate. Competitors may offer lower prices or other incentives which may attract customers away from our retail subsidiaries. We may also face competition from a number of other energy service providers, other energy industry participants, or nationally branded providers of consumer products and services who may develop business that will compete with our retail subsidiaries.
The introduction or expansion of competing technologies for power generation and demand-side management tools could adversely affect our performance.
The power generation business has seen a substantial change in the technologies used to produce power. With federal and state incentives for the development and production of renewable sources of power, we have seen market penetration of competing technologies, such as wind, solar, and commercial-sized power storage. Additionally, the development of demand-side management tools and practices can effect peak demand requirements for some of our markets at certain times during the year. The continued development of subsidized, competing power generation technologies and significant development of demand-side management tools and practices could alter the market and price structure for power and negatively affect our financial condition, results of operations and cash flows.

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Power Operations
Our power generating operations performance involves significant risks and hazards and may be below expected levels of output or efficiency.
The operation of power plants involves risks, including the breakdown or failure of power generation equipment, transmission lines, pipelines or other equipment or processes, performance below expected levels of output or efficiency and risks related to the creditworthiness of our contract counterparties and the creditworthiness of our counterparties’ customers or other parties, such as steam hosts, with whom our counterparties have contracted. From time to time our power plants have experienced unplanned outages, including extensions of scheduled outages due to equipment breakdowns, failures or other problems which are an inherent risk of our business. Unplanned outages typically can result in lost revenues, increase our maintenance expenses and may reduce our profitability, which could have a material adverse effect on our financial condition, results of operations and cash flows.
In addition, an unplanned outage may prevent the affected power plant from performing under any applicable PPAs, commodity contracts or other contractual arrangements. Such failure may allow a counterparty to terminate an agreement and/or seek liquidated damages, and we could incur costs to cover our hedges. Although insurance is maintained to partially protect against operating risks, the proceeds of insurance may not be adequate to cover lost revenues or increased expenses. As a result, we could be unable to service principal and interest payments under, or may otherwise breach, our financing obligations, particularly with respect to the affected power plant, which could result in losing our interest in the affected power plant or, possibly, one or more other power plants.
We may be subject to future claims, litigation and enforcement.
Our power generating operations are inherently hazardous and may lead to catastrophic events, including loss of life, personal injury and destruction of property, and subject us to litigation. Natural gas is highly explosive and power generation involves hazardous activities, including acquiring, transporting and delivering fuel, operating large pieces of rotating equipment and delivering power to transmission and distribution systems. These and other hazards can cause severe damage to and destruction of property, plant and equipment and suspension of operations. In the worst circumstances, catastrophic events can cause significant personal injury or loss of life. Further, the occurrence of any one of these events may result in us being named as a defendant in lawsuits asserting claims for substantial damages. We maintain an amount of insurance protection that we consider adequate; however, we cannot provide any assurance that the insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we are subject.
Additionally, we are party to various litigation matters, including regulatory and administrative proceedings arising out of the normal course of business. We review our litigation activities and determine if an unfavorable outcome to us is considered “remote,” “reasonably possible” or “probable” as defined by U.S. GAAP. Where we have determined an unfavorable outcome is probable and is reasonably estimable, we accrue for potential litigation losses. A successful claim against us that is not fully insured could be material. The liability we may ultimately incur with respect to such litigation matters, in the event of a negative outcome, may be in excess of amounts currently accrued, if any. Where we determine an unfavorable outcome is not probable or reasonably estimable, we do not accrue for any potential litigation loss. The ultimate outcome of these litigation matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated. As a result, we give no assurance that such litigation matters would, individually or in the aggregate, not have a material adverse effect on our financial condition, results of operations or cash flows. See also Note 15 of the Notes to Consolidated Financial Statements for a description of our more significant litigation matters.
We rely on power transmission and fuel distribution facilities owned and operated by other companies.
We depend on facilities and assets that we do not own or control for the transmission to our customers of the power produced by our power plants and the distribution of natural gas fuel or fuel oil to our power plants. If these transmission and distribution systems are disrupted or capacity on those systems is inadequate, our ability to sell and deliver power products or obtain fuel may be hindered. ISOs that oversee transmission systems in regional power markets have imposed price limitations and other mechanisms to address volatility in their power markets. Existing congestion, as well as expansion of transmission systems, could affect our performance, which in turn could adversely affect our business.
Our power project development and construction activities involve risk and may not be successful.
The development and construction of power plants is subject to substantial risks. In connection with the development of a power plant, we must generally obtain:

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necessary power generation equipment;
governmental permits and approvals including environmental permits and approvals;
fuel supply and transportation agreements;
sufficient equity capital and debt financing;
power transmission agreements;
water supply and wastewater discharge agreements or permits; and
site agreements and construction contracts.
To the extent that our development and construction activities continue or expand, we may be unsuccessful on a timely and profitable basis. Although we may attempt to minimize the financial risks of these activities by securing a favorable PPA and arrangin