10-K 1 cpn_10kx12312019.htm CALPINE 10-K FOR YEAR-ENDED DECEMBER 31, 2019 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, 2019
 
 
[    ]
 
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
______________________
calpinelogoa02.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) or 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 [ ]     No [X]
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 [X]     No [ ]
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 [    ]     No [X]
Indicate by check mark whether the registrant has submitted electronically 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 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 [ ]
 
Accelerated filer  [    ]                
Non-accelerated filer  [X]
 
Smaller reporting company  [    ]
(Do not check if a smaller reporting company)
 
Emerging growth company [ ]
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]
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, 2019, the last business day of the registrant’s most recently completed second fiscal quarter: $0.
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: Calpine Corporation: 105.2 shares of common stock, par value $0.001, were outstanding as of February 24, 2020.
DOCUMENTS INCORPORATED BY REFERENCE


 




CALPINE CORPORATION AND SUBSIDIARIES
FORM 10-K
ANNUAL REPORT
For the Year Ended December 31, 2019
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, 2019, 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
 
 
 
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, repaid on April 5, 2019
 
 
 
2022 First Lien Notes
 
The $750 million aggregate principal amount of 6.0% senior secured notes due 2022, issued October 31, 2013, repaid on December 20, 2019 and January 21, 2020
 
 
 
2023 First Lien Term Loans
 
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, repaid on April 5, 2019, and 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, repaid on August 12, 2019
 
 
 
2023 Senior Unsecured Notes
 
The $1.25 billion aggregate principal amount of 5.375% senior unsecured notes due 2023, issued July 22, 2014, repaid on December 27, 2019 and January 21, 2020
 
 
 
2024 First Lien Notes
 
The $490 million aggregate principal amount of 5.875% senior secured notes due 2024, issued October 31, 2013, repaid on December 20, 2019 and January 21, 2020
 
 
 
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
 
Collectively, the $625 million aggregate principal amount of 5.25% senior secured notes due 2026, issued May 31, 2016, and the $560 million aggregate principal amount of 5.25% senior secured notes due 2026, issued on December 15, 2017
 
 
 
2026 First Lien Term Loans
 
Collectively, the $950 million first lien senior secured term loan, dated April 5, 2019, 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 and the $750 million first lien senior secured term loan, dated August 12, 2019, among Calpine Corporation, as borrower, the lending party thereto, Credit Suisse AG, Cayman Islands Branch, as administrative agent and MUFG Union Bank, N.A., as collateral agent
 
 
 
2028 First Lien Notes
 
The $1.25 billion aggregate principal amount of 4.5% senior secured notes due 2028, issued December 20, 2019
 
 
 
2028 Senior Unsecured Notes
 
The $1.4 billion aggregate principal amount of 5.125% senior unsecured notes due 2028, issued December 27, 2019
 
 
 
AB 32
 
California Assembly Bill 32
 
 
 

ii



ABBREVIATION
 
DEFINITION
 
 
 
Accounts Receivable Sales Program
 
Receivables purchase agreement between Calpine Solutions and Calpine Receivables 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
 
 
 
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
 
 
 
Board of Directors
 
Calpine Corporation Board of Directors
 
 
 
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 which is an entity that manages the power grid and operates the competitive power market in California
 
 
 
CARB
 
California Air Resources Board
 
 
 
Calpine Equity Incentive Plans
 
Calpine’s equity plans in place prior to the Merger, which provided for grants of equity awards to Calpine non-union employees and non-employee members of our Board of Directors
 
 
 
Calpine Receivables
 
Calpine Receivables, 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, an indirect, wholly-owned subsidiary of Calpine, which is a supplier of power to commercial and industrial retail customers in the United States with customers in 20 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
 
 
 
CCA
 
Community Choice Aggregators which are local governments that procure power on behalf of their residents, businesses and municipal accounts from an alternative supplier while still receiving transmission and distribution service from their existing utility
 
 
 
CCFC
 
Calpine Construction Finance Company, L.P., an indirect, wholly-owned subsidiary of Calpine
 
 
 
CCFC Term Loan
 
The $1.0 billion first lien senior secured term loan entered into on December 15, 2017 among CCFC as borrower, the lenders party thereto, and Credit Suisse AG, Cayman Islands Branch, as administrative agent and collateral agent
 
 
 

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, repaid on December 15, 2017
 
 
 
CDHI
 
Calpine Development Holdings, Inc., an indirect, wholly-owned subsidiary of Calpine
 
 
 
CFTC
 
Commodities Futures Trading Commission
 
 
 
Champion Energy
 
Champion Energy Marketing, LLC, an indirect, wholly owned subsidiary of Calpine, which owns a retail electric provider that serves residential, governmental, commercial and industrial customers in deregulated electricity markets in 14 states and the District of Columbia, including presence in California, Texas, the Mid-Atlantic and Northeast
 
 
 
Chapter 11
 
Chapter 11 of the U.S. Bankruptcy Code
 
 
 
Class B Interests
 
Partnership interests in CPN Management having the rights and obligations with respect to Class B Interests as set forth in the Second Amended and Restated Limited Partnership Agreement of CPN Management dated August 29, 2018
 
 
 
CO2
 
Carbon dioxide
 
 
 
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, commodity transmission and transportation expense, environmental compliance expenses, ancillary retail expense and realized settlements from our marketing, hedging and optimization activities including natural gas and fuel oil transactions hedging future power sales
 
 
 
Commodity Margin
 
Measure of profit that includes revenue recognized on our wholesale and retail power sales activity, electric capacity sales, REC sales, steam sales, realized settlements associated with our marketing, hedging, optimization and trading activities, fuel and purchased energy expenses, commodity transmission and transportation expenses, environmental compliance expenses and ancillary retail expense. Commodity Margin is a measure of segment profit or loss under FASB Accounting Standards Codification 280 used by our chief operating decision maker to make decisions about allocating resources to the relevant segments and assessing their performance
 
 
 
Commodity revenue
 
The sum of our revenues recognized on our wholesale and retail power sales activity, electric capacity sales, REC sales, steam sales and realized settlements from our marketing, hedging, optimization and trading activities
 
 
 
Company
 
Calpine Corporation, a Delaware corporation, and its subsidiaries
 
 
 
Corporate Revolving Facility
 
The approximately $2.0 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, December 1, 2016, September 15, 2017, October 20, 2017, March 8, 2018, May 18, 2018, April 5, 2019 and August 12, 2019 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
 
 
 
CPN Management
 
CPN Management, LP, which owns 100% of the common stock of Calpine Corporation
 
 
 
CSAPR
 
Cross-State Air Pollution Rule
 
 
 
EIA
 
Energy Information Administration of the U.S. Department of Energy
 
 
 
EPA
 
U.S. Environmental Protection Agency

iv



ABBREVIATION
 
DEFINITION
 
 
 
 
 
 
ERCOT
 
Electric Reliability Council of Texas which is an entity that manages the flow of electric power to Texas customers representing approximately 90 percent of the state’s electric load
 
 
 
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 2024 First Lien Notes, the 2026 First Lien Notes and the 2028 First Lien Notes
 
 
 
First Lien Term Loans
 
Collectively, the 2019 First Lien Term Loan, the 2023 First Lien Term Loans, the 2024 First Lien Term Loan and the 2026 First Lien Term Loans
 
 
 
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
 
 
 
IRC
 
Internal Revenue Code
 
 
 
IRS
 
U.S. Internal Revenue Service
 
 
 
ISO(s)
 
Independent System Operator(s) which is an entity that coordinates, controls and monitors the operation of an electric power system
 
 
 
ISO-NE
 
ISO New England Inc., an independent nonprofit RTO serving states in the New England area, including Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont
 
 
 
KWh
 
Kilowatt hour(s), a measure of power produced, purchased or sold
 
 
 
LIBOR
 
London Inter-Bank Offered Rate
 
 
 
LTSA(s)
 
Long-Term Service Agreement(s)
 
 
 
Lyondell
 
LyondellBasell Industries N.V.
 
 
 
Market Heat Rate(s)
 
The regional power price divided by the corresponding regional natural gas price
 
 
 
Merger
 
Merger of Volt Merger Sub, Inc. with and into Calpine pursuant to the terms of the Merger Agreement, which was consummated on March 8, 2018
 
 
 

v



ABBREVIATION
 
DEFINITION
 
 
 
Merger Agreement
 
Agreement and Plan of Merger, dated August 17, 2017, by and among Calpine Corporation, Volt Parent, LP and Volt Merger Sub, Inc.
 
 
 
MMBtu
 
Million Btu
 
 
 
MRO
 
Midwest Reliability Organization
 
 
 
MW
 
Megawatt(s), a measure of plant capacity
 
 
 
MWh
 
Megawatt hour(s), a measure of power produced, purchased or sold
 
 
 
NAAQS
 
National Ambient Air Quality Standards
 
 
 
NERC
 
North American Electric Reliability Council
 
 
 
NOL(s)
 
Net operating loss(es)
 
 
 
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 retail energy supplier for homes and small businesses primarily concentrated in the Northeast U.S.
 
 
 
NOx
 
Nitrogen oxides
 
 
 
NPCC
 
Northeast Power Coordinating Council
 
 
 
NYISO
 
New York ISO which operates competitive wholesale markets to manage the flow of electricity across New York
 
 
 
NYMEX
 
New York Mercantile Exchange
 
 
 
OCI
 
Other Comprehensive Income
 
 
 
OMEC
 
Otay Mesa Energy Center, LLC, an indirect, wholly-owned subsidiary that owns the Otay Mesa Energy Center, a 608 MW power plant located in San Diego County, California
 
 
 
OTC
 
Over-the-Counter
 
 
 
PG&E
 
Pacific Gas & Electric Company
 
 
 
PJM
 
PJM Interconnection is a RTO that coordinates the movement of wholesale electricity in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia
 
 
 
PPA(s)
 
Any term power purchase agreement or other contract for a physically settled sale (as distinguished from a financially settled future, option or other derivative or hedge transaction) of any power product, including power, capacity and/or ancillary services, in the form of a bilateral agreement or a written or oral confirmation of a transaction between two parties to a master agreement, including sales related to a tolling transaction in which the purchaser provides the fuel required by us to generate such power and we receive a variable payment to convert the fuel into power and steam
 
 
 
PSD
 
Prevention of Significant Deterioration
 
 
 
PUCT
 
Public Utility Commission of Texas
 
 
 
PUHCA 2005
 
U.S. Public Utility Holding Company Act of 2005
 
 
 
PURPA
 
U.S. Public Utility Regulatory Policies Act of 1978
 
 
 

vi



ABBREVIATION
 
DEFINITION
 
 
 
QF(s)
 
Qualifying facility(ies), which are cogeneration facilities and certain small power production facilities eligible to be “qualifying facilities” under PURPA, provided that they meet certain power and thermal energy production requirements and efficiency standards. QF status provides an exemption from the books and records requirement of PUHCA 2005 and grants certain other benefits to the QF
 
 
 
REC(s)
 
Renewable energy credit(s)
 
 
 
Report
 
This Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 24, 2020
 
 
 
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 which is an entity that coordinates, controls and monitors the operation of an electric power system and administers the transmission grid on a regional basis
 
 
 
SDG&E
 
San Diego Gas & Electric Company
 
 
 
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, the 2025 Senior Unsecured Notes and the 2028 Senior Unsecured Notes
 
 
 
SERC
 
Southeastern Electric Reliability Council
 
 
 
SO2
 
Sulfur dioxide
 
 
 
Spark Spread(s)
 
The difference between the sales price of power per MWh and the cost of natural gas to produce it
 
 
 
Steam Adjusted Heat Rate
 
The adjusted Heat Rate for our natural gas-fired power plants, excluding peakers, calculated by dividing (a) the fuel consumed in Btu reduced by the net equivalent Btu in steam exported to a third party by (b) the KWh generated. Steam Adjusted Heat Rate is a measure of fuel efficiency, so the lower our Steam Adjusted Heat Rate, the lower our cost of generation
 
 
 
Stockholders Agreement
 
Stockholders Agreement, dated March 8, 2018, by and between Calpine Corporation and CPN Management
 
 
 
TRE
 
Texas Reliability Entity, Inc.
 
 
 
U.S. GAAP
 
Generally accepted accounting principles in the U.S.
 
 
 
VAR
 
Value-at-risk
 
 
 

vii



ABBREVIATION
 
DEFINITION
 
 
 
VIE(s)
 
Variable interest entity(ies)
 
 
 
WECC
 
Western Electricity Coordinating Council
 
 
 
Whitby
 
Whitby Cogeneration Limited Partnership, a 50% partnership interest, which we sold on November 20, 2019, 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 wholesale and retail 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 Term Loans, First Lien Notes, Corporate Revolving Facility, CCFC Term Loan 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;
Extensive competition in our wholesale and retail businesses, including from renewable sources of power, interference by states in competitive power markets through subsidies or similar support for new or existing power plants, lower prices and other incentives offered by retail competitors, 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 and floods, acts of terrorism, cyber attacks or wildfires that may affect our power plants or the markets our power plants or retail operations serve and our corporate offices;
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 or if a significant customer were to seek bankruptcy protection under Chapter 11;
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, through our website. Our SEC filings, including exhibits filed therewith, are also available directly on the SEC’s website at www.sec.gov.

2



PART I

Item 1.
Business
BUSINESS AND STRATEGY
We are a premier competitive power company with 77 power plants, including one under construction, primarily in the U.S. We sell power and related services to our wholesale customers who include commercial and industrial end-users, state and regional wholesale market operators, and our retail customers. We measure our success by delivering long-term 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 value through a diverse and balanced capital allocation approach that includes portfolio management including select asset sales, organic or acquisitive growth, returning capital to owners and debt reduction. The mix of this activity shifts over time given the external market environment and the opportunity set. During the year ended December 31, 2019, we paid cash distributions to our parent, CPN Management, totaling $1.15 billion. Since the beginning of 2017 through the end of January 2020, we have reduced our total debt by approximately $1.6 billion and funded approximately $350 million of expansion/growth projects. We further optimized our capital structure by refinancing, redeeming, repricing or amending several of our debt instruments during the year ended December 31, 2019 achieving substantial annual interest savings.
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 and retail power markets in California, Texas and the Northeast and Mid-Atlantic regions 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: efficient combined-cycle power plants, which use natural gas-fired combustion turbines, and renewable geothermal conventional steam turbines. We are among the world’s largest owners and operators of industrial gas turbines as well as cogeneration power plants. Our Geysers Assets located in northern California represent the largest geothermal power generation portfolio in the U.S. as well as the largest single producing power generation asset of all renewable energy in the state of California.
We sell power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators and industrial companies, retail power providers, municipalities, CCAs and other governmental entities, power marketers as well as retail commercial, industrial, governmental and residential customers. We continue to focus on providing products and services that are beneficial to our wholesale and retail 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 and related products 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.
We assess our wholesale business on a regional basis due to the effect on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors affecting supply and demand. Our geographic reportable segments for our wholesale business are West (including geothermal), Texas and East (including Canada) and we have a separate reportable segment for our retail business.
Our wholesale power plant portfolio, including partnership interests, consists of 77 power plants, including one under construction, with an aggregate current generation capacity of 26,035 MW and 361 MW under construction. In March 2019, our York 2 Energy Center commenced commercial operations, bringing online approximately 828 MW of combined cycle, natural gas-fired capacity with dual-fuel capability. Our fleet consists of 62 natural gas-fired combustion turbine-based plants, one natural gas and fuel oil-fired steam-based plant, 13 geothermal steam turbine-based plants and one photovoltaic solar plant. Our wholesale geographic segments have an aggregate generation capacity of 7,590 MW in the West, 9,115 MW in Texas and 9,330 MW with an additional 361 MW under construction in the East. Inclusive of our power generation portfolio and our retail sales platforms, we serve customers in 23 states in the U.S. and in Canada and Mexico.

3



Our goal is to be recognized as the premier competitive power company in the U.S. as viewed by our employees, owners, customers and policy-makers as well as the communities in which our facilities are located. We seek to deliver long-term 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.
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 $398 billion in power sales in 2019 according to the EIA. 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 or retail 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 and retail power markets in the U.S. We also operate, to a lesser extent, in competitive wholesale power markets in the Southeast. In addition to our sales of electrical power to wholesale and retail customers, our power plants produce and our customers require several other products. A description of the products we provide to our customers is below:
First, we provide power to utilities, independent electric system operators and industrial companies, retail power providers, municipalities, CCAs and other governmental entities, power marketers as well as retail commercial, industrial, governmental and residential customers. 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.
Second, we provide capacity for sale to utilities, independent electric system operators and retail power providers. In various markets, retail power providers, including our affiliates, (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. Capacity auctions are held in the Northeast, Mid-Atlantic and certain Midcontinent regional markets. 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 produce RECs primarily 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.
Of the five products above, we are active not only in production but also in the procurement of four of the five (excluding steam) on behalf of our retail customers.
We also buy and sell emission allowances and credits, including those under California’s AB 32 GHG reduction program, Massachusetts’ CO2 reduction program, RGGI, the federal Acid Rain and CSAPR programs, and emission reduction credits under the federal Nonattainment New Source Review program.
Although all of the products mentioned above contribute to our financial performance and are the primary components of our Commodity Margin, the most important are our sales of wholesale power and capacity. We utilize long-term customer contracts for our power and steam sales where possible. For power and capacity that are not sold under customer contracts or longer-dated capacity auctions, we use our hedging program and retail channels and sell power into shorter term markets throughout the regions in which we participate.

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The Price and Supply of Natural Gas
Approximately 96%, or 24,915 MW, 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 is constrained, 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.
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., when electricity demand exceeds available renewable generation and natural gas prices exceed the cost of available coal generation), 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 until the point we are cheaper than any available coal on marginal economics. 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 or power prices, we could be required to post additional cash collateral or letters of credit.
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 operating and maintenance 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.

5



Regulatory and Environmental Trends
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 2019, 38% of the power generated in the U.S. was fueled by natural gas, 24% by coal, 20% by nuclear facilities and the remaining 18% 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. For a further discussion of the environmental and other governmental regulations that affect us, see “— Governmental and Regulatory Matters.”
Competition from renewable generation and energy storage is likely to continue to increase in the future. Federal and state financial incentives and RPS requirements continue to foster renewables development.
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.
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 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 majority of our risk exposures arise from our ownership and operation of power plants. Our primary risk exposures are Spark Spread, power prices, natural gas prices, capacity prices, locational price differences in power and in natural gas, natural gas transportation, electric transmission, REC prices, carbon allowance prices in California and the Northeast and other emissions credit prices. In addition to the direct risk exposure to commodity prices, we also have general market risks such as risk related to performance of our counterparties and customers and plant operating performance risk.
Our operations are commodity intensive. We produced approximately 103 billion KWh of electricity in 2019 across North America and consumed approximately 790 Bcf of natural gas, making us one of the largest producers of electricity and consumers of natural gas in North America. Additionally, our retail affiliates provided approximately 60 billion KWh to customers in 2019. We actively manage our commodity 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 subsidiaries, 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 2020 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

6



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 and retail units 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 with gains and losses reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings.
SEGMENT AND SIGNIFICANT CUSTOMER INFORMATION
See Note 18 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, 2019, 2018 and 2017.

7



DESCRIPTION OF OUR OPERATIONS
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Geographic Diversity
Dispatch Technology
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Power Plants in Operation
We own 77 power plants, including one under construction, with an aggregate generation capacity of 26,035 MW and 361 MW under construction.
Natural Gas-Fired Fleet
Our natural gas-fired power plants primarily utilize two types of designs: 1,640 MW of simple-cycle combustion turbines and 22,941 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 12 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 2019 for the power plants we operate was 7,326 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 19 years.
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. Unlike other renewable resources such as wind or sunlight, which depend on intermittent sources to generate power, geothermal power provides a consistent source of energy as evidenced by our Geysers Assets’ availability of approximately 86% in 2019, which reflects the impact of a third-party transmission outage at our Geysers Assets associated with a wildfire during the fourth quarter of 2019. The sale of RECs to customers is an important separate income stream for our Geysers Assets.
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 15 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 three million gallons a day from The Lake County Recharge Project from Lake County. As a result of these recharge projects, MWh production has been relatively constant. We expect that, as a result of the water injection program, the reservoir at our Geysers Assets will be able to supply economic quantities of steam for the foreseeable future.
We periodically review our geothermal studies to help us assess the economic life of our geothermal reserves. Our most recent geothermal reserve study was conducted in 2019. 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 2079. In reaching this conclusion, our evaluation, consistent with the due diligence study of 2019, 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 105 leases comprising approximately 28,000 acres of federal, state and private geothermal resource lands in The

9



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 2019 is:
26% related to leases with the federal government via the Office of Natural Resources Revenue,
31% related to leases with the California State Lands Commission and
43% related to leases with private landowners/leaseholders.
In general, our geothermal leases grant us the exclusive right to drill for, produce and sell geothermal resources from these properties and the right to use the surface for all related purposes. Each lease requires the payment of annual rent until commercial quantities of geothermal resources are established. After such time, the leases require the payment of minimum advance royalties or other payments until production commences, at which time production royalties are payable on a monthly basis from 10 to 31 days (depending upon the lease terms) following the close of the production month. Such royalties and other payments are payable to landowners, state and federal agencies and others, and vary widely as to the particular lease. In general, royalties payable are calculated based upon a percentage of total gross revenue received by us associated with our geothermal leases. Each lease’s royalty calculation is based upon its percentage of revenue as calculated by its steam generated relative to the total steam generated by our Geysers Assets as a whole.
Our geothermal leases are generally for initial terms varying from five to 20 years and for so long thereafter as geothermal resources are produced and sold. Most 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 four 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 and 4 MW of capacity from solar power generation technology at our Vineland Solar Energy Center in New Jersey.
Retail Operations
Our retail segment provides energy and related services to commercial, industrial, governmental and residential customers through our retail subsidiaries which consist of Calpine Solutions and Champion Energy (including North American Power). Our retail operations have an overlapping presence with our wholesale business in California, Texas and the Northeast and Mid-Atlantic regions of the U.S and provided approximately 60 billion KWh to customers in 2019 consisting of approximately 6 million annualized residential customer equivalents. Thus, our retail segment geographically and strategically complements our wholesale generation fleet providing access to forward market liquidity through both direct and mass market retail sales channels.


10



Table of Operating Power Plants and Project Under Construction
Set forth below is certain information regarding our operating power plants and project under construction at January 28, 2020.
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)
 
2019
Total MWh
Generated(4)
WEST
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Geothermal
 
 
 
 
 
 
 
 
 
 
 
 
 
 
McCabe #5 & #6
 
WECC
 
CA
 
Renewable
 
100
%
 
84

 
84

 
635,462

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

 
76

 
546,804

Calistoga
 
WECC
 
CA
 
Renewable
 
100
%
 
69

 
69

 
400,526

Eagle Rock
 
WECC
 
CA
 
Renewable
 
100
%
 
68

 
68

 
606,753

Big Geysers
 
WECC
 
CA
 
Renewable
 
100
%
 
61

 
61

 
351,745

Lake View
 
WECC
 
CA
 
Renewable
 
100
%
 
54

 
54

 
491,695

Quicksilver
 
WECC
 
CA
 
Renewable
 
100
%
 
53

 
53

 
368,140

Sonoma
 
WECC
 
CA
 
Renewable
 
100
%
 
53

 
53

 
350,221

Cobb Creek
 
WECC
 
CA
 
Renewable
 
100
%
 
51

 
51

 
350,775

Socrates
 
WECC
 
CA
 
Renewable
 
100
%
 
50

 
50

 
299,620

Sulphur Springs
 
WECC
 
CA
 
Renewable
 
100
%
 
47

 
47

 
456,099

Grant
 
WECC
 
CA
 
Renewable
 
100
%
 
41

 
41

 
244,322

Aidlin
 
WECC
 
CA
 
Renewable
 
100
%
 
18

 
18

 
106,159

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

 
857

 
3,540,562

Pastoria Energy Center
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
780

 
759

 
4,061,160

Hermiston Power Project
 
WECC
 
OR
 
Combined Cycle
 
100
%
 
566

 
635

 
4,303,231

Russell City Energy Center(5)
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
572

 
619

 
662,160

Otay Mesa Energy Center
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
513

 
608

 
751,810

Metcalf Energy Center
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
564

 
605

 
2,566,516

Sutter Energy Center
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
542

 
578

 
653,076

Los Medanos Energy Center
 
WECC
 
CA
 
Cogen
 
100
%
 
518

 
572

 
2,707,147

South Point Energy Center
 
WECC
 
AZ
 
Combined Cycle
 
100
%
 
520

 
530

 
1,883,597

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

 
309

 
216,237

Gilroy Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
141

 
26,680

Gilroy Cogeneration Plant
 
WECC
 
CA
 
Cogen
 
100
%
 
109

 
130

 
89,536

King City Cogeneration Plant
 
WECC
 
CA
 
Cogen
 
100
%
 
120

 
120

 
161,388

Wolfskill Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
48

 
7,008

Yuba City Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
28,995

Feather River Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
12,321

Creed Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
11,763

Lambie Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
12,245

Goose Haven Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
11,509

Riverview Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
47

 
20,042

King City Peaking Energy Center
 
WECC
 
CA
 
Simple Cycle
 
100
%
 

 
44

 
6,038

Agnews Power Plant
 
WECC
 
CA
 
Combined Cycle
 
100
%
 
28

 
28

 
6,613

Subtotal
 
 
 
 
 
 
 
 
 
6,635

 
7,590

 
26,947,955




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SEGMENT / Power Plant
 
NERC
Region
 
U.S. State or
Canadian
Province
 
Technology
 
Calpine
Interest
Percentage
 
Calpine Net
Interest
Baseload
(MW)(1)(3)
 
Calpine Net
Interest
With Peaking
(MW)(2)(3)
 
2019
Total MWh
Generated(4)
TEXAS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deer Park Energy Center
 
TRE
 
TX
 
Cogen
 
100
%
 
1,103

 
1,204

 
6,775,720

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

 
1,000

 
5,481,210

Baytown Energy Center
 
TRE
 
TX
 
Cogen
 
100
%
 
810

 
896

 
4,746,868

Channel Energy Center
 
TRE
 
TX
 
Cogen
 
100
%
 
732

 
817

 
4,172,535

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

 
781

 
4,266,517

Bosque Energy Center
 
TRE
 
TX
 
Combined Cycle
 
100
%
 
760

 
782

 
4,257,071

Freestone Energy Center
 
TRE
 
TX
 
Combined Cycle
 
75
%
 
779

 
746

 
5,536,148

Magic Valley Generating Station
 
TRE
 
TX
 
Combined Cycle
 
100
%
 
682

 
712

 
2,865,506

Jack A. Fusco Energy Center(7)
 
TRE
 
TX
 
Combined Cycle
 
100
%
 
523

 
609

 
2,343,664

Corpus Christi Energy Center
 
TRE
 
TX
 
Cogen
 
100
%
 
426

 
500

 
2,047,276

Texas City Power Plant
 
TRE
 
TX
 
Cogen
 
100
%
 
400

 
453

 
1,743,106

Hidalgo Energy Center
 
TRE
 
TX
 
Combined Cycle
 
78.5
%
 
397

 
379

 
2,136,301

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

 
236

 
1,092,978

Subtotal
 
 
 
 
 
 
 
 
 
8,594

 
9,115

 
47,464,900

EAST
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Bethlehem Energy Center
 
RFC
 
PA
 
Combined Cycle
 
100
%
 
960

 
1,130

 
4,721,711

Hay Road Energy Center
 
RFC
 
DE
 
Combined Cycle
 
100
%
 
931

 
1,130

 
1,473,514

York 2 Energy Center
 
RFC
 
PA
 
Combined Cycle
 
100
%
 
668

 
828

 
4,073,106

Morgan Energy Center
 
SERC
 
AL
 
Cogen
 
100
%
 
720

 
807

 
3,121,040

Fore River Energy Center
 
NPCC
 
MA
 
Combined Cycle
 
100
%
 
750

 
731

 
4,403,186

Edge Moor Energy Center
 
RFC
 
DE
 
Steam Cycle
 
100
%
 

 
725

 
146,670

Granite Ridge Energy Center
 
NPCC
 
NH
 
Combined Cycle
 
100
%
 
745

 
695

 
3,025,593

York Energy Center
 
RFC
 
PA
 
Combined Cycle
 
100
%
 
464

 
565

 
1,379,992

Westbrook Energy Center
 
NPCC
 
ME
 
Combined Cycle
 
100
%
 
552

 
552

 
958,466

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

 
519

 
1,075,167

Zion Energy Center
 
RFC
 
IL
 
Simple Cycle
 
100
%
 

 
503

 
663,766

Pine Bluff Energy Center
 
SERC
 
AR
 
Cogen
 
100
%
 
184

 
215

 
1,169,631

Cumberland Energy Center
 
RFC
 
NJ
 
Simple Cycle
 
100
%
 

 
191

 
95,697

Kennedy International Airport Power Plant
 
NPCC
 
NY
 
Cogen
 
100
%
 
110

 
121

 
483,081

Sherman Avenue Energy Center
 
RFC
 
NJ
 
Simple Cycle
 
100
%
 

 
92

 
24,265

Bethpage Energy Center 3
 
NPCC
 
NY
 
Combined Cycle
 
100
%
 
60

 
80

 
111,104

Carlls Corner Energy Center
 
RFC
 
NJ
 
Simple Cycle
 
100
%
 

 
73

 
5,911

Mickleton Energy Center
 
RFC
 
NJ
 
Simple Cycle
 
100
%
 

 
67

 
60

Bethpage Power Plant
 
NPCC
 
NY
 
Combined Cycle
 
100
%
 
55

 
56

 
195,701

Christiana Energy Center
 
RFC
 
DE
 
Simple Cycle
 
100
%
 

 
53

 
189

Bethpage Peaker
 
NPCC
 
NY
 
Simple Cycle
 
100
%
 

 
48

 
45,293

Stony Brook Power Plant
 
NPCC
 
NY
 
Cogen
 
100
%
 
45

 
47

 
288,650

Tasley Energy Center
 
RFC
 
VA
 
Simple Cycle
 
100
%
 

 
33

 
657

Delaware City Energy Center
 
RFC
 
DE
 
Simple Cycle
 
100
%
 

 
23

 
157

West Energy Center
 
RFC
 
DE
 
Simple Cycle
 
100
%
 

 
20

 
78


12



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)
 
2019
Total MWh
Generated(4)
Bayview Energy Center
 
RFC
 
VA
 
Simple Cycle
 
100
%
 

 
12

 
2,585

Crisfield Energy Center
 
RFC
 
MD
 
Simple Cycle
 
100
%
 

 
10

 
657

Vineland Solar Energy Center
 
RFC
 
NJ
 
Renewable
 
100
%
 

 
4

 
5,348

Subtotal
 
 
 
 
 
 
 
 
 
6,666

 
9,330

 
27,471,275

Total operating power plants
 
76
 
 
 
 
 
 
 
21,895

 
26,035

 
101,884,130

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Power plants sold during 2019
 
 
 
 
 
 
 
 
 
 
RockGen Energy Center
 
MRO
 
WI
 
Simple Cycle
 
100
%
 
n/a

 
n/a

 
152,712

Garrison Energy Center
 
RFC
 
DE
 
Combined Cycle
 
100
%
 
n/a

 
n/a

 
976,547

Whitby Cogeneration(10)
 
NPCC
 
ON
 
Cogen
 
50
%
 
n/a

 
n/a

 
75,260

Subtotal
 
 
 
 
 
 
 
 
 
 
 
 
 
1,204,519

Total operating and sold power plants
 
 
 
 
 
 
 
 
 
 
 
 
 
103,088,649

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Project Under Construction
Washington Parish Energy Center(11)
 
SERC
 
LA
 
Simple Cycle
 
100
%
 

 
361

 
n/a

Total operating power plants and project under construction
 
 
 
 
 
 
 
 
 
21,895

 
26,396

 
 
___________
(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)
On January 28, 2020 we purchased the 25% interest in Russell City Energy Center owned by a third party. MWh generation for 2019 reflects our net interest at the time of generation. Subsequent to the acquisition, we will reflect 100% of the results of our 619 MW Russell City Energy Center in our earnings.
(6)
Pasadena is comprised of 260 MW of cogen technology and 521 MW of combined cycle (non-cogen) technology.
(7)
Formerly our Brazos Valley Power Plant, which was renamed in December 2017.
(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)
On November 20, 2019, we sold our 50% partnership interest in Whitby Cogeneration.
(11)
A third party will purchase a 100% ownership interest in this power plant upon achieving commercial operation.
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.
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, including those by ISO/RTOs, continue to have an effect on our business. Some of the more significant governmental and regulatory matters that affect our business are discussed below.

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Power and Natural Gas Matters
Federal Regulation of Power
FERC Jurisdiction
The Federal Power Act (“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.
Our power plants, outside of ERCOT, are subject to FERC’s jurisdiction as either exempt wholesale generators (“EWGs”) under the FPA or QFs under PURPA. Most of our affiliates have been granted authority to sell power at market-based rates and have been granted certain waivers of FERC reporting and accounting regulations. However, we cannot assure that such authorities or waivers will not be revoked in the future for these affiliates.
The 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. The FERC is authorized to assess a maximum civil penalty of approximately $1.29 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 the Energy Policy Act of 2005 (“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 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 the FERC independently, or, alternatively, by the NERC and the regional reliability organizations with frontline responsibility for auditing, investigating and otherwise ensuring compliance with reliability standards, subject to the FERC’s 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 $1.29 million per day per violation may be assessed for violations of the reliability and critical infrastructure protection standards.
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 generation affiliates are either QFs or EWGs, none of them 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.
With regard to our retail sales affiliates, state PUCs have the ability to set policies that either enhance or limit customer choice. Each state that has adopted retail electric choice creates its own laws, regulations and compliance requirements which evolve over time and could impact our ability to maintain or expand retail operations.
Power Regions
The following is a brief overview of 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. These markets are constantly evolving in response to external factors that may disrupt the competitive balance within the wholesale markets.
Recently, several initiatives at the state and regional levels to provide out-of-market financial subsidies to certain generation resources in states and power regions with competitive wholesale markets threaten to undermine the operation of these power markets. Some of these initiatives have been enacted while others are currently being developed for future implementation. If these anticompetitive actions are ultimately upheld and implemented, they could adversely affect capacity and energy prices in the deregulated electricity markets which in turn could have a material adverse effect on our business prospects and financial results.

14



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 determines Resource Adequacy (“RA”) requirements for load serving entities (“LSEs”) and for specified local areas utilizing inputs from the CAISO in order to ensure the reliability of electric service in California. CPUC rules require LSEs to contract for capacity with sufficient generation resources in order to ensure capacity is available when and where it is needed. To the extent LSE’s have not procured sufficient capacity through the CPUC administered process, the CAISO will implement a backstop procurement process called the Capacity Procurement Mechanism (“CPM”) to meet its reliability needs. Currently, there are active proceedings at both the CAISO and CPUC which could entail changes to both the RA and CPM constructs. We do not know at this point whether these changes will be impactful to our business.
ERCOT
ERCOT is the ISO that manages approximately 90% 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.
In early 2018, the PUCT approved changes to energy price formation and scarcity pricing. These changes affect the shape of the Operating Reserve Demand Curve (“ORDC”), which produces a price “adder” to the clearing price of energy that increases as reserve capacity declines. The effect of these changes to the ORDC is to produce a more robust price signal than previously existed as reserve capacity declines.
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 over time.
On June 29, 2018, the FERC issued a decision finding PJM’s current tariff to be unjust and unreasonable due to the price-suppressive effects of out-of-market compensation provided to certain generation resources by states within the PJM market. The FERC rejected both replacement proposals submitted by PJM to address the issue and instead opted for a paper hearing to identify a reasonable replacement mechanism. PJM’s annual capacity auction, which was scheduled to be held in May 2019, has been postponed pending the issuance of a FERC decision in this proceeding.
On December 19, 2019, the FERC issued an order in the paper hearing docket, directing PJM to expand its minimum offer price rule (“MOPR”) to apply to most generators receiving a state subsidy, although certain existing resources are exempted from the MOPR requirement. For non-exempt resources receiving a state subsidy, the MOPR will be set at the net Cost of New Entry for new resources and the Net Avoidable Cost Rate for existing resources. PJM is directed to submit a compliance filing by March 18, 2020. PJM must also propose dates in this filing for when the postponed May 2019 auction will be held. PJM has indicated that several future auctions will be delayed. Multiple parties have sought rehearing of the FERC’s order. The FERC has not ruled on those rehearing requests.
In addition, subsequent to the December 19, 2019 order, several states in the PJM region have expressed interest in using the “Fixed Resource Requirement” (FRR) provisions of the PJM tariff to bilaterally contract for capacity instead of participating in PJM’s market. It is unknown at this time whether or not states will pursue this approach, and what the resulting impact on our business will be.
The Independent Market Monitor (“IMM”) for PJM filed a complaint with the FERC on February 21, 2019 alleging that a component of PJM’s Reliability Pricing Model (“RPM”) allows sellers of the Capacity Performance product (“CP”) to offer CP at prices above the competitive level, thereby potentially allowing them to exercise market power. The IMM argues that this

15



provision of the tariff is unjust and unreasonable because the tariff does not provide a mechanism for the IMM to review these offers. Additionally, the IMM argues that the tariff should be revised to lower the Market Seller Offer Cap. This change would require nearly all competitive suppliers to submit their offers to the IMM for review prior to bidding in the RPM. In response to the IMM’s complaint, Calpine joined with many other competitive suppliers to urge the FERC to reject the IMM’s proposed resolution as inconsistent with CP and, alternatively, to enhance the penalty provisions of CP. This course of action would address the IMM’s concerns and would also be more consistent with the CP design. FERC action on the IMM’s complaint is pending.
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.
In response to reliability concerns related to fuel security in the New England region, ISO-NE filed a proposal with the FERC in mid-2018 that would allow it to retain certain generators under cost-of-service RMR Contracts that it believes are necessary to ensure fuel security on the system. The only units ISO-NE has contracted with to date are Mystic Units 8 and 9 (the “Mystic Units”). Included in ISO-NE’s proposal is a requirement that the cost-of-service units participate in ISO-NE’s forward capacity auction (“FCA”) as price takers. Calpine and many other generators opposed ISO-NE’s proposal, arguing that having these generators act as price takers will suppress capacity market clearing prices. The FERC rejected the price suppression concerns and accepted ISO-NE’s filing on December 3, 2018. Several companies have sought rehearing of the FERC’s decision. The Mystic Units were price takers in the FCA 13 and 14 auctions held in February 2019 and 2020, respectively, which likely contributed to lower capacity market clearing prices.
ISO-NE concedes that treating the cost-of-service units (i.e., the Mystic Units) as price takers in the FCA suppresses clearing prices. As a result, ISO-NE filed with the FERC an interim, administrative mechanism, referred to as the Energy Inventory Program, to provide additional compensation to all generators that provide fuel security to the system during the winter months of 2023-2024 and 2024-2025. The FERC was unable to issue an order on the proposal due to a lack of quorum. Consequently, on May 28, 2019, the Energy Inventory Program became effective by operation of law. Certain stakeholders have appealed the FERC’s decision to the U.S. Court of Appeals for the District of Columbia Circuit. Briefing has not yet commenced.
Additionally, ISO-NE has committed to the FERC to develop a long-term market-based solution to incent and retain fuel secure resources and is conducting stakeholder meetings to develop a solution. ISO-NE intends to submit this long-term solution to the FERC by April 15, 2020. Stakeholder meetings are continuing.
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. NYISO also manages a forward capacity market where capacity prices are determined through auctions.
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. We own two pipelines in Texas that are subject to the Texas Railroad Commission regulation as Texas gas utilities.
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 Natural Gas Policy Act (“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 $1.29 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.

16



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).
Environmental Matters
Federal Air Emissions Regulations
CAA
The CAA provides for the regulation of air quality and air emissions, largely through state implementation of federal requirements. We believe that all of our operating power plants comply with existing federal and state performance standards mandated under the CAA. In addition to regulation of air emissions at the federal level, a number of states in which we do business 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.
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 six 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 effective September 23, 2019. The area’s status is also in nonattainment under the 2015 ozone standard, 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 Texas Commission on Environmental Quality adopted regulations to attain the earlier NAAQS for ozone including the establishment of a Cap-and-Trade program for NOx emitted by industrial sources in the Houston-Galveston-Brazoria ozone nonattainment area, including power plants. We own and operate six 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 ongoing noncompliance of the Houston-Galveston-Brazoria area with the 2008 and 2015 standards, 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.

17



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 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, which will specify the control requirements for sources in a state.
GHG Emissions
Over the past several years, the EPA has proposed and issued rules related to GHG emissions within the power sector. The current 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 generally meet the technology that would be required if they triggered PSD permitting requirements. Therefore, we believe we are well-positioned to benefit from this regulatory development.
On October 23, 2015, the EPA finalized the New Source Performance Standard (“NSPS”) for GHG emissions from new, modified and reconstructed power plants and the Clean Power Plan. On June 19, 2019, the EPA issued the Affordable Clean Energy (“ACE”) rule which replaced the Clean Power Plan. The ACE rule regulates GHG emissions from existing coal-fired power plants and establishes a “best system of emission reduction” for reducing carbon emissions. Litigation challenging the ACE rule is ongoing.
State Air Emissions Regulations
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, Massachusetts’ CO2 reduction program and RGGI in the Northeast. The evolution of these programs could have a material effect on our business.
In 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 through bilateral or exchange transactions and pursuant to the terms of PPAs.
California: GHG - Cap-and-Trade Regulation
California’s climate policies and GHG reduction targets are among the most ambitious and aggressive in the world. Assembly Bill (“AB”) 32, as amended by Senate Bill (“SB”) 32 in 2016, requires California to reduce statewide GHG emissions to 1990 levels by 2020 and to at least 40% below 1990 levels by 2030. To meet this mandate, the CARB has promulgated a suite of complementary regulatory measures, including the Cap-and-Trade Regulation and Mandatory Reporting Regulation. Covered entities, such as our power plants, must surrender compliance instruments, which include both allowances and offset credits, in an amount equivalent to their GHG emissions. AB 398, enacted in 2017, authorized extension of the Cap-and-Trade Regulation through 2030.
AB 398 required several changes in the post-2020 Cap-and-Trade Regulation, including a requirement that CARB impose a price ceiling and two reserve tiers to control the pace of price increases, as well as limitations on the percentage of offset credits that covered entities can surrender to meet their compliance obligation. In subsequently adopting regulatory amendments to implement AB 398’s mandates, the CARB adopted an initial price ceiling value for 2021 at $65, which will increase each year by

18



five percent plus the rate of inflation. Assuming an annual inflation rate of two percent, the 2030 price ceiling will approach $119, above which an unlimited number of additional metric tons will be available to covered entities if needed for compliance.
In October 2019, the United States sued California in the U.S. Court for the Eastern District of California, alleging that California’s linkage of its Cap-and-Trade program with a cap-and-trade system implemented by the Canadian province of Québec, as well as the California Cap-and-Trade Regulation’s linkage authority and regulations, violate several provisions of the U.S. Constitution relating to foreign affairs. In addition, the Utah Legislature has appropriated funding for the State of Utah to sue California in federal court challenging the California Cap-and-Trade Regulation’s treatment of imported electricity as a violation of the dormant Commerce Clause and an intrusion into FERC’s exclusive jurisdiction over the sale of electricity at wholesale in interstate commerce.
Several of our natural gas-fired power plants in California will likely remain subject to the Cap-and-Trade Regulation through 2030 as a result of passage of AB 398. If the United States’ pending challenge to the Cap-and-Trade Program were to succeed, we do not anticipate it would have any material impact on us. If the State of Utah should file a lawsuit challenging the Cap-and-Trade Regulation’s imported power provisions and, as a consequence, the CARB should be enjoined from further implementation of those provisions, it is possible that the CARB would continue applying the program’s compliance obligation to in-state electricity generation, but not to imported electricity, in which case in-state natural gas-fired power plants could be competitively disadvantaged relative to out-of-state fossil generation.
Northeast GHG Regulation: RGGI
Ten states in the Northeast participate in RGGI, a Cap-and-Trade program, which affects our power plants in Maine, Massachusetts, New Hampshire, New Jersey, New York and Delaware (together emitting about 5.1 million tons of CO2 annually). The governors of Pennsylvania and Virginia are currently taking actions to have their state join RGGI.
We receive annual allocations from New York’s long-term contract set-aside pool to cover some of the CO2 emissions attributable to our PPA at our 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.
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 annually-declining hard caps on CO2 emissions from regulated facilities. The Massachusetts Department of Environmental Protection issued a final rule on August 11, 2017, which became effective on January 1, 2018. The rule establishes an allowance trading system and auction platform. Although we view the regulations 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.
Other Environmental Regulations
RPS
We are subject to an RPS in multiple states in which we do business. Generally, an RPS requires each retail seller of electricity to include in its resource portfolio (the resources procured by the retail seller to supply its retail customers) a certain amount of power generated from renewable or clean energy resources by a certain date.
California RPS
California’s RPS requires retail power providers to generate or procure 33% and 60% 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. Beginning in 2021, load-serving entities are required to meet 65% of their compliance obligations with contracts with terms of ten years or longer. The law that increased the 2030 RPS target to 60%, SB 100, also sets a state policy that eligible renewable energy and zero-carbon resources supply 100% of all retail sales of electricity in California by 2045. While this goal is aspirational and the legislation does not establish an enforceable framework or mechanism by which it will be achieved, it will nevertheless guide procurement and planning decisions. In addition, a recently signed executive order articulates a carbon neutrality goal for the entire state, not just the electricity sector, by 2045, which is five years earlier than the existing target of reducing greenhouse gas emissions to 80% below 1990 levels. While the RPS generally depresses wholesale energy prices, the intermittency of many renewable resources raises operational flexibility challenges that present opportunities for natural

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gas-fired generation to provide capacity and ancillary services products. Additionally, the RPS could result in the retirement of non-renewable generating units creating opportunities for our fleet.
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. Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of cooling water intake structures reflect the best technology available for minimizing adverse effects on the environment. 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 many of our power plants. In addition, we are required to maintain spill prevention control and countermeasure plans for some of our power plants. We do not use once-through cooling technology at any of the power plants in our fleet. We believe that our facilities that are subject to the Clean Water Act are in compliance with applicable discharge requirements of the Clean Water Act.
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 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.
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 these 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.
EMPLOYEES
At December 31, 2019, we employed 2,256 full-time employees, of whom 179 were represented by collective bargaining agreements. Two collective bargaining agreements, representing a total of 28 employees, will expire within one year. We have never experienced a work stoppage or a strike.

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Item 1A.
Risk Factors
Commercial Operations
Our financial performance is affected by commodity price fluctuations in the wholesale and retail 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. Depending upon price risk management activity undertaken by us, a decline in market prices for power, generation capacity, and ancillary services may adversely affect our financial performance. 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;
changes in power transmission or fuel transportation capacity constraints or inefficiencies;
volatile weather conditions, particularly unusually hot or mild summers or unusually cold or warm winters in our market areas;
an economic downturn which could negatively affect demand for power;
changes in the supply of commodities utilized as fuel sources for power generation, including but not limited to coal, natural gas and fuel oil;
technological shifts resulting in changes in the demand for power or in patterns of power usage, including the potential development of demand-side management tools, expansion and technological advancements in power storage capability and the development of new fuels or new technologies for the production or storage of power;
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, the CFTC and state public utility commissions;
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 the PJM and ISO-NE capacity auctions and the NYISO and California markets; and
regulations and market rules related to our RECs.
Accounting for derivative 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 forward commodity market price risk exposure utilizing both physical and financial commodity purchases and sales commitments. Some of these contracts are accounted for as derivatives under U.S. GAAP, which requires us to record the fair value of the commitment on the balance sheet with changes in the fair value of all derivatives reflected within current period earnings. As current period earnings are impacted by non-cash mark-to-market gains/losses associated with price risk management hedges of future period activity that are accounted for as derivatives, we are unable to accurately predict the effect that our risk management decisions may have on our quarterly and annual financial results prepared in accordance with U.S. GAAP.

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The use of hedging agreements may not work as planned or fully protect us and could result in financial losses.
In accordance with internal policies and procedures designed to monitor hedging activities and positions, we 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.
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.
Extensive competition in our wholesale and retail businesses 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.
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.
Additionally, 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 businesses that will compete with our retail subsidiaries.
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;

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a material breach of a representation or warranty or our failure to observe, comply with or perform any other material obligation under the contract; or
events of liquidation, dissolution, insolvency or bankruptcy.
Revenue may be reduced significantly upon expiration or termination of our PPAs.
Some of the capacity from our existing portfolio is sold under long-term PPAs that expire at various times. We seek to extend contracts or 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. 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. If a counterparty to a PPA were to seek bankruptcy protection under Chapter 11 or liquidation under Chapter 7 of the U.S. Bankruptcy Code, they may be able to terminate the PPA. 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.
For example, our wholesale business currently has contracts with investor owned California utilities which could be affected should they be found liable for recent wildfires in California and, accordingly, incur substantial costs associated with the wildfires. 
On January 29, 2019, PG&E and PG&E Corporation each filed voluntary petitions for relief under Chapter 11. We currently have several power plants that provide energy and energy-related products to PG&E under PPAs, many of which have PG&E collateral posting requirements. Since the bankruptcy filing, we have received all material payments under the PPAs, either directly or through the application of collateral. We also currently have numerous other agreements with PG&E related to the operation of our power plants in Northern California, under which PG&E has continued to provide service since its bankruptcy filing. We cannot predict the ultimate outcome of this matter and continue to monitor the bankruptcy proceedings. However, should the outcome in the matter be unfavorable, our business may be adversely affected.
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.
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, inability to perform and potential recognition of liquidated damages owed and/or termination of existing long-term PPAs, 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.
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

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and delivering power to transmission and distribution systems. These and other hazards including, but not limited to, the risk of events such as wildfires that may affect the ability for our power plants to operate 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 Note 16 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 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.
We are currently constructing one natural gas-fired power plant and may construct other facilities in the future, including battery storage facilities. 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:
necessary power generation or storage 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 arranging adequate financing prior to the commencement of construction, the development of a power project may require us to expend significant cash sums for preliminary engineering, permitting, legal and other expenses before we can determine whether a project is feasible, economically attractive or financeable. The process for obtaining governmental permits and approvals is complicated and lengthy, often taking more than one year, and is subject to significant uncertainties. We may be unable to obtain all necessary licenses, permits, approvals and certificates for proposed projects, and completed power plants may not comply with all applicable permit conditions, statutes or regulations. In addition, regulatory compliance for the construction and operation of our power plants can be a costly and time-consuming process. Intricate and changing environmental and other regulatory requirements may necessitate substantial expenditures to obtain and maintain permits. If a project is unable to function as planned due to changing requirements, loss of required permits or regulatory status or local opposition, it may create expensive delays, extended periods of non-operation or significant loss of value in a project resulting in potential impairments.

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We may be unable to obtain an adequate supply of fuel in the future.
We obtain substantially all of our physical natural gas and fuel oil supply from third parties pursuant to arrangements that vary in term, pricing structure, firmness and delivery flexibility. Our physical natural gas and fuel oil supply arrangements must be coordinated with transportation agreements, balancing agreements, storage services, financial hedging transactions and other contracts so that the natural gas and fuel oil is delivered to our power plants at the times, in the quantities and otherwise in a manner that meets the needs of our generation portfolio and our customers. We must also comply with laws and regulations governing natural gas transportation.
Additionally, the PJM and ISO-NE power markets have recently experienced an increase in natural gas-fired generation assets that supply electricity to the area. As a result, there has been a corresponding increase in the need for natural gas transmission assets to supply the generation assets with fuel to generate power. When extreme cold temperatures rapidly increase the demand for natural gas used for residential heating, it can also create constraints on natural gas pipelines that serve power generation assets. When these conditions exist, it could interrupt the fuel supply to our natural gas-fired power plants in these power markets, although some of our natural gas-fired power plants in this region are dual-fuel and benefit from the ability to operate on both natural gas and fuel oil.
While adequate supplies of natural gas and fuel oil are currently available to us at prices we believe are reasonable for each of our power plants, we are exposed to increases in the price of natural gas and fuel oil, and it is possible that sufficient supplies to operate our portfolio profitably may not continue to be available to us. In addition, we face risks with regard to the delivery to and the use of natural gas and fuel oil by our power plants including the following:
transportation may be unavailable if pipeline infrastructure is damaged or disabled;
pipeline tariff changes may adversely affect our ability to, or cost to, deliver natural gas and fuel oil supply;
new pipelines and pipeline expansions may not be permitted in a timely manner due to environmental concerns or prolonged regulatory processes;
third-party suppliers may default on natural gas supply obligations, and we may be unable to replace supplies currently under contract;
market liquidity for physical natural gas and fuel oil or availability of natural gas and fuel oil services (e.g. storage) may be insufficient or available only at prices that are not acceptable to us;
natural gas and fuel oil quality variation may adversely affect our power plant operations;
our natural gas and fuel oil operations capability may be compromised due to various events such as natural disaster, loss of key personnel or loss of critical infrastructure;
fuel supplies diverted to residential heating for humanitarian reasons; and
any other reasons.
Our power plants and construction projects are subject to impairments.
If we were to experience a significant reduction in our expected revenues and operating cash flows for an extended period of time from a prolonged economic downturn or from advances or changes in technologies, we could experience future impairments of our power plant assets as a result. There can be no assurance that any such losses or impairments to the carrying value of our financial assets would not have a material adverse effect on our financial condition, results of operations and cash flows.
Our geothermal power reserves may be inadequate for our operations.
In connection with each geothermal power plant, we estimate the productivity of the geothermal resource and the expected decline in productivity. The productivity of a geothermal resource may decline more than anticipated, resulting in insufficient reserves being available for sustained generation of the power capacity desired. In addition, we may not be able to successfully manage the development and operation of our geothermal reservoirs or accurately estimate the quantity or productivity of our steam reserves. An incorrect estimate or inability to manage our geothermal reserves or a decline in productivity could adversely affect our results of operations or financial condition. In addition, the development and operation of geothermal power resources are subject to substantial risks and uncertainties. The successful exploitation of a geothermal power resource ultimately depends upon many factors including the following:
the heat content of the extractable steam or fluids;
the geology of the reservoir;

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the total amount of recoverable reserves;
operating expenses relating to the extraction of steam or fluids;
price levels relating to the extraction of steam, fluids or power generated; and
capital expenditure requirements relating primarily to the drilling of new wells.
Significant events beyond our control, such as natural disasters, including weather-related events, or acts of terrorism, could damage our power plants or our corporate offices or cause a loss of system load and may affect us in unpredictable ways.
Certain of our geothermal and natural gas-fired power plants, particularly in the West, have been in the past and remain subject to frequent low-level seismic disturbances. More significant seismic disturbances are possible. In addition, other areas in which we operate, particularly in Texas and the Southeast, routinely experience tornados and hurricanes. Operations at our corporate offices in Houston, Texas could be substantially affected by a hurricane. Any significant loss of system load resulting from a weather-related event could negatively affect our wholesale business and retail subsidiaries. Such events could damage or shut down our power plants, power transmission or the fuel supply facilities upon which our wholesale business and retail subsidiaries are dependent. Our existing power plants are built to withstand relatively significant levels of seismic and other disturbances, and we believe we maintain adequate insurance protection, earthquake, property damage or business interruption insurance may be inadequate to cover all potential losses sustained in the event of extensive damages to our power plants or disruptions to our wholesale and retail operations due to natural disasters.
Periodic wildfires in the West, particularly California, could damage our power plants or cause a loss of system load and may affect us in unpredictable ways.
Our geothermal and natural gas-fired power plants in the West have been in the past and remain subject to an ongoing risk of wildfires. Severe drought conditions, unseasonably warm temperatures and stronger winds have increased the severity and prevalence of wildfires in California. Although such wildfires have not resulted in material damages to us in the past, we cannot be certain that any such events would not materially and adversely affect our operations in the future. Such events could damage or shut down our power plants, power transmission or the fuel supply facilities upon which our power plants are dependent or cause serious injuries, fatalities, property damage or service interruptions, which could expose us to liabilities that could be material. Although we believe we maintain adequate insurance protection, property damage liability or business interruption insurance may be inadequate to cover all potential losses sustained in the event of extensive damages to our power plants or disruptions to our operations due to wildfires. The recent wildfires in California may exacerbate these insurance risks by leading to adverse changes in insurance deductibles, premiums, coverage and/or limits. If we incur a substantial liability and the damages are above our estimates for self-insured claims, or such damages are not covered by our insurance policies or are in excess of policy limits, or if we incur liability at a time when we do not have liability insurance, our results of operations and cash flows could be materially and adversely affected.
In addition, electric utilities in California are authorized to shut down power for public safety reasons, such as during periods of extreme fire hazard, if the utility reasonably believes that there is an imminent and significant risk that strong winds may topple power lines or cause vegetation to come into contact with power lines leading to increased risk of fire. Any shut down of power for public safety reasons may reduce our revenues.
Our business, financial condition and results of operations could be adversely affected by strikes or work stoppages by unionized employees or by our inability to replace key employees.
Approximately 8% of our employees are subject to collective bargaining agreements. In the event that our union employees participate in a strike, work stoppage or engage in other forms of labor disruption, we would be responsible for procuring replacement labor and could experience reduced power generation or outages.
In addition, our success is largely dependent on the skills, experience and efforts of our people. The loss of the services of one or more members of our senior management or of numerous employees with critical skills could have a negative effect on our business, financial condition and results of operations and future growth if we were unable to replace them.
Failures in our systems or a cyber attack or breach of our information technology systems or technology could significantly disrupt our business operations or result in sensitive customer information being compromised, which would negatively affect our reputation and/or results of operations.
Our information technology systems contain personal, financial and other information that is entrusted to us by our customers and employees as well as financial, proprietary and other confidential information related to our business, which makes us a target of cyber attacks on our systems. We rely on electronic networks, computers, systems, including our gateways, programs

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to run our business and operations, our employees and third party technology and information technology infrastructure providers and, as a result, are potentially exposed to the risk of security breaches, computer or other malware, viruses, social engineering or general hacking, industrial espionage, employee or third party error or malfeasance, or other irregularities or compromises on our systems or those to third parties, which could result in the loss or misappropriation of sensitive data or other disruption to our operations.
We depend on computer and telecommunications systems we do not own or control. We have entered into agreements with third parties for hardware, software, telecommunications and other information technology services in connection with the operation of our power plants. In addition, we have developed proprietary software systems, management techniques and other information technologies incorporating software licensed from third parties. We also rely on software systems owned and operated by third parties, such as ISOs and RTOs, to be functioning in order to be able to transmit the electricity produced by our power plants to our customers. It is possible that we, or a third party that we rely on, could incur interruptions from a loss of communications, hardware or software failures, a cyber attack or a breach of our information technology systems or technology, computer viruses or malware. We believe that we have positive relations with our vendors and maintain adequate anti-virus and malware software and controls; however, any interruptions to our arrangements with third parties, to our computing and communications infrastructure, or to our information systems or any of those operated by a third party that we rely on could significantly disrupt our business operations.
A cyber attack on our systems or networks that impairs our information technology systems could disrupt our business operations and result in loss of service to customers. We have a comprehensive cybersecurity program designed to protect and preserve the integrity of our information technology systems. We have experienced and expect to continue to experience actual or attempted cyber attacks on our information technology systems or networks; however, none of these actual or attempted cyber attacks has had a material effect on our operations or financial condition. Even when a security breach is detected, the full extent of the breach may not be determined for some time. The risk of a security breach or disruption, particularly through a cyber attack or a cyber intrusion, including by computer hackers, foreign governments and cyber terrorists, has magnified as the number, intensity and sophistication of attempted attacks and intrusions from around the world has increased. An increasing number of companies have disclosed security breaches of their information technology systems and networks, some of which have involved sophisticated and highly targeted attacks. We believe such incidents are likely to continue, and we are unable to predict the direct or indirect effect of any future attacks on our business.
Additionally, our retail subsidiaries require access to sensitive customer information in the ordinary course of business. If a significant data breach occurred, the reputation of our retail subsidiaries may be adversely affected, customer confidence may be diminished, and our retail subsidiaries may become subject to legal claims, any of which may contribute to the loss of customers and have a material adverse effect on our retail subsidiaries.
Capital Resources; Liquidity
We have substantial liquidity needs and could face liquidity pressure.
As of December 31, 2019, our consolidated debt outstanding was $11.7 billion, of which approximately $9.7 billion was outstanding under our Senior Unsecured Notes, First Lien Term Loans and First Lien Notes. In addition, we had $1,085 million issued in letters of credit and our pro rata share of unconsolidated subsidiary debt was approximately $150 million. Although we significantly extended our maturities during the last several years, we could face liquidity challenges as we continue to have substantial debt and substantial liquidity needs in the operation of our business. Our ability to make payments on our indebtedness, to meet margin requirements and to fund planned capital expenditures and development efforts will depend on our ability to generate cash in the future from our operations and our ability to access the capital markets. This, to a certain extent, is dependent upon industry conditions, as well as general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control, as discussed further in “— Commercial Operations” above.

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We also have exposure to many different financial institutions and counterparties including those under our Senior Unsecured Notes, First Lien Term Loans, First Lien Notes, Corporate Revolving Facility and other credit and financing arrangements as we routinely execute transactions in connection with our hedging and optimization activities, including brokers and dealers, commercial banks, investment banks and other institutions and industry participants. Many of these transactions expose us to credit risk in the event that any of our lenders or counterparties are unable to honor their commitments or otherwise default under a financing agreement. See additional discussion regarding our capital resources and liquidity in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”
Our indebtedness could adversely affect our financial health and limit our operations.
Our indebtedness has important consequences, including:
limiting our ability to borrow additional amounts for working capital, capital expenditures, debt service requirements, potential growth or other purposes;
limiting our ability to use operating cash flows in other areas of our business because we must dedicate a substantial portion of these funds to service our debt;
increasing our vulnerability to general adverse economic and industry conditions;
limiting our ability to capitalize on business opportunities and to react to competitive pressures and adverse changes in governmental regulation;
limiting our ability or increasing the costs to refinance indebtedness; and
limiting our ability to enter into marketing, hedging and optimization activities by reducing the number of counterparties with whom we can transact as well as the volume and type of those transactions.
We may be unable to obtain additional financing or access the credit and capital markets in the future at prices that are beneficial to us or at all.
If our available cash, including future cash flows generated from operations, is not sufficient in the near term to finance our operations, post collateral or satisfy our obligations as they become due, we may need to access the capital and credit markets. Our ability to arrange financing (including any extension or refinancing) and the cost of the financing is dependent upon numerous factors, including general economic and capital market conditions. Market disruptions such as those experienced in the U.S. and abroad in recent years, may increase our cost of borrowing or adversely affect our ability to access capital. Other factors include:
low credit ratings may prevent us from obtaining any material amount of additional debt financing;
conditions in energy commodity markets;
regulatory developments;
credit availability from banks or other lenders for us and our industry peers;
investor confidence in the industry and in us;
the continued reliable operation of our current power plants; and
provisions of tax, regulatory and securities laws that are conducive to raising capital.
While we have utilized non-recourse or lease financing when appropriate, market conditions and other factors may prevent us from completing similar financings in the future. It is possible that we may be unable to obtain the financing required to develop, construct, acquire or expand power plants on terms satisfactory to us. We have financed our existing power plants using a variety of leveraged financing structures, including senior secured and unsecured indebtedness, construction financing, project financing, term loans and lease obligations. In the event of a default under a financing agreement which we do not cure, the lenders or lessors would generally have rights to the power plant and any related assets. In the event of foreclosure after a default, we may not be able to retain any interest in the power plant or other collateral supporting such financing. In addition, any such default or foreclosure may trigger cross default provisions in our other financing agreements.
Our Senior Unsecured Notes, First Lien Term Loans, First Lien Notes, Corporate Revolving Facility, CCFC Term Loan and our other debt instruments impose restrictions on us and any failure to comply with these restrictions could have a material adverse effect on our liquidity and our operations.
The restrictions under our Senior Unsecured Notes, First Lien Term Loans, First Lien Notes, Corporate Revolving Facility, CCFC Term Loan and other debt instruments could adversely affect us by limiting our ability to plan for or react to market

28



conditions or to meet our capital needs and, if we were unable to comply with these restrictions, could result in an event of default under these debt instruments. These restrictions require us to meet certain financial performance tests on a quarterly basis and limit or prohibit our ability, subject to certain exceptions to, among other things:
incur or guarantee additional first lien indebtedness up to certain consolidated net tangible asset ratios;
enter into certain types of commodity hedge agreements that can be secured by first lien collateral;
enter into sale and leaseback transactions;
make certain investments;
create or incur liens;
consolidate or merge with or transfer all or substantially all of our assets to another entity, or allow substantially all of our subsidiaries to do so;
lease, transfer or sell assets and use proceeds of permitted asset leases, transfers or sales;
engage in certain business activities; and
enter into certain transactions with our affiliates.
Our Senior Unsecured Notes, First Lien Term Loans, First Lien Notes, Corporate Revolving Facility, CCFC Term Loan and our other debt instruments contain events of default customary for financings of their type, including a cross default to debt other than non-recourse project financing debt, a cross-acceleration to non-recourse project financing debt and certain change of control events. If we fail to comply with the covenants and are unable to obtain a waiver or amendment, or a default exists and is continuing under such debt, the lenders or the holders or trustee, as applicable, could give notice and declare outstanding borrowings and other obligations under such debt immediately due and payable.
Our ability to comply with these covenants may be affected by events beyond our control, and any material deviations from our forecasts could require us to seek waivers or amendments of covenants or alternative sources of financing or to reduce expenditures. We may not be able to obtain such waivers, amendments or alternative financing, or if obtainable, it could be on terms that are not acceptable to us. If we are unable to comply with the terms of our Senior Unsecured Notes, First Lien Term Loans, First Lien Notes, Corporate Revolving Facility, CCFC Term Loan and our other debt instruments, or if we fail to generate sufficient cash flows from operations, or if it becomes necessary to obtain such waivers, amendments or alternative financing, it could adversely affect our financial condition, results of operations and cash flows.
Our credit status is below investment grade, which may restrict our operations, increase our liquidity requirements and restrict financing opportunities.
There are a number of factors that rating agencies evaluate to arrive at credit ratings for us and our subsidiaries, including regulatory framework, ability to recover costs and earn returns, diversification, financial strength and liquidity. If one or more rating agencies downgrade us, borrowing costs would increase, the potential pool of investors and funding sources would likely decrease, and cash or letter of credit collateral demands may be triggered by the terms of a number of commodity contracts, leases and other agreements.
Our corporate and debt credit ratings are below investment grade. There is no assurance that our credit ratings will improve in the future, which may restrict the financing opportunities available to us or may increase the cost of any available financing. Our current credit rating has resulted in the requirement that we provide additional collateral in the form of letters of credit or cash for credit support obligations and may adversely affect our subsidiaries’ and our financial position and results of operations.
Certain of our obligations are required to be secured by letters of credit or cash, which increase our costs; if we are unable to provide such security it may restrict our ability to conduct our business.
Companies using derivatives, which include many commodity contracts, are subject to the inherent risks of such transactions. Consequently, many such companies, including us, may be required to post cash collateral for certain commodity transactions; and, the level of collateral will increase as a company increases its hedging activities. We use margin deposits, prepayments and letters of credit as credit support for commodity procurement and risk management activities. Future cash collateral requirements may increase based on the extent of our involvement in standard contracts and movements in commodity prices, and also based on our credit ratings and general perception of creditworthiness in this market. Certain of our financing arrangements for our power plants have required us to post letters of credit which are at risk of being drawn down in the event we, or the applicable subsidiary, default on our obligations.

29



Many of our collateral agreements require that letters of credit posted as collateral must be issued by a financial institution with a minimum credit rating of “A”. Currently the financial institutions that issue letters of credit under our Corporate Revolving Facility and other letter of credit facilities meet or exceed the minimum credit rating criteria. However, if one or more of these financial institutions is no longer able to meet the minimum credit rating criteria, then we could be required to post collateral funding from our cash and cash equivalents which could negatively affect our liquidity.
These letter of credit and cash collateral requirements increase our cost of doing business and could have an adverse effect on our overall liquidity, particularly if there was a call for a large amount of additional cash or letter of credit collateral due to an unexpectedly large movement in the market price of a commodity. As of December 31, 2019, we had $1,085 million issued in letters of credit under our Corporate Revolving Facility and other facilities, with $1,392 million remaining available for borrowing or for letter of credit support under our Corporate Revolving Facility. In addition, we have ratably secured our obligations under certain of our power and natural gas agreements that qualify as eligible commodity hedge agreements with the assets subject to liens under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility.
Additionally, changes in market regulations can increase the use of credit support and collateral.
We may not have sufficient liquidity to hedge market risks effectively.
We are exposed to market risks through our purchase and sale of power, capacity and related products, fuel, transmission services and emission allowances. These market risks include, among other risks, volatility arising from location and timing differences that may be associated with buying and transporting fuel, converting fuel into power and delivering the power to a buyer.
We undertake these activities through agreements with various counterparties, many of which require us to provide guarantees, offset or netting arrangements, letters of credit, a second lien on assets and/or cash collateral to protect the counterparties against the risk of our default or insolvency. The amount of such credit support that must be provided typically is based on the difference between the price of the commodity in a given contract and the market price of the commodity. Significant movements in market prices can result in our being required to provide cash collateral and letters of credit in very large amounts. The effectiveness of our strategy may be dependent on the amount of collateral available to enter into or maintain these contracts, and liquidity requirements may be greater than we anticipate or will be able to meet. Without a sufficient amount of working capital to post as collateral in support of performance guarantees or as a cash margin, we may not be able to manage price volatility effectively or to implement our strategy. An increase in the amount of letters of credit or cash collateral required to be provided to our counterparties may negatively affect our liquidity and financial condition.
Further, if any of our power plants experience unplanned outages, we may be required to procure replacement power at spot market prices in order to fulfill contractual commitments. Without adequate liquidity to meet margin and collateral requirements, we may be exposed to significant losses, may miss significant opportunities and may have increased exposure to the volatility of spot markets.
Our ability to receive future cash flows generated from the operation of our subsidiaries may be limited.
Almost all of our operations are conducted through our subsidiaries and other affiliates. As a result, we depend almost entirely upon their earnings and cash flows to service our indebtedness, post collateral and finance our ongoing operations. Certain of our project debt and other agreements restrict our ability to receive dividends and other distributions from our subsidiaries. Some of these limitations are subject to a number of significant exceptions (including exceptions permitting such restrictions in connection with certain subsidiary financings). Accordingly, the financing agreements of certain of our subsidiaries and other affiliates generally restrict their ability to pay dividends, make distributions or otherwise transfer funds to us prior to the payment of their other obligations, including their outstanding debt, operating expenses, lease payments and reserves or during the existence of a default.
We may utilize project financing, preferred equity and other types of subsidiary financing transactions when appropriate in the future, which could increase our debt and may be structurally senior to other debt such as our First Lien Term Loans, First Lien Notes and Corporate Revolving Facility.
Our ability and the ability of our subsidiaries to incur additional indebtedness are limited in some cases by existing indentures, debt instruments or other agreements. Our subsidiaries may incur additional construction/project financing indebtedness, issue preferred equity to finance the acquisition and development of new power plants and engage in certain types of non-recourse financings to the extent permitted by existing agreements, and may continue to do so in order to fund our ongoing operations. Any such newly incurred subsidiary preferred equity would be added to our current consolidated debt levels and would likely be structurally senior to our debt, which could also intensify the risks associated with our already existing leverage.

30



Our First Lien Term Loans, First Lien Notes and Corporate Revolving Facility are effectively subordinated to certain project indebtedness.
Certain of our subsidiaries and other affiliates are separate and distinct legal entities and, except in limited circumstances, have no obligation to pay any amounts due with respect to our indebtedness or indebtedness of other subsidiaries or affiliates, and do not guarantee the payment of interest on or principal of such indebtedness. In the event of our bankruptcy, liquidation or reorganization (or the bankruptcy, liquidation or reorganization of a subsidiary or affiliate), such subsidiaries’ or other affiliates’ creditors, including trade creditors and holders of debt issued by such subsidiaries or affiliates, will generally be entitled to payment of their claims from the assets of those subsidiaries or affiliates before any assets are made available for distribution to us or the holders of our indebtedness. As a result, holders of our indebtedness will be effectively subordinated to all present and future debts and other liabilities (including trade payables) of certain of our subsidiaries. As of December 31, 2019, our subsidiaries had approximately $967 million in debt from our CCFC subsidiary and approximately $1.0 billion in secured project financing from other subsidiaries, which are effectively senior to our First Lien Term Loans, First Lien Notes and Corporate Revolving Facility. We may incur additional project financing indebtedness in the future, which will be effectively senior to our other secured and unsecured debt.
Governmental Regulation
Federal tax incentives and regulations, existing and proposed state RPS and energy efficiency standards, as well as economic support for renewable sources of power under federal or state legislation could adversely affect our operations.
Renewables have the ability to take market share from us and to lower overall wholesale power prices which could negatively affect us. In December 2015, the Consolidated Appropriations Act extended the production tax credit for wind through the end of 2016 with gradual decreases thereafter until the tax credit was to expire 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%. On December 20, 2019, President Trump signed the federal government budget appropriation bill which included a one year extension of the production tax credit for wind, allowing wind facilities that begin construction in 2020 to be eligible for a 60% production tax credit. California has a RPS in effect and recently enacted legislation requiring implementation of a 100% CO2-free electricity requirement by 2045. A number of additional states, including Maine, New York, Texas and Wisconsin, have an array of different RPS in place. Existing state-specific RPS requirements may change due to regulatory and/or legislative initiatives, and other states may consider implementing enforceable RPS in the future. A more robust RPS in states in which we are active, coupled with federal tax incentives, would likely initially drive up the number of wind and solar resources, increasing power supply to various markets which could negatively affect the dispatch of our natural gas-fired power plants, primarily in Texas and California.
Similarly, several states have energy efficiency initiatives in place while others are considering imposing them. Improved energy efficiency when mandated by law or promoted by government sponsored incentives can decrease demand for power which could negatively affect the dispatch of our natural gas-fired power plants.
Increased oversight and investigation by the CFTC relating to derivative transactions, as well as certain financial institutions, could have an adverse effect on our ability to hedge risks associated with our business.
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).
Changes in the regulation of the power markets in which we operate could negatively affect us.
We have a significant presence in the major competitive power markets of California, Texas and the Northeast and Mid-Atlantic regions of the U.S. While these markets are largely deregulated, they continue to evolve. Existing regulations within the markets in which we operate may be revised or reinterpreted and new laws or regulations may be issued. We cannot predict the future development of regulation or legislation nor the ultimate effect such changes in these markets could have on our business; however, we could be negatively affected.

31



Additionally, state PUCs have the ability to set policies that either enhance or limit customer choice. Each state that has adopted retail electric choice creates its own laws, regulations and compliance requirements which evolve over time and could impact our ability to maintain or expand retail operations and negatively affect our retail business.
State legislative and regulatory action could adversely affect our competitive position and business.
Certain states have taken or are considering taking anticompetitive actions by subsidizing or otherwise providing economic support to existing, uneconomic power plants in a manner that could have an adverse effect on the deregulated power markets. In addition, certain states in which we have retail operations are taking actions which we believe limit customer choice as well as other actions that we believe are anticompetitive and could negatively affect our retail operations. We are actively participating in many of the legislative, regulatory and judicial processes challenging these actions at the state and federal levels. If these anticompetitive actions are ultimately upheld and implemented, they could adversely affect capacity and energy prices in the deregulated electricity markets or impede our ability to maintain or expand our retail operations which in turn could have a material adverse effect on our business prospects and financial results.
Existing and future anticipated GHG/Carbon and other environmental regulations could cause us to incur significant costs and adversely affect our operations generally or in a particular quarter when such costs are incurred.
Environmental laws and regulations have generally become more stringent over time, and this trend is likely to continue. In particular, there is a potential that carbon taxes or limits on carbon, CO2 and other GHG emissions could be implemented at the federal or expanded at the state or regional levels. We continue to monitor and actively participate in initiatives where we anticipate a material effect on our business.
Currently, ten states in the Northeast are required to comply with a Cap-and-Trade program, RGGI, to regulate CO2 emissions from power plants. California has implemented AB 32 which places a statewide cap on GHG emissions and requires the state to return to 1990 emission levels by 2020. In December 2010, the CARB adopted a regulation establishing a GHG Cap-and- Trade program which is in effect for electric utilities and other “major industrial sources,” and in 2015 for certain other GHG sources including transportation fuels and natural gas distribution. The Massachusetts Department of Environmental Protection issued a final rule in August 2017 that imposes new GHG limits on power plants and other sources.
Environmental regulations could also affect the availability and price of natural gas used in our generation facilities. Permitting of new natural gas transportation pipelines has become more difficult in some regions such as the Northeast, and restrictions on natural gas production have been implemented or proposed in some locations.
We are subject to other complex governmental regulation which could adversely affect our operations.
Generally, in the U.S., we are subject to regulation by the FERC regarding the terms and conditions of wholesale service and the sale and transportation of natural gas, as well as by state agencies regarding physical aspects of the power plants. The majority of our generation is sold at market prices under the market-based rate authority granted by the FERC. If certain conditions are not met, FERC has the authority to withhold or rescind market-based rate authority and require sales to be made based on cost-of-service rates. A loss of our market-based rate authority could have a materially negative effect on our generation business. FERC could also impose fines or other restrictions or requirements on us under certain circumstances.
The construction and operation of power plants require numerous permits, approvals and certificates from the appropriate foreign, federal, state and local governmental agencies, as well as compliance with numerous environmental laws and regulations of federal, state and local authorities. We could also be required to install expensive pollution control measures or limit or cease activities, including the retirement of certain generating plants, based on these regulations. Should we fail to comply with any environmental requirements that apply to power plant construction or operations, we could be subject to administrative, civil and/or criminal liability and fines, and regulatory agencies could take other actions to curtail our operations.
Furthermore, certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. We are generally responsible for all liabilities associated with the environmental condition of our power plants, including any soil or groundwater contamination that may be present, regardless of when the liabilities arose and whether the liabilities are known or unknown, or arose from the activities of predecessors or third parties.

32



If we were deemed to have market power in certain markets as a result of common ownership by certain significant investors, we could lose FERC authorization to sell power at wholesale at market-based rates in such markets or be required to engage in mitigation in those markets.
Certain of our significant ownership groups own power generating assets, or own significant equity interests in entities with power generating assets, in markets where we currently own power plants. We could be determined to have market power if these existing significant owners acquire additional significant ownership or equity interest in other entities with power generating assets in the same markets where we generate and sell power.
If the FERC makes the determination that we have market power, the FERC could, among other things, revoke market-based rate authority for the affected market-based companies or order them to mitigate that market power. If market-based rate authority was revoked for any of our market-based rate companies, those companies would be required to make wholesale sales of power based on cost-of-service rates, which could negatively affect their revenues. If we are required to mitigate market power, we could be required to sell certain power plants in regions where we are determined to have market power. A loss of our market-based rate authority or required sales of power plants, particularly if it affected several of our power plants or was in a significant market, could have a material negative effect on our financial condition, results of operations and cash flows.
Item 1B.
Unresolved Staff Comments
None.
Item 2.
Properties

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 either lease or own the land upon which our power plants are built. We believe that our properties are adequate for our current operations. A description of our power plants is included under Item 1. “Business — Description of Our Power Plants.”

Item 3.
Legal Proceedings
See Note 16 of the Notes to Consolidated Financial Statements for a description of our legal proceedings.
Item 4.
Mine Safety Disclosures
Not applicable.


33



PART II

Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
At December 31, 2019, all of the outstanding shares of Calpine Corporation common stock are held by our parent, CPN Management.
Item 6. Selected Financial Data
SELECTED CONSOLIDATED FINANCIAL DATA
 
Years Ended December 31,
 
2019
 
2018
 
2017
 
2016
 
2015
 
(in millions)
Statement of Operations data:
 
 
 
 
 
 
 
 
 
Operating revenues
$
10,072

 
$
9,512

 
$
8,752

 
$
6,716

 
$
6,472

Net income (loss) attributable to Calpine
$
770

 
$
10

 
$
(339
)
 
$
92

 
$
235

Balance Sheet data:
 
 
 
 
 
 
 
 
 
Total assets
$
16,649

 
$
16,062

 
$
16,453

 
$
17,493

 
$
16,849

Short-term debt and finance lease obligations
$
1,268

 
$
637

 
$
225

 
$
748

 
$
221

Long-term debt and finance lease obligations
$
10,438

 
$
10,148

 
$
11,180

 
$
11,431

 
$
11,716



34



Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Forward-Looking Information
This Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our accompanying Consolidated Financial Statements and related Notes. See the cautionary statement regarding forward-looking statements at the beginning of this Report for a description of important factors that could cause actual results to differ from expected results. See also Item 1A. “Risk Factors.”
INTRODUCTION AND OVERVIEW
We are a power generation company engaged in the ownership and operation of primarily natural gas-fired and geothermal power plants in North America. We have a significant presence in major competitive wholesale and retail power markets in California, Texas and the Northeast and Mid-Atlantic regions of the U.S. We sell power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators and industrial companies, retail power providers, municipalities, CCAs and other governmental entities, power marketers as well as retail commercial, industrial, governmental and residential customers. We continue to focus on providing products and services that are beneficial to our wholesale and retail 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 and related products 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.
We assess our wholesale business on a regional basis due to the effect on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors affecting supply and demand. Our geographic reportable segments for our wholesale business are West (including geothermal), Texas and East (including Canada) and we have a separate reportable segment for our retail business.

35



RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2019 AND 2018
Below are our results of operations for the year ended December 31, 2019, as compared to the same period in 2018 (in millions, except for percentages and operating performance metrics). A discussion regarding our results of operations for the year ended December 31, 2018, as compared to the same period in 2017 can be found under Item 7 of Part II “Management’s Discussion and Analysis — Results of Operations for the Years Ended December 31, 2018 and 2017” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018, filed with the SEC on March 28, 2019, which is available on our website at www.calpine.com and on the SEC’s website at www.sec.gov. In the comparative tables below, increases in revenue/income or decreases in expense (favorable variances) are shown without brackets while decreases in revenue/income or increases in expense (unfavorable variances) are shown with brackets.
 
2019
 
2018
 
Change
 
% Change
Operating revenues:
 
 
 
 
 
 
 
Commodity revenue
$
9,437

 
$
9,865

 
$
(428
)
 
(4
)
Mark-to-market gain (loss)
618

 
(373
)
 
991

 
#

Other revenue
17

 
20

 
(3
)
 
(15
)
Operating revenues
10,072

 
9,512

 
560

 
6

Operating expenses:
 
 
 
 
 
 
 
Fuel and purchased energy expense:
 
 
 
 
 
 
 
Commodity expense
6,164

 
6,914

 
750

 
11

Mark-to-market (gain) loss
340

 
(165
)
 
(505
)
 
#

Fuel and purchased energy expense
6,504

 
6,749

 
245

 
4

Operating and maintenance expense
1,001

 
1,020

 
19

 
2

Depreciation and amortization expense
694

 
739

 
45

 
6

General and other administrative expense
150

 
158

 
8

 
5

Other operating expenses
79

 
98

 
19

 
19

Total operating expenses
8,428

 
8,764

 
336

 
4

Impairment losses
84

 
10

 
(74
)
 
#

(Gain) on sale of assets, net
(10
)
 

 
10

 
#

(Income) from unconsolidated subsidiaries
(22
)
 
(24
)
 
(2
)
 
(8
)
Income from operations
1,592

 
762

 
830

 
#

Interest expense
609

 
617

 
8

 
1

(Gain) loss on extinguishment of debt
58

 
(28
)
 
(86
)
 
#

Other (income) expense, net
37

 
81

 
44

 
54

Income before income taxes
888

 
92

 
796

 
#

Income tax expense
98

 
64

 
(34
)
 
(53
)
Net income
790

 
28

 
762

 
#

Net income attributable to the noncontrolling interest
(20
)
 
(18
)
 
(2
)
 
(11
)
Net income attributable to Calpine
$
770

 
$
10

 
$
760

 
#

 
2019
 
2018
 
Change
 
% Change
Operating Performance Metrics:
 
 
 
 
 
 
 
MWh generated (in thousands)(1)(2)
100,845

 
95,732

 
5,113

 
5

Average availability(2)
86.7
%
 
87.6
%
 
(0.9
)%
 
(1
)
Average total MW in operation(1)
25,399

 
25,120

 
279

 
1

Average capacity factor, excluding peakers
50.0
%