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Miller
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6: EX-31.1 Section 302 Certification of CEO HTML 35K
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Financial Officer
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Sheets Parentheticals
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Securities registered pursuant to Section 12(b) of the Act:
Calpine Corporation Common Stock,
$0.001 Par Value
Name of each exchange on which registered:
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [X] No [ ]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes [ ] No [X]
Indicate by check mark whether the
registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files). Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer, “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large
accelerated filer [X]
Accelerated filer [ ]
Non-accelerated filer [ ]
Smaller reporting company [ ]
(Do not check if a smaller reporting company)
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, 2017, the last business day of the registrant’s most recently completed second fiscal quarter: approximately $3,624 million.
Indicate
the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: Calpine Corporation: 360,543,323 shares of common stock, par value $0.001, were outstanding as of February 14, 2018.
As used in this annual report for the year ended December 31, 2017, 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
2008
Director Plan
The Amended and Restated Calpine Corporation 2008 Director Incentive Plan
2008 Equity Plan
The Amended and Restated Calpine Corporation 2008 Equity Incentive Plan
2017
Director Plan
The Calpine Corporation 2017 Equity Compensation Plan for Non-Employee Directors
2017 Equity Plan
The Calpine Corporation 2017 Equity Incentive Plan
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
2020 First Lien Term Loan
The $390 million first lien senior secured term loan, dated October
23, 2013, among Calpine Corporation, as borrower, the lenders party thereto, Citibank, N.A., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent, repaid on May 31, 2016
2022 First Lien Notes
The $750 million aggregate principal amount of 6.0% senior secured notes due 2022, issued October 31, 2013
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 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
2023
Senior Unsecured Notes
The $1.25 billion aggregate principal amount of 5.375% senior unsecured notes due 2023, issued July 22, 2014
2024 First Lien Notes
The $490 million aggregate principal amount of 5.875% senior secured notes due 2024, issued October 31, 2013
2024
First Lien Term Loan
The $1.6 billion first lien senior secured term loan, dated May 28, 2015 (as amended December 21, 2016), among Calpine Corporation, as borrower, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent
2024 Senior Unsecured Notes
The $650
million aggregate principal amount of 5.5% senior unsecured notes due 2024, issued February 3, 2015
ii
ABBREVIATION
DEFINITION
2025
Senior Unsecured Notes
The $1.55 billion aggregate principal amount of 5.75% senior unsecured notes due 2025, issued July 22, 2014
2026 First Lien Notes
Collectively, the $625 million aggregate principal amount of 5.25% senior secured notes due 2026, issued on May 31, 2016, and the $560 million aggregate principal amount of 5.25% senior secured
notes due 2026, issued on December 15, 2017
AB 32
California Assembly Bill 32
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
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
Calpine Equity Incentive Plans
Collectively, the Director Plans and the Equity Plans, which provide for grants of equity awards to Calpine non-union employees and non-employee members of Calpine’s Board of Directors
Calpine Receivables
Calpine
Receivables, LLC, 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 the third largest 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
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, 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
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 reviewed by our chief operating decision maker 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. Our chief operating decision maker uses Commodity Margin, which is a measure of segment profit or loss under FASB Accounting Standards Codification 280, 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 $1.8 billion aggregate amount revolving credit facility credit agreement, dated as of December 10, 2010, as amended on June 27, 2013, July 30, 2014, February 8, 2016, December 1, 2016, September 15, 2017 and October 20, 2017 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
CSAPR
Cross-State
Air Pollution Rule
Director Plans
Collectively, the 2008 Director Plan and the 2017 Director Plan
EIA
Energy Information Administration of the U.S. Department of Energy
EPA
U.S.
Environmental Protection Agency
Equity Plans
Collectively, the 2008 Equity Plan and the 2017 Equity Plan
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 2023 First Lien Notes, the 2024 First Lien Notes and the 2026 First Lien Notes
First Lien Term Loans
Collectively, the 2019 First Lien Term Loan, the 2023 First Lien Term Loans and the 2024 First Lien Term Loan
FRCC
Florida
Reliability Coordinating Council
GE
General Electric International, Inc.
Geysers Assets
Our geothermal power plant assets, including our steam extraction and gathering assets,
located in northern California consisting of 13 operating power plants
GHG(s)
Greenhouse gas(es), primarily carbon dioxide (CO2), and including methane (CH4), nitrous oxide (N2O), sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs) and perfluorocarbons (PFCs)
Greenfield
LP
Greenfield Energy Centre LP, a 50% partnership interest between certain of our subsidiaries and a third party which operates the Greenfield Energy Centre, a 1,038 MW natural gas-fired, combined-cycle power plant in Ontario, Canada
Heat Rate(s)
A measure of the amount of fuel required to produce a unit of power
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)
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
Merger
Agreement
Agreement and Plan of Merger, dated as of August 17, 2017, by and among Calpine Corporation, Volt Parent, LP and Volt Merger Sub, Inc.
v
ABBREVIATION
DEFINITION
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
Noble
Solutions
Noble Americas Energy Solutions LLC, which was legally renamed Calpine Energy Solutions, LLC on December 1, 2016 following the completion of its acquisition by an indirect, wholly-owned subsidiary of Calpine Corporation
NOL(s)
Net operating loss(es)
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
NYSE
New
York Stock Exchange
OCI
Other Comprehensive Income
OMEC
Otay Mesa Energy Center, LLC, an indirect, wholly-owned subsidiary of Calpine that owns the Otay Mesa Energy Center,
a 608 MW natural gas-fired, combined-cycle power plant located in San Diego county, California
OTC
Over-the-Counter
PG&E
Pacific Gas & Electric Company
PJM
PJM
Interconnection is a RTO that coordinates the movement of wholesale electricity in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia
PPA(s)
Any term power purchase agreement or other contract for a physically settled sale (as distinguished from a financially settled future, option or other derivative or hedge transaction) of any power product, including
power, capacity and/or ancillary services, in the form of a bilateral agreement or a written or oral confirmation of a transaction between two parties to a master agreement, including sales related to a tolling transaction in which the purchaser provides the fuel required by us to generate such power and we receive a variable payment to convert the fuel into power and steam
PSD
Prevention of Significant Deterioration
PSU(s)
Performance
Stock Units
PUCT
Public Utility Commission of Texas
vi
ABBREVIATION
DEFINITION
PUHCA
2005
U.S. Public Utility Holding Company Act of 2005
PURPA
U.S. Public Utility Regulatory Policies Act of 1978
QF(s)
Qualifying
facility(ies), which are cogeneration facilities and certain small power production facilities eligible to be “qualifying facilities” under PURPA, provided that they meet certain power and thermal energy production requirements and efficiency standards. QF status provides an exemption from the books and records requirement of PUHCA 2005 and grants certain other benefits to the QF
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
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
SEC
U.S.
Securities and Exchange Commission
Securities Act
U.S. Securities Act of 1933, as amended
Senior Unsecured Notes
Collectively, the 2023 Senior Unsecured Notes, the 2024 Senior
Unsecured Notes and the 2025 Senior Unsecured Notes
SERC
Southeastern Electric Reliability Council
Severance Plan
Calpine Corporation Change in Control and Severance Benefits
Plan
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
TRE
Texas
Reliability Entity, Inc.
TSR
Total shareholder return
U.S. GAAP
Generally accepted accounting principles in the U.S.
vii
ABBREVIATION
DEFINITION
VAR
Value-at-risk
VIE(s)
Variable
interest entity(ies)
WECC
Western Electricity Coordinating Council
Whitby
Whitby Cogeneration Limited Partnership, a 50% partnership interest between certain of our subsidiaries
and a third party which operates Whitby, a 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada
viii
Forward-Looking Statements
This Report contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act, and Section 21E of the Exchange Act. Forward-looking statements may appear throughout this Report, including without limitation, the “Management’s Discussion and Analysis” section. We use words
such as “believe,”“intend,”“expect,”“anticipate,”“plan,”“may,”“will,”“should,”“estimate,”“potential,”“project” and similar expressions to identify forward-looking statements. Such statements include, among others, those concerning our expected financial performance and strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. We believe that the forward-looking statements are based upon reasonable assumptions and expectations. However, you are cautioned that any such forward-looking statements are not guarantees of future performance and that a number of risks and uncertainties could cause actual results to differ materially from those anticipated in the forward-looking statements. Such risks and uncertainties include, but are not limited to:
•
Risks
and uncertainties associated with the Merger, including (i) any event that could give rise to termination of the Merger Agreement or otherwise cause failure of the Merger to close, (ii) failure to obtain certain regulatory approvals for the Merger, (iii) the effect of the Merger on our relationships with customers and employees and (iv) the effect of the Merger on our financial results and business;
•
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 Notes, First
Lien Term Loans, 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;
•
Competition, including from renewable sources of power, interference by states in competitive power markets through subsidies or similar support for new or existing power plants, and other risks associated with marketing and selling power in the evolving energy markets;
•
Structural changes in the supply and demand of power, resulting from the development of new fuels or technologies
and demand-side management tools (such as distributed generation, power storage and other technologies);
•
The expiration or early termination of our PPAs and the related results on revenues;
•
Future capacity revenue may not occur at expected levels;
•
Natural disasters, such as hurricanes,
earthquakes, droughts, wildfires and floods, acts of terrorism or cyber attacks that may affect our power plants or the markets our power plants or retail operations serve and our corporate 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;
•
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.
1
Given
the risks and uncertainties surrounding forward-looking statements, you should not place undue reliance on these statements. Many of these factors are beyond our ability to control or predict. Our forward-looking statements speak only as of the date of this Report. Other than as required by law, we undertake no obligation to update or revise forward-looking statements, whether as a result of new information, future events, or otherwise.
Where You Can Find Other Information
Our website is www.calpine.com. Information contained on our website
is not part of this Report. Information that we furnish or file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to, or exhibits included in, these reports are available for download, free of charge, on our website as soon as reasonably practicable after such materials are filed with or furnished to the SEC. Our SEC filings, including exhibits filed therewith, are also available on the SEC’s website at www.sec.gov. You may obtain and copy any document we furnish or file with the SEC at the SEC’s public reference room at 100 F Street, NE, Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the SEC’s public reference facilities
by calling the SEC at 1-800-SEC-0330. You may request copies of these documents, upon payment of a duplicating fee, by writing to the SEC at its principal office at 100 F Street, NE, Room 1580, Washington, D.C. 20549.
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PART I
Item 1.
Business
BUSINESS AND STRATEGY
Business
We
are a premier competitive power company with 80 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 shareholder value. We accomplish this through our focus on operational excellence at our power plants and in our customer and commercial activity, as well as through our disciplined approach to capital allocation.
On August 17, 2017, we entered into the Merger Agreement with Volt Parent, LP (“Volt Parent”) and Volt Merger Sub, Inc. (“Merger Sub”), a wholly-owned subsidiary of Volt Parent, pursuant to which Merger Sub will merge with and into Calpine, with Calpine surviving the Merger as a subsidiary of Volt Parent. On
December 15, 2017, the Merger was approved by our shareholders representing a majority of the outstanding shares of Calpine common stock.
At the effective time of the Merger, each share of Calpine common stock outstanding as of immediately prior to the effective time of the Merger (excluding certain shares as described in the Merger Agreement) will cease to be outstanding and be converted into the right to receive $15.25 per share in cash or approximately $5.6 billion in total. Calpine currently expects the Merger to be completed in the first quarter of 2018, subject to the receipt of certain regulatory approvals and the satisfaction or waiver of certain other customary closing conditions. For further information on the Merger and the Merger Agreement, please refer to the Current Report on Form 8-K filed on August 22, 2017 and
the proxy statement filed on November 14, 2017 by Calpine. The foregoing description of the Merger Agreement is subject to, and qualified in its entirety by, the full text of the Merger Agreement attached as an exhibit to the Form 8-K filed on August 22, 2017, and is incorporated by reference herein. See also Note 2 of the Notes to Consolidated Financial Statements for further information related to the Merger and the Merger Agreement.
We are one of the largest power generators in the U.S. measured by power produced. We own and operate primarily natural gas-fired and geothermal power plants in North America and have a significant presence in major competitive wholesale power markets in California (included in our West segment), Texas (included in our Texas segment) and the Northeast
and Mid-Atlantic regions (included in our East segment) of the U.S. Since our inception in 1984, we have been a leader in environmental stewardship. We have invested in clean power generation to become a recognized leader in developing, constructing, owning and operating an environmentally responsible portfolio of flexible and reliable power plants. Our portfolio is primarily comprised of two types of power generation technologies: 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
continue to focus on getting closer to our customers through expansion of our retail platform which began with the acquisition of Champion Energy in 2015 and was followed by the acquisitions of Calpine Solutions in late 2016 and North American Power in early 2017. Our retail portfolio has been established to provide an additional source of liquidity for our generation fleet as we hedge retail load from our wholesale generation assets as appropriate.
We sell power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities and other governmental entities, power marketers as well as retail commercial, industrial, governmental and residential customers. We purchase primarily natural gas and some fuel oil as fuel for our power plants and engage in related natural gas
transportation and storage transactions. We also purchase power for sale to our customers and purchase electric transmission rights to deliver power to our customers. Additionally, consistent with our Risk Management Policy, we enter into natural gas, power, environmental product, fuel oil and other physical and financial commodity contracts to hedge certain business risks and optimize our portfolio of power plants. Seasonality and weather can have a significant effect on our results of operations and are also considered in our hedging and optimization activities.
We assess our 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 reportable segments are West (including
geothermal), Texas and East (including Canada). Our portfolio, including partnership interests, consists of 80 power plants, including one under construction, with an aggregate current generation capacity of 25,967 MW and
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828 MW under construction. Inclusive of our power generation portfolio and our retail sales platforms, we serve customers in 25 states in the U.S. and in Canada and Mexico. Our fleet, including projects under construction, consists of 65 natural gas-fired combustion turbine-based plants, one natural gas and fuel oil-fired steam-based plant, 13 geothermal steam turbine-based plants and one photovoltaic solar plant.
Strategy
Our
goal is to be recognized as the premier competitive power company in the U.S. as viewed by our employees, shareholders, customers and policy-makers as well as the communities in which our facilities are located. We seek to deliver long-term 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 $387 billion in power sales in 2017 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 and the Midwest. In addition to our sales of electrical power to wholesale and retail customers, our power plants produce several ancillary products.
•
First, we are a provider of power to utilities, independent
electric system operators, industrial and agricultural companies, retail power providers, municipalities and other governmental entities, power marketers as well as retail commercial, industrial, governmental and residential customers. 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 (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 Midwest 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 sell RECs from our Geysers Assets in northern California. California has an RPS that
requires load serving entities to have RECs for a certain percentage of their demand for the purpose of guaranteeing a certain level of renewable generation in the state or in neighboring areas. Because geothermal is a renewable source of energy, we receive a REC for each MWh we produce and are able to sell our RECs to load serving entities. We also purchase RECs from other sources for resale to our customers.
•
Fourth, our cogeneration power plants produce steam, in addition to electricity, for sale to industrial customers for use in their manufacturing processes or heating, ventilation and air conditioning operations.
•
Fifth,
we provide ancillary service products to wholesale power markets. These products include the right for the purchaser to call on our generation to provide flexibility to the market and support operation of the electric grid.
In addition to the five products above, we are buyers and sellers of emission allowances and credits, including those under California’s AB 32 GHG reduction program, RGGI, the federal Acid Rain and CSAPR programs and emission reduction credits under the federal Nonattainment New Source Review program.
Although all of the products mentioned above contribute to our financial performance and are the primary components of our Commodity Margin, the most important are our sales of wholesale power and capacity. We utilize long-term customer contracts for our power
and steam sales where possible. For power and capacity that are not sold under customer contracts or
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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.
The Price and Supply of Natural Gas
Approximately 96%, or 24,847 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 tight, 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., natural gas prices are above coal prices in our Texas or East segments), increases in natural gas prices may increase our unhedged Commodity Margin
because our combined-cycle power plants in those markets are more fuel-efficient than conventional natural gas-fired technologies and peaking power plants. Conversely, decreases in natural gas prices may decrease our unhedged Commodity Margin. In these instances, our cost of production advantage relative to less efficient natural gas-fired generation is diminished on an absolute basis until the point we are cheaper than 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.
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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 2017, 31% of the power generated in the U.S. was fueled by natural gas, 30% by coal, 20% by nuclear facilities and the remaining 19% 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 is likely 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.
We actively manage our risk exposures
with a variety of physical and financial instruments with varying time horizons. These instruments include PPAs, tolling arrangements, Heat Rate swaps and options, retail power sales including through our retail affiliates, steam sales, buying and selling standard physical power and natural gas products, buying and selling exchange traded instruments, buying and selling environmental and capacity products, natural gas transportation and storage arrangements, electric transmission service and other contracts for the sale and purchase of power products. We utilize these instruments to maximize the risk-adjusted returns for our Commodity Margin.
At any point in time, the relative quantity of our products hedged or sold under longer-term contracts
is determined by the availability of forward product sales opportunities and our view of the attractiveness of the pricing available for forward sales. We have economically hedged a portion of our expected generation and natural gas portfolio as well as retail load supply obligations, where appropriate, mostly through power and natural gas forward physical and financial transactions including retail power sales; however, we currently remain susceptible to significant price movements for 2018 and beyond. When we elect to enter into these transactions, we are able to economically hedge a portion of our Spark Spread at pre-determined generation and price levels.
We conduct our hedging and optimization activities within a structured risk management framework based on controls, policies and procedures. We monitor these activities through active and ongoing management and oversight, defined roles and responsibilities, and daily
risk estimates and reporting. Additionally, we seek to manage the associated risks through diversification, by controlling position sizes, by using portfolio position limits, and by actively managing hedge positions to lock in margin. We are exposed to commodity price movements (both profits and losses) in connection with these transactions. These positions are
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included in and subject to our consolidated risk management portfolio position limits and controls structure. Our future hedged status and marketing and optimization activities are subject to change as determined by our commercial operations group, Chief Risk Officer, senior management and Board of Directors. For control purposes, we have VAR limits that govern the overall risk of our portfolio of
power plants, energy contracts, financial hedging transactions and other contracts. Our VAR limits, transaction approval limits and other risk related controls are dictated by our Risk Management Policy which is approved by our Board of Directors and by a committee comprised of members of our senior management and administered by our Chief Risk Officer’s organization. The Chief Risk Officer’s organization is segregated from the commercial operations unit and reports directly to our Audit Committee and Chief Financial Officer. Our Risk Management Policy is primarily designed to provide us with a degree of protection from significant downside commodity price risk exposure to our cash flows.
We have historically used interest rate hedging instruments
to adjust the mix between our fixed and variable rate debt. To the extent eligible, our interest rate hedging instruments have been designated as cash flow hedges, and changes in fair value are recorded in OCI to the extent they are effective with gains and losses reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings.
SEGMENT AND SIGNIFICANT CUSTOMER INFORMATION
See Note 17 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, 2017, 2016 and 2015.
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DESCRIPTION OF OUR POWER PLANTS
Geographic Diversity
Dispatch Technology
8
Power Plants in Operation
We own 80 power plants, including one under construction, with an aggregate generation capacity of 25,967 MW and 828 MW under construction.
Natural Gas-Fired Fleet
Our natural gas-fired power plants primarily utilize two types of designs: 2,260 MW of simple-cycle combustion turbines and 22,253 MW of combined-cycle combustion turbines and a small portion from conventional natural gas/oil-fired boilers with steam turbines. Simple-cycle combustion turbines burn natural gas or fuel oil to spin an electric generator to produce power. A combined-cycle unit combusts fuel like a simple-cycle combustion turbine and the exhaust heat is captured by a heat recovery boiler to create
steam which can then spin a steam turbine. Simple-cycle turbines are easier to maintain, but combined-cycle turbines operate with much higher efficiency. Each of our power plants currently in operation is capable of producing power for sale to a utility, another third-party end user, our retail customers or an intermediary such as a marketing company. At 15 of our power plants, we also produce thermal energy (primarily steam and chilled water), which can be sold to industrial and governmental users. These plants are called combined heat and power facilities.
Our Steam Adjusted Heat Rate for 2017 for the power plants we operate was 7,305 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 17 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. For the past 17 years, our Geysers Assets have reliably generated, on average, approximately six million MWh of renewable power per year. Unlike other renewable resources such as wind or sunlight, which depend on intermittent sources to generate power, geothermal power provides a consistent source of energy as evidenced by our Geysers Assets’ availability of approximately 94% in 2017.
We
inject water back into the steam reservoir, which extends the useful life of the resource and helps to maintain the output of our Geysers Assets. The water we inject comes from the condensate associated with the steam extracted to generate power, wells and creeks, as well as water purchase agreements for reclaimed water. We receive and inject an average of approximately 16 million gallons of reclaimed water per day into the geothermal steam reservoir at The Geysers where the water is naturally heated by the Earth, creating additional steam to fuel our Geysers Assets. Approximately 12 million gallons per day are received from the Santa Rosa Geysers Recharge Project, which we developed jointly with the City of Santa Rosa, and we receive, on average, approximately four million gallons a day from The Lake County Recharge Project from Lake
County. As a result of these recharge projects, MWh production has been relatively constant. We expect that, as a result of the water injection program, the reservoir at our Geysers Assets will be able to supply economic quantities of steam for the foreseeable future.
We periodically review our geothermal studies to help us assess the economic life of our geothermal reserves. Our most recent geothermal reserve study was conducted in 2015. Our evaluation of our geothermal reserves, including our review of any applicable independent studies conducted, indicated that our Geysers Assets should continue to supply sufficient steam to generate positive cash flows at least through 2073. In reaching this conclusion, our evaluation, consistent with the due diligence study of 2015, assumes that defined “proved reserves” are those quantities of geothermal energy which, by analysis of geological and engineering data, can be estimated
with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions, operating methods and government regulations.
We lease the geothermal steam fields from which we extract steam for our Geysers Assets. We have leasehold mineral interests in 105 leases comprising approximately 28,000 acres of federal, state and private geothermal resource lands in The
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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 2017 is:
•
27% related to leases with the federal government via the Office of Natural Resources Revenue,
•
29% related to leases with the California State Lands Commission and
•
44% related to leases with private landowners/leaseholders.
In
general, our geothermal leases grant us the exclusive right to drill for, produce and sell geothermal resources from these properties and the right to use the surface for all related purposes. Each lease requires the payment of annual rent until commercial quantities of geothermal resources are established. After such time, the leases require the payment of minimum advance royalties or other payments until production commences, at which time production royalties are payable on a monthly basis from 10 to 31 days (depending upon the lease terms) following the close of the production month. Such royalties and other payments are payable to landowners, state and federal agencies and others, and vary widely as to the particular lease. In general, royalties payable are calculated based upon a percentage of total gross revenue received by us associated with our geothermal leases. Each lease’s royalty calculation is based upon its percentage of revenue as calculated by its steam
generated relative to the total steam generated by our Geysers Assets as a whole.
Our geothermal leases are generally for initial terms varying from five to 20 years and for so long as geothermal resources are produced and sold. A few of our geothermal leases were signed in excess of 30 years ago. Our federal leases are, in general, for an initial 10-year period with renewal clauses for an additional 40 years for a maximum of 50 years. The 50-year term expires in 2024 for the majority of our federal leases. However, our federal leases allow for a preferential right to renewal for a second 40-year term on such terms and conditions as the lessor deems appropriate if, at the end of the initial 40-year term, geothermal steam is being produced or utilized in commercial quantities. The majority of our other leases run through the economic life of our Geysers Assets and provide for renewals so long as geothermal resources are being
produced or utilized, or are capable of being produced or utilized, in commercial quantities from the leased land or from land unitized with the leased land. Although we believe that we will be able to renew our leases through the economic life of our Geysers Assets on terms that are acceptable to us, it is possible that certain of our leases may not be renewed, or may be renewable only on less favorable terms.
In addition, we hold 40 geothermal leases comprising approximately 43,840 acres of federal geothermal resource lands in the Glass Mountain area in northern California, which is separate from The Geysers region. Four test production wells were drilled prior to our acquisition of these leases and we have drilled one test well since their acquisition, which produced commercial quantities of steam during flow tests. However, the properties subject to these leases have not been developed and there can be no assurance that
these leases will ultimately be developed.
Other Power Generation Technologies
We also have 725 MW of older, less efficient technology at our Edge Moor Energy Center which has conventional steam turbine technology. We also have 4 MW of capacity from solar power generation technology at our Vineland Solar Energy Center in New Jersey.
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Table of Operating Power Plants and Projects Under Construction and Advanced Development
Set forth below is certain information regarding our operating power plants and projects under construction and advanced development at December 31, 2017.
Projects
Under Construction and Advanced Development
Projects Under Construction
York
2 Energy Center
RFC
PA
Combined Cycle
100
%
668
828
n/a
Projects
Under Advanced Development
Washington
Parish Energy Center(11)
SERC
LA
Simple Cycle
100
%
—
361
n/a
Bluestone
Wind Farm(12)
NPCC
NY
Renewable
100
%
124
124
n/a
Total
operating power plants and projects
22,400
27,280
___________
(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). Wind capacities are based on nameplate capacity.
(2)
Natural gas-fired fleet peaking capacities are primarily derived on as-built as-designed peaking outputs based on site specific average summer temperatures and include power enhancement features such as heat recovery steam generator duct-firing, gas turbine power augmentation, and/or other power augmentation
features. For certain power plants with definitive contracts, capacities at contract conditions have been included. Oil-fired capacities reflect capacity test results.
(3)
These outputs do not factor in the typical MW loss and recovery profiles over time, which natural gas-fired turbine power plants display associated with their planned major maintenance schedules.
(4)
MWh
generation is shown here as our net operating interest.
(5)
We suspended operations to assess the future of these facilities.
(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)
Calpine
holds a 50% partnership interest in Whitby Cogeneration through its subsidiaries; however, it is operated by Atlantic Packaging Products Ltd.
(11)
A third party will purchase a 100% ownership interest in this power plant upon achieving commercial operation.
(12)
Once construction is complete, the wind facility will sell all of the RECs associated with the power produced to a third party under a 20-year PPA.
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.
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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.
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 on December 14, 2016. The area’s status has not yet been determined for the 2015 ozone standard, but is likely to be
in nonattainment as well, which could lead to further, more stringent regulation of NOx emissions from mobile sources and a number of industry sources, particularly the power industry.
Pursuant to authority granted under the CAA, the TCEQ adopted regulations to attain the earlier NAAQS for ozone including the establishment of a Cap-and-Trade program for NOx emitted by power plants in the Houston-Galveston-Brazoria ozone nonattainment area. We own and operate 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 more stringent ozone standard promulgated in 2015, allowable NOx emissions under this program could be reduced at some point in the future, which could cause us to incur additional compliance costs. However,
we cannot estimate such costs until such program changes are proposed and finalized.
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,
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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. The Clean Power Plan requires a reduction in GHG emissions from existing power plants of 32% from 2005 levels by 2030. We believe that we are positioned to comply with the guidelines of the Clean Power Plan. Litigation challenging the Clean Power Plan is ongoing. The current Presidential administration is taking actions to repeal the Clean Power Plan upon the basis that it exceeds the EPA’s authority and proposing emissions guidelines to replace
the Clean Power Plan. If the EPA successfully repeals and replaces the Clean Power Plan with other emissions guidelines, it is unclear what effect, if any, such emissions guidelines would have on our business.
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, and RGGI in the Northeast. The evolution of these programs could have a material effect on our business.
In both of these programs, a cap is established defining the maximum allowable emissions of GHGs emitted by sources subject to the program. Affected sources are required to hold one
allowance for each ton of CO2 emitted (and, in the case of California’s program, other GHGs) during the applicable compliance period. Both programs also contain provisions for the use of qualified offsets in lieu of allowances. Allowances are distributed through auctions or through allocations to affected companies. In addition, there are functional secondary markets for allowances. We obtain allowances in a variety of ways, including through bilateral or exchange transactions and pursuant to the terms of PPAs.
California: GHG - Cap-and-Trade Regulation
AB 32 requires the state to reduce statewide GHG emissions in reference to 1990 levels. To meet this mandate, the CARB has promulgated a number of regulations, including the Cap-and-Trade Regulation and Mandatory Reporting Rule, which took effect on January
1, 2012. 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. Senate Bill 32 amended AB 32 by requiring the CARB to ensure that statewide GHG emissions are reduced to at least 40% below 1990 levels by 2030. Assembly Bill (“AB”) 398 authorized extension of the Cap-and-Trade Regulation through 2030. AB 617 required the CARB to prepare a statewide strategy to reduce emissions of toxic air contaminants and criteria air pollutants in communities affected by a high cumulative exposure burden and the local air districts to prepare community emissions reduction programs to achieve emissions reductions within such communities, as identified by the CARB.
The California Cap-and-Trade market has been linked to the GHG Cap-and-Trade market in Québec and Ontario, Canada. The Governor of New York has also
previously announced that New York would explore the possibility of linking RGGI, a carbon market operating in nine northeastern states, with the California-Québec and Ontario markets.
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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, although we believe the net effect of the Cap-and-Trade Regulation will be beneficial to us, particularly by increasing the appeal of our Geysers Assets. While it is too early to predict whether any of our California natural gas-fired power plants may ultimately be subject to a requirement to reduce emissions under AB 617 or what such a requirement might entail, much of our California fleet already meets emissions
limits that are among the lowest in the U.S. and we do not anticipate that significant additional reductions will be required from our fleet pursuant to AB 617.
Northeast GHG Regulation: RGGI
Nine states in the Northeast participate in RGGI, a Cap-and-Trade program, which affects our power plants in Maine, Massachusetts, New Hampshire, New York and Delaware (together emitting about 5.4 million tons of CO2 annually).
We receive annual allocations from New York’s long-term contract set-aside pool to cover some of the CO2 emissions attributable to our PPAs at both the Kennedy International Airport Power Plant and Stony
Brook Power Plant. We do not anticipate any significant business or financial effect from RGGI, given the efficiency of our power plants in RGGI states.
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. 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.
Oregon: GHG - Cap and Invest Legislation
Legislation is currently under development in Oregon, Senate Bill 1070, that would create a GHG “cap and invest” trading program linked to the Western Climate Initiative jurisdictions implementing GHG trading programs, which currently consist of California, Ontario and Québec. Two versions of the legislation are currently being drafted for possible consideration by the Oregon House and Senate during its 35-day legislative session in February and March 2018. If enacted, Oregon would then develop regulations establishing the annual allowance budgets and governing the distribution of allowances, with the goal of holding joint auctions with the other Western Climate Initiative
participating jurisdictions possibly as soon as 2021.
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 50% of the power they sell to retail customers from renewable resources by 2020 and 2030, respectively, with intermediate targets leading up to 2020 and 2030. Behind-the-meter solar generally does not count towards California’s RPS
requirements. Under California’s RPS, there are limits on different “buckets” of procurement that can be used to satisfy the RPS. Load-serving entities must satisfy a growing fraction of their compliance obligations with renewable power from resources located in California or delivered into California within the hour, such as our Geysers Assets. The California legislature is considering increasing the RPS to 60% by 2030 and, potentially, a 100% CO2-free RPS by 2045; however, a vote on this proposal is not likely until the 2018 legislative session. While the RPS generally depresses wholesale energy prices, the intermittency of many renewable resources raises operational flexibility challenges that present opportunities for natural gas-fired generation to provide capacity and ancillary services products.
Other States
A
number of additional states have an RPS in place. Existing state-specific RPS requirements may change due to regulatory and/or legislative initiatives, and other states may consider implementing an enforceable RPS in the future. Our retail subsidiaries operate in states that have an RPS in place and are required to procure a certain amount of power from renewable sources or purchase renewable energy credits in order to comply with the RPS requirements.
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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 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 the Energy Policy Act of 2005 (“EPAct 2005”), we use geothermal re-injection wells to inject reclaimed wastewater back into the steam reservoir, which are subject to the underground injection control program. We believe that we are in compliance with Part C of the Safe Drinking Water Act.
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.
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.
The majority of our power plants are subject to FERC’s jurisdiction; however, certain power plants
qualify for available exemptions. FERC’s jurisdiction over exempt wholesale generators (“EWGs”) under the FPA applies to the majority of our power plants because they are EWGs or are owned by EWGs, except our EWGs located in ERCOT. Power plants located in ERCOT are exempt from many FERC regulations under the FPA. Many of our power plants that are not EWGs are operated as QFs under PURPA. Several of our affiliates have been granted authority to engage in sales at market-based rates and blanket authority to issue securities, and have also been granted certain waivers of FERC reporting and accounting regulations available to non-
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traditional public utilities; however, we cannot assure that such authorities or waivers will not be revoked for these affiliates
or will be granted in the future to other affiliates.
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 $1.2 million per violation for each day that the violation continues. The FPA also provides for the assessment of criminal fines and imprisonment for violations under Part II of the FPA. This penalty authority was enhanced in EPAct 2005.
Pursuant to EPAct 2005, NERC has been certified by the FERC as the Electric Reliability Organization to develop and enforce reliability standards and critical infrastructure protection standards, which protect the bulk power system against potential 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 $1.2 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 affiliates are either QFs or EWGs, none of our affiliates are currently subject to direct rate regulation by a state PUC. However, states may assert jurisdiction over the siting and construction of power generating facilities including QFs and EWGs and, with the exception of QFs, over the issuance of securities and the sale or other transfer of assets by these facilities. State PUCs also maintain extensive control over the procurement of wholesale power by the utilities that they regulate. Many of these utilities are our customers, and agreements between us and these counterparties often require approval by state PUCs.
Power Regions
The following is a brief overview of 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.
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.
ERCOT
ERCOT is the ISO that manages approximately 85% of Texas’ load and
an electric grid covering about 75% of the state, overseeing transactions associated with Texas’ competitive wholesale and retail power markets. FERC does not regulate wholesale sales of power in ERCOT. The PUCT exercises regulatory jurisdiction over the rates and services of any electric utility conducting business within Texas. Our subsidiaries that own power plants in Texas have power generation company status at the PUCT, and are either EWGs or QFs and are exempt from PUCT rate regulation. ERCOT ensures resource adequacy through an energy-only model. In ERCOT, there is a market offer price cap for energy and capacity services purchased by ERCOT. Under certain market conditions, the offer cap could be lower. Our subsidiaries are subject to the offer cap rules, but only for sales of power
and capacity services to ERCOT.
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PJM
PJM operates wholesale power markets, a locationally based energy market, a forward capacity market and ancillary service markets. PJM also performs transmission planning and operation for the region. The rules and regulations affecting PJM power markets and transmission are subject to change at any time.
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.
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.
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 $1.2 million per violation for each day that the violation continues. The NGA and NGPA also provide for the assessment of criminal fines and imprisonment time for violations.
Federal Regulation of Futures and Other Derivatives
CFTC Regulation of Futures Transactions
The CFTC has regulatory oversight of the futures markets, including trading on NYMEX for energy, and licensed futures professionals such as brokers, clearing members and large traders. In connection with its oversight of the futures markets and NYMEX, the CFTC regularly investigates market
irregularities and potential manipulation of those markets. Recent laws also give the CFTC certain powers with respect to broker-type markets referred to as “exempt commercial markets” or ECMs, including the Intercontinental Exchange. The CFTC monitors activities in the OTC, ECM and physical markets that may be undertaken for the purpose of influencing futures prices. With respect to ECMs, the CFTC exercises only light-handed regulation primarily related to trade reporting, price dissemination and record retention (including retention of fraudulent claims and allegations).
EMPLOYEES
At December 31, 2017, we employed 2,290 full-time employees, of whom 181 were represented by collective bargaining agreements.
One collective bargaining agreement, representing a total of 20 employees, will expire within one year. We have never experienced a work stoppage or a strike.
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Item 1A.
Risk Factors
Merger Related
Failure to complete the Merger, or to complete the Merger timely, as a result of the failure to obtain necessary regulatory approvals or to satisfy certain other closing conditions, could negatively affect our business
and the market price of Calpine common stock.
The Merger is subject to various closing conditions such as receipt of certain regulatory approvals in the United States, among other customary closing conditions. It is possible that a government entity may prohibit, delay or refuse to grant approval for the consummation of the Merger. If any condition to the closing of the Merger is not satisfied or, if permissible, waived, the Merger will not be completed. In addition, satisfying the conditions to the closing of the Merger may take longer than we expect. There can be no assurance that any of the outstanding conditions to closing will be satisfied or waived or that other events will not intervene to delay or result in the failure to consummate the Merger.
If the Merger is not completed for any reason, our shareholders would not receive any payment for their shares in connection with
the Merger while we will remain an independent public company, and our shares will continue to be traded on the NYSE. Depending on the circumstances that would have caused the Merger not to be completed, the price of our common stock may decline materially. If that were to occur, it is uncertain when, if ever, the price of the shares would return to the price levels at which the shares currently trade. In addition, any delay in closing or a failure to close the Merger could exacerbate any negative effect on our business and on our relationships with other parties with which we maintain business relationships, as well as negatively affect our ability to implement alternative business plans. Finally, if the Merger is not completed, our Board of Directors will, among other things, continue to evaluate and review our business operations, properties and capitalization, and make such changes as it deems appropriate and continue to seek to identify opportunities to enhance
shareholder value. However, there can be no assurance that any other transaction acceptable to Calpine will be available or that our business, prospects or results of operation will not be materially adversely affected.
Uncertainties associated with the Merger may cause us to lose key customers or suppliers and make it more difficult to retain and hire key personnel.
As a result of the uncertainty surrounding the conduct of our business during the pendency of the Merger, we may lose key customers and suppliers and our relationships with other parties with which we maintain business relationships may be materially adversely affected. Parties with which we maintain business relationships may experience uncertainty about our future and seek alternative relationships with third parties, seek to alter their business relationships with us or fail to extend an existing relationship with
us. In addition, our employees, including key personnel, may be uncertain about their future roles and relationships with us following the completion of the Merger, which may adversely affect our ability to retain them or to hire new employees.
Restrictions imposed on us pursuant to the Merger Agreement may prevent us from pursuing business opportunities, which could have a material adverse effect on our business, financial condition and results of operations.
The Merger Agreement restricts us from taking certain actions without Volt Parent’s consent while the Merger is pending. These restrictions may, among other matters, prevent us from pursuing otherwise attractive business opportunities, making certain investments or acquisitions, selling assets, engaging in capital expenditures in excess of certain agreed limits, incurring certain
indebtedness or making certain other changes to our business pending the closing of the Merger. These restrictions could have a material adverse effect on our business, financial condition and results of operations.
Commercial Operations
Our financial performance is affected by 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 and fluctuate substantially. Unlike most other commodities, power can only be stored on a very limited basis and generally must be produced concurrently with its use. As a result, power prices are subject to significant volatility due to supply and demand imbalances, especially in the day-ahead and spot markets. Long- and short-term
power and natural gas prices may also fluctuate substantially due to other factors outside of our control, including:
•
increases and decreases in generation capacity in our markets;
•
changes in power transmission or fuel transportation capacity constraints or inefficiencies;
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•
volatile
weather conditions, particularly unusually hot or mild summers or unusually cold or warm winters in our market areas;
•
quarterly and seasonal fluctuations;
•
an economic downturn which could negatively affect demand for power;
•
changes in the supply of commodities 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 and practices 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 and the CFTC;
•
sufficient
liquidity in the forward commodity markets to conduct our hedging activities;
•
some of our competitors (mainly utilities) receive entitlement-guaranteed rates of return on their capital investments, with returns that exceed market returns and may affect our ability to sell our power at economical rates;
•
structure and operating characteristics of our capacity markets such as our PJM capacity auctions and our NYISO markets; and
•
regulations
and market rules related to our RECs.
Accounting for our hedging activities may increase the volatility in our quarterly and annual financial results.
We engage in commodity-related marketing and price-risk management activities in order to economically hedge our 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 a result, we are unable to accurately predict the effect that our risk management decisions may have on our quarterly and annual financial results.
The
use of hedging agreements may not work as planned or fully protect us and could result in financial losses.
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.
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Our ability to enter into hedging agreements and manage our counterparty and customer credit risk could adversely affect us.
Our
wholesale counterparties, retail customers and suppliers may experience deteriorating credit. These conditions could cause counterparties in the natural gas and power markets, particularly in the energy commodity derivative markets that we rely on for our hedging activities, to withdraw from participation in those markets. If multiple parties withdraw from those markets, market liquidity may be threatened, which in turn could adversely affect our business and create more volatility in our earnings. Additionally, these conditions may cause our counterparties or customers to seek bankruptcy protection under Chapter 11 or liquidation under Chapter 7 of the U.S. Bankruptcy Code. Our credit risk may be exacerbated to the extent collateral held by us cannot be realized or is liquidated at prices not sufficient to recover the full amount of the exposure due to us. There can be no assurance that any such losses or impairments to the carrying value of our financial assets would
not materially and adversely affect our financial condition, results of operations and cash flows.
Competition in the power generation industry could adversely affect our performance.
The power generation industry is characterized by intense competition, and we encounter competition from utilities, industrial companies, marketing and trading companies and other independent power producers. This competition has put pressure on power utilities to lower their costs, including the cost of purchased power, and increasing competition in the supply of power in the future could increase this pressure. In addition, construction during the last decade has created excess power supply and higher reserve margins in the power trading markets, putting downward pressure on prices.
Other companies we compete with may have greater liquidity, greater access
to credit and other financial resources, lower cost structures, greater ability to incur losses, longer-standing relationships with customers, greater potential for profitability from ancillary services or greater flexibility in the timing of their sale of generation capacity and ancillary services than we do.
In certain situations, our PPAs and other contractual arrangements, including construction agreements, commodity contracts, maintenance agreements and other arrangements, may be terminated by the counterparty or customer and/or may allow the counterparty or customer to seek liquidated damages.
The situations that could allow a counterparty or customer to terminate the contract and/or seek liquidated
damages include:
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the cessation or abandonment of the development, construction, maintenance or operation of a power plant;
•
failure of a power plant to achieve construction milestones or commercial operation by agreed-upon deadlines;
•
failure of a power plant to achieve certain output or efficiency minimums;
•
our
failure to make any of the payments owed to the counterparty or to establish, maintain, restore, extend the term of or increase any required collateral;
•
failure of a power plant to obtain material permits and regulatory approvals by agreed-upon deadlines;
•
a material breach of a representation or warranty or our failure to observe, comply with or perform any other material obligation under the contract; or
•
events
of liquidation, dissolution, insolvency or bankruptcy.
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Revenue may be reduced significantly upon expiration or termination of our PPAs.
Some of the capacity from our existing portfolio is sold under long-term PPAs that expire at various times. We seek to sell any capacity not sold under long-term PPAs, on a short-term basis as market opportunities arise. Our non-contracted capacity is generally sold on the spot market at current market prices as merchant energy. When the terms of each of our various PPAs expire, it is possible that the price paid to us for the generation of power under subsequent arrangements or in short-term markets may be significantly less than the price that had been paid
to us under the PPA. 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 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.
Our retail subsidiaries may experience customer attrition or may not be able to originate new business at the same levels
as in the past which could adversely affect our performance.
There is extensive competition in the retail power markets in which our retail subsidiaries operate. Competitors may offer lower prices or other incentives which may attract customers away from our retail subsidiaries. We may also face competition from a number of other energy service providers, other energy industry participants, or nationally branded providers of consumer products and services who may develop business that will compete with our retail subsidiaries.
The introduction or expansion of competing technologies for power generation and demand-side
management tools could adversely affect our performance.
The power generation business has seen a substantial change in the technologies used to produce power. With federal and state incentives for the development and production of renewable sources of power, we have seen market penetration of competing technologies, such as wind, solar, and commercial-sized power storage. Additionally, the development of demand-side management tools and practices can effect peak demand requirements for some of our markets at certain times during the year. The continued development of subsidized, competing power generation technologies and significant development of demand-side management tools and practices could alter the market and price structure for power and negatively affect our financial condition, results of operations and cash flows.
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 and delivering power to transmission and distribution systems. These and other hazards can cause severe damage to and destruction of property,
plant and equipment and suspension of operations. In the worst circumstances, catastrophic events can cause significant personal injury or loss of life. Further, the occurrence of any one of these events may result in us being named as a defendant in lawsuits asserting claims for substantial damages. We maintain an amount of insurance protection that we consider adequate; however, we cannot provide any assurance that the insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we are subject.
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Additionally, we are party to various litigation matters, including regulatory and administrative proceedings arising out of the normal course of business. We review our litigation activities and determine if
an unfavorable outcome to us is considered “remote,”“reasonably possible” or “probable” as defined by U.S. GAAP. Where we have determined an unfavorable outcome is probable and is reasonably estimable, we accrue for potential litigation losses. A successful claim against us that is not fully insured could be material. The liability we may ultimately incur with respect to such litigation matters, in the event of a negative outcome, may be in excess of amounts currently accrued, if any. Where we determine an unfavorable outcome is not probable or reasonably estimable, we do not accrue for any potential litigation loss. The ultimate outcome of these litigation matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated. As a result, we give no assurance that such litigation matters would, individually or in the aggregate, not have a material adverse effect on our financial
condition, results of operations or cash flows. See also Note 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 fuel or fuel oil to our power plants. If these transmission and distribution systems are disrupted or capacity on those systems is inadequate, our ability to sell and deliver power products or obtain fuel may be hindered. ISOs that oversee transmission systems in regional power markets have imposed price limitations and other mechanisms to address volatility in their power markets. Existing congestion, as well as expansion of transmission
systems, could affect our performance, which in turn could adversely affect our business.
Our power project development and construction activities involve risk and may not be successful.
The development and construction of power plants is subject to substantial risks. In connection with the development of a power plant, we must generally obtain:
•
necessary power generation equipment;
•
governmental permits and approvals including environmental permits
and approvals;
•
fuel supply and transportation agreements;
•
sufficient equity capital and debt financing;
•
power transmission agreements;
•
water
supply and wastewater discharge agreements or permits; and
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.
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.
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Additionally, the PJM power market has 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 the PJM power market, 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;
•
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;
•
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 (including cyber attacks), 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, are subject to frequent low-level
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seismic disturbances and a persistent risk of wildfires. More significant seismic disturbances are possible. In addition, other areas in which we operate, particularly in Texas and the Southeast, 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. However, earthquake, property damage or business interruption insurance may be inadequate to cover all potential losses sustained in the event of serious damages to our power plants or disruptions to our wholesale and retail operations due to natural disasters.
In addition to physical damage to our power plants, the risk of future terrorist activity (including cyber attacks) could result in adverse changes in the insurance markets and disruptions in the power and fuel markets. These events could
also adversely affect the U.S. economy, create instability in the financial markets and, as a result, have an adverse effect on our ability to access capital on terms and conditions acceptable to us.
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.
We depend on computer and telecommunications systems we do not own or control and failures in our systems or a cybersecurity attack or breach of our IT systems or technology could significantly disrupt our business operations or result in sensitive customer information being compromised which would negatively materially affect our reputation and/or results of operations.
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 we or a third party that we rely on could incur interruptions from a loss of communications, hardware or software failures, a cybersecurity attack or a breach of our IT 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 of 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 of our IT systems or networks; however, none of these actual or attempted cyber attacks has had a material effect on our operations or financial condition.
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,
or our retail subsidiaries may be 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, 2017, our consolidated debt outstanding was $11.4 billion, of which approximately $8.8 billion was outstanding under our Senior Unsecured Notes, First Lien Term Loans and First Lien Notes.
In addition, we had $1,069 million issued in letters of credit and our pro rata share of unconsolidated subsidiary debt was approximately $128 million. Although we
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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.
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 or to repurchase equity issued by certain of our subsidiaries to third parties; 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. In addition, we believe these conditions have and may continue to have an adverse effect on the price of our common stock, which in turn may also reduce our ability to access capital or credit markets. 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
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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 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 of the First Lien Notes, 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.
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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.
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, 2017, we had $1,069 million issued in letters of credit under our Corporate Revolving Facility and other facilities, with $1.2 billion 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 sale of power, capacity and related products and the purchase and sale of 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
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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.
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, 2017, our subsidiaries had approximately $1.0 billion in debt from our CCFC subsidiary and approximately $1.5 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. The Consolidated Appropriations Act which extended the
production tax credit for wind through the end of 2016 with gradual decreases thereafter until the tax credit expires completely in 2019 and extended the 30% investment tax credit for solar through the end of 2019 with gradual decreases through 2021 after which the investment tax credit declines to 10% was enacted in December 2015. California has a RPS in effect and in 2015 enacted legislation requiring implementation of a 50% RPS by 2030. 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, primarily in Texas and California.
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).
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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 for 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.
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.
Currently, nine 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, 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.
In 2011, the EPA finalized regulations governing GHG emissions from major sources as well as emissions of criteria and hazardous air pollutants from the electric generation sector. We continue to monitor and actively participate in the EPA initiatives where we anticipate a material effect on our business.
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.
31
If
we were deemed to have market power in certain markets as a result of the ownership of our stock by certain significant shareholders, 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 shareholder 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 shareholders 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.
Our business may be materially affected by changes to fiscal and tax policies. Potentially negative or unexpected tax consequences of these policies, or the uncertainty surrounding their potential effects, could adversely affect
our financial condition, results of operations or cash flows.
The Tax Cuts and Jobs Act (the “Act”) was signed into law on December 22, 2017. This legislation makes significant changes to the U.S. Internal Revenue Code. Such changes include a reduction in the corporate tax rate and limitations on certain corporate deductions and credits, among other changes. The Act requires complex computations not previously provided in U.S. tax law. As such, the application of accounting guidance for such items is currently uncertain. We have provided a provisional estimate on the effect of the Act in our Consolidated Financial Statements. As additional regulatory guidance is issued by the applicable taxing authorities and accounting treatment is clarified, this could result in refinement of the estimates of the effect of the Act on our Consolidated Financial Statements.
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 have regional offices in Dublin, California, Wilmington, Delaware, an engineering, construction and maintenance services office in Pasadena, Texas and government affairs offices in Washington D.C., Sacramento, California and Austin, Texas. We operate
our business through a variety of divisions, subsidiaries and affiliates.
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.
32
PART II
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market
Information and Stockholder Matters
Calpine Corporation common stock is traded on the NYSE under the symbol “CPN”. The following table sets forth the high and low sales price per share for our common stock for each quarter of the years 2017 and 2016, as reported on the NYSE.
High
Low
2017
First
Quarter
$
12.60
$
10.53
Second Quarter
14.35
9.30
Third
Quarter
14.94
12.86
Fourth Quarter
15.16
14.60
2016
First
Quarter
$
16.49
$
11.53
Second Quarter
16.07
13.22
Third
Quarter
15.12
11.97
Fourth Quarter
13.22
10.39
As of December 31,
2017, there were 80 registered shareholders of record of our common stock according to our stock transfer agent.
We have never paid cash dividends on our common stock. Future cash dividends, if any, will be at the discretion of our Board of Directors and will depend upon, among other things, our future operations and earnings, capital requirements, general financial condition, contractual and financing restrictions and such other factors as our Board of Directors may deem relevant.
Repurchase of Equity Securities
Period
(a)
Total Number of
Shares Purchased(1)
(b)
Average Price
Paid Per Share
(c)
Total Number
of
Shares Purchased
as Part of
Publicly Announced
Plans or Programs(2)
(d)
Maximum Dollar Value of Shares That May
Yet Be Purchased
Under the Plans or
Programs (in millions)
October
3,469
$
14.87
—
$
307
November
13,715
$
15.02
—
$
307
December
62,581
$
15.07
—
$
307
Total
79,765
$
15.05
—
$
307
___________
(1)
Represents
shares withheld by us to satisfy tax withholding obligations associated with the vesting of restricted stock awarded to employees during the fourth quarter of 2017.
(2)
In November 2014, our Board of Directors authorized an increase in the total authorization of our multi-year share repurchase program to $1.0 billion. There is no expiration date on the repurchase authorization and the amount and timing of future share repurchases, if any, will be determined as market and business conditions warrant.
33
Stock
Performance Graph
The performance graph below compares cumulative return on our common stock for the period December 31, 2012 through December 31, 2017, with the cumulative return of Standard & Poor’s 500 Index (S&P 500) and the S&P 500 Utilities Index.
The graph below compares each period assuming that $100 was invested on December 31, 2012 in our common stock and each of above indices and that all dividends are reinvested. The returns shown below may not be indicative of future performance.
Net income (loss) per common share attributable to Calpine
$
(0.95
)
$
0.26
$
0.65
$
2.34
$
0.03
Diluted
earnings (loss) per common share:
Net income (loss) per common share attributable to Calpine
$
(0.95
)
$
0.26
$
0.64
$
2.31
$
0.03
Balance
Sheet data:
Total assets(1)
$
16,453
$
17,493
$
16,849
$
16,089
$
15,846
Short-term
debt and capital lease obligations
$
225
$
748
$
221
$
199
$
204
Long-term
debt and capital lease obligations
$
11,180
$
11,431
$
11,716
$
10,933
$
10,751
____________
(1)
During
the third quarter of 2017, we elected to begin offsetting fair value amounts associated with our derivative instruments and related cash collateral and margin deposits on our Consolidated Balance Sheets that are executed with the same counterparty under master netting arrangements. This change in presentation is retrospectively reflected for all periods presented. See Note 3 of the Notes to Consolidated Financial Statements for a further description of the change in accounting principle associated with our election to offset fair value amounts associated with our derivative instruments.
35
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 (included in our West segment), Texas (included in our Texas segment) and the Northeast and Mid-Atlantic regions (included in our East segment) of the U.S. We sell power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities and other governmental entities, power marketers as well as retail commercial, industrial, governmental and residential customers. We continue to focus on getting closer to our customers through expansion of our retail platform which began with the acquisition of Champion Energy in 2015 and was followed by the acquisitions of Calpine Solutions
in late 2016 and North American Power in early 2017. We purchase primarily natural gas and some fuel oil as fuel for our power plants and engage in related natural gas transportation and storage transactions. We also purchase power for sale to our customers and purchase electric transmission rights to deliver power to our customers. Additionally, consistent with our Risk Management Policy, we enter into natural gas, power, environmental product, fuel oil and other physical and financial commodity contracts to hedge certain business risks and optimize our portfolio of power plants.
On August 17, 2017, we entered into the Merger Agreement with Volt Parent, LP (“Volt Parent”) and Volt Merger Sub, Inc. (“Merger Sub”), a wholly-owned subsidiary of Volt Parent, pursuant to which
Merger Sub will merge with and into Calpine, with Calpine surviving the Merger as a subsidiary of Volt Parent. On December 15, 2017, the Merger was approved by our shareholders representing a majority of the outstanding shares of Calpine common stock.
At the effective time of the Merger, each share of Calpine common stock outstanding as of immediately prior to the effective time of the Merger (excluding certain shares as described in the Merger Agreement) will cease to be outstanding and be converted into the right to receive $15.25 per share in cash or approximately $5.6 billion in total. Calpine currently expects the Merger to be completed in the first quarter of 2018, subject to the receipt of certain regulatory approvals and the satisfaction or waiver of certain other customary closing conditions. See Note 2 of the Notes to Consolidated Financial Statements for further information
related to the Merger and the Merger Agreement.
Below are our results of operations for the year ended December 31, 2017, as compared to the same period in 2016 (in millions, except for percentages and operating performance metrics). 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.
Net income attributable to the noncontrolling interest
(18
)
(19
)
1
5
Net
income (loss) attributable to Calpine
$
(339
)
$
92
$
(431
)
#
2017
2016
Change
% Change
Operating
Performance Metrics:
MWh generated (in thousands)(1)(2)
93,114
107,264
(14,150
)
(13
)
Average
availability(2)
86.8
%
90.5
%
(3.7
)%
(4
)
Average total MW in operation(1)
25,193
26,368
(1,175
)
(4
)
Average
capacity factor, excluding peakers
46.6
%
51.2
%
(4.6
)%
(9
)
Steam Adjusted Heat Rate(2)
7,305
7,324
19
—
__________
#
Variance
of 100% or greater
(1)
Represents generation and capacity from power plants that we both consolidate and operate. See “— Description of Our Power Plants – Table of Operating Power Plants and Projects Under Construction and Advanced Development” for our total equity generation and capacities.
(2)
Generation, average availability and Steam Adjusted Heat Rate exclude power plants and units that are inactive.
37
We
evaluate our Commodity revenue and Commodity expense on a collective basis because the price of power and natural gas tend to move together as the price for power is generally determined by the variable operating cost of the next marginal generator to be dispatched to meet demand. The spread between our Commodity revenue and Commodity expense represents a significant portion of our Commodity Margin. Our financial performance is correlated to how we maximize our Commodity Margin through management of our portfolio of power plants, as well as our hedging and optimization activities. See additional segment discussion in “Commodity Margin by Segment.”
Commodity revenue, net of Commodity expense, increased $56 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, primarily due to (favorable
variances are shown without brackets while unfavorable variances are shown with brackets):
(in millions)
$
150
Higher energy margins due to increased contribution from retail activity
following the acquisitions of Calpine Solutions in December 2016 and North American Power in January 2017 and higher realized Spark Spreads in our West and Texas segments. The increase was partially offset by a reduction in energy margin due to lower Spark Spreads in our East segment and lower generation across all segments
49
Higher regulatory capacity revenue primarily in our East segment
(40
)
A natural gas pipeline transportation
billing credit received in our West segment during the second quarter of 2016 with no similar credit received in 2017
(55
)
The net period-over-period effect of our portfolio management activities, primarily including the sales of the 375 MW Mankato Power Plant in October 2016 and the 599 MW Osprey Energy Center in January 2017
(48
)
Year-over-year change in contract
amortization, lease levelization related to tolling contracts and other(1)
$
56
__________
(1)
Commodity Margin excludes amortization expense related to contracts
recorded at fair value, non-cash GAAP-related adjustments to levelize revenues from tolling agreements, Commodity revenue and Commodity expense attributable to the noncontrolling interest and other unusual or non-recurring items.
Mark-to-market gain/loss, net from hedging our future generation, fuel supply requirements and retail activities had an unfavorable variance of $170 million primarily driven by the change in forward commodity prices on our derivative contracts during the year ended December 31, 2017.
Our normal, recurring operating and maintenance expense increased by $2 million during 2017 compared to 2016 after excluding the effect of a $68 million increase associated with the expansion of our retail portfolio through
the acquisitions of Calpine Solutions in December 2016 and North American Power in January 2017 partially offset by the period-over-period effect of power plant portfolio changes, a $23 million increase in severance and other employee-related costs, a $6 million increase in equipment failure costs primarily due to Delta Energy Center partially reduced by the receipt of insurance proceeds, and a $4 million increase in major maintenance expense resulting from our plant outage schedule.
Depreciation and amortization expense increased by $62 million during 2017 compared to 2016 primarily due to the acquisitions of Calpine Solutions and North American Power in December 2016 and January 2017, respectively, and the reclassification of South Point Energy Center from held for sale to held and used during the first quarter of 2017.
General and other administrative expense increased by $15
million for the year ended December 31, 2017 compared to 2016 primarily due to higher stock-based compensation expense resulting from an increase in the value of our performance share units and a change in the overall mix of awards granted during the year ended December 31, 2017 and the acquisitions of Calpine Solutions and North American Power in December 2016 and January 2017, respectively.
Other operating expenses increased by $6 million for the year ended December 31, 2017 compared to 2016 primarily due to Merger-related costs associated with legal, investment banking and other professional fees associated with the Merger partially offset by lower project development costs in 2017 compared to 2016. See Note 2 of the Notes to Consolidated Financial Statements for further information
related to the Merger and the Merger Agreement.
During the year ended December 31, 2017, we recorded impairment losses of approximately $41 million to adjust the carrying value of turbine equipment to fair value following the initiation of marketing efforts during 2017 as well as an impairment loss related to our South Point Energy Center. During the year ended December 31, 2016, we recorded impairment losses of approximately $13 million related to the potential sale of our South Point Energy Center. See Note 4 of the Notes to Consolidated Financial Statements for further information regarding the sale of South Point Energy Center which was denied by the Nevada Public Utility Commission in February 2017.
38
In
line with our strategy to focus on competitive wholesale markets and sell or contract power plants located in power markets outside our strategic concentration, we completed the sale of the Osprey Energy Center and Mankato Power Plant in our East segment on January 3, 2017 and October 26, 2016, respectively, resulting in a gain on sale of assets, net of $27 million and $157 million during the years ended December 31, 2017 and 2016, respectively. See Note 4 of the Notes to Consolidated Financial Statements for further information regarding the sales of Osprey Energy Center and Mankato Power Plant.
Debt modification and extinguishment costs
for the year ended December 31, 2017, primarily consisted of $21 million in connection with the redemption of our 2023 First Lien Notes in March 2017, $4 million from the write-off of debt issuance costs associated with the repayment of our 2017 First Lien Term Loan and $12 million from the write-off of debt issuance costs associated with the repayment of our CCFC Term Loans in December 2017. Debt modification and extinguishment costs for the year ended December 31, 2016, consisted of $15 million from the write-off of deferred financing costs in connection with the repayment in May 2016 of a portion of our First Lien Term Loans maturing in 2019 and 2020, $5 million from the write-off of debt issuance costs in connection with the repurchase of a portion of our 2023 First Lien Notes in December 2016 and $5 million associated with the refinancing of project debt in November
2016.
During the year ended December 31, 2017, we recorded an income tax expense of $8 million compared to an income tax expense of $48 million for the year ended December 31, 2016. The favorable year-over-year change primarily resulted from a favorable adjustment to our reserve for uncertain tax positions in 2017 and acquisitions and domestic restructuring activities that occurred in 2016.
Below are our
results of operations for the year ended December 31, 2016, as compared to the same period in 2015 (in millions, except for percentages and operating performance metrics). 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.
Net income attributable to the noncontrolling interest
(19
)
(14
)
(5
)
(36
)
Net
income attributable to Calpine
$
92
$
235
$
(143
)
(61
)
2016
2015
Change
% Change
Operating
Performance Metrics:
MWh generated (in thousands)(1)(2)
107,264
112,150
(4,886
)
(4
)
Average
availability(2)
90.5
%
89.2
%
1.3
%
1
Average total MW in operation(1)
26,368
25,785
583
2
Average
capacity factor, excluding peakers
51.2
%
55.6
%
(4.4
)%
(8
)
Steam Adjusted Heat Rate(2)
7,324
7,306
(18
)
—
__________
#
Variance
of 100% or greater
(1)
Represents generation and capacity from power plants that we both consolidate and operate. See “— Description of Our Power Plants – Table of Operating Power Plants and Projects Under Construction and Advanced Development” for our total equity generation and capacities.
(2)
Generation, average availability and Steam Adjusted Heat Rate exclude power plants and units that are inactive.
40
We
evaluate our Commodity revenue and Commodity expense on a collective basis because the price of power and natural gas tend to move together as the price for power is generally determined by the variable operating cost of the next marginal generator to be dispatched to meet demand. The spread between our Commodity revenue and Commodity expense represents a significant portion of our Commodity Margin. Our financial performance is correlated to how we maximize our Commodity Margin through management of our portfolio of power plants, as well as our hedging and optimization activities. See additional segment discussion in “Commodity Margin by Segment.”
Commodity revenue, net of Commodity expense, decreased $288 million for the year ended December 31, 2016, compared to the year ended December 31, 2015, primarily due to (favorable
variances are shown without brackets while unfavorable variances are shown with brackets):
(in millions)
$
(215
)
Lower energy margins due to decreased contribution from wholesale hedges, lower realized Spark Spreads in our Texas and
West segments and the expiration of the Pastoria Energy Center PPA. These factors were partially offset by increased contribution from our retail hedging activity and the positive effect of a new PPA associated with our Morgan Energy Center in the East segment
(44
)
Lower regulatory capacity revenue primarily in the East and West segments at our power plants which were fully operational period-over-period
40
A
natural gas pipeline transportation billing credit received in the West segment
37
The net year-over-year effect of our portfolio management activities, including the acquisition of our 695 MW Granite Ridge Energy Center on February 5, 2016 and the commencement of commercial operations at our 309 MW Garrison Energy Center in June 2015 partially offset by the sale of our 375 MW Mankato Power Plant in October 2016 and the expiration of the operating lease related to the Greenleaf power plants in June 2015
(106
)
Year-over-year
change in contract amortization, lease levelization related to tolling contracts and other(1)
$
(288
)
__________
(1)
Commodity
Margin excludes amortization expense related to contracts recorded at fair value, non-cash GAAP-related adjustments to levelize revenues from tolling agreements, Commodity revenue and Commodity expense attributable to the noncontrolling interest and other unusual or non-recurring items.
Mark-to-market gain/loss from hedging our future generation, retail activities and fuel needs had a favorable variance of $112 million primarily driven by a decrease in net mark-to-market losses in the current year as compared to the prior year.
Our normal, recurring operating and maintenance expense decreased $38 million during 2016 compared to 2015. The decrease in our normal, recurring operating and maintenance expense was primarily due to a $16 million decrease in repairs and maintenance
expense and production-related expenses, a $7 million reduction in equipment failure costs related to outages, a $6 million decrease primarily from lower property taxes associated with two power plants in our Texas segment and a $9 million decrease in other miscellaneous expenses. The remaining net decrease of $3 million includes a $30 million decrease in major maintenance expense resulting from our plant outage schedule and costs from scrap parts related to outages, a $24 million decrease related to costs associated with a wildfire at our Geysers Assets in September 2015, a $40 million increase attributable to power plant portfolio changes and the acquisitions of our retail subsidiaries and an $11 million increase in stock based compensation expense and other miscellaneous items.
In line with our strategy to focus on competitive wholesale
markets and sell or contract power plants located in power markets outside our strategic concentration, we completed the sale of the Mankato Power Plant in our East segment on October 26, 2016, resulting in a gain on sale of assets, net of $157 million during the year ended December 31, 2016. In addition, we entered into an asset sale agreement on April 1, 2016 for the sale of substantially all of the assets comprising our South Point Energy Center to Nevada Power Company d/b/a NV Energy for approximately $76 million which resulted in an impairment loss of approximately $13 million that was recorded during the first quarter of 2016. See Note 4 of the Notes to Consolidated Financial Statements for further information regarding the
sale of South Point Energy Center which was denied by the Nevada Public Utility Commission in February 2017.
Debt modification and extinguishment costs for the year ended December 31, 2016, consisted of $15 million from the write-off of debt issuance costs in connection with the repayment in May 2016 of a portion our First Lien Term Loans maturing in 2019 and 2020, $5 million from the write-off of debt issuance costs in connection with repurchase of a portion of our 2023 First Lien Notes in December 2016 and $5 million associated with the refinancing of project debt in November 2016. Debt modification and extinguishment costs for the year ended December 31, 2015, consisted of $26 million in debt extinguishment costs in connection with the repurchases of a portion of our 2023 First Lien Notes, which is comprised of $22 million
of prepayment penalties and
41
$4 million associated with the write-off of debt issuance costs and $13 million in debt modification costs related to the issuance of our 2024 First Lien Term Loan in May 2015.
Other (income) expense, net increased by $10 million during 2016 compared to 2015 primarily due to a $5 million increase related to credit fees associated with our retail operations during 2016 and a $5 million increase resulting from a foreign currency translation loss related to our Canadian subsidiaries.
During the year ended December 31,
2016, we recorded income tax expense of $48 million compared to income tax benefit of $76 million for the year ended December 31, 2015. The unfavorable year-over-year change primarily resulted from an internal restructuring during 2015 of certain of our international entities by moving certain foreign subsidiaries under a different foreign parent. This restructuring resulted in our ability to further utilize foreign NOLs that were previously unavailable to offset the income tax obligation on future earnings and, thus, resulted in a partial release of our valuation allowance recorded against our NOLs. Additionally, the unfavorable year-over-year change resulted from recent acquisitions and domestic restructurings.
42
COMMODITY MARGIN BY SEGMENT
We use Commodity Margin to assess reportable segment performance. Commodity Margin includes revenues 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 activity less costs from our fuel and purchased energy expenses, commodity transmission and transportation expenses, environmental compliance expenses and ancillary retail expense. We believe that Commodity Margin is a useful tool for assessing the performance of our core operations and is a key operational measure of profit reviewed by our chief operating decision maker. See Note 17 of the Notes
to Consolidated Financial Statements for a reconciliation of Commodity Margin to income (loss) from operations by segment.
The following tables show our Commodity Margin and related operating performance metrics by segment for the years ended December 31, 2017 and 2016 (exclusive of the noncontrolling interest). In the comparative tables below, favorable variances are shown without brackets while unfavorable variances are shown
with brackets. The MWh generated by segment below represent generation from power plants that we both consolidate and operate. Generation, average availability and Steam Adjusted Heat Rate exclude power plants and units that are inactive.
West:
2017
2016
Change
% Change
Commodity
Margin (in millions)
$
1,065
$
991
$
74
7
Commodity
Margin per MWh generated
$
48.53
$
37.74
$
10.79
29
MWh
generated (in thousands)
21,946
26,256
(4,310
)
(16
)
Average availability
83.2
%
92.0
%
(8.8
)%
(10
)
Average
total MW in operation
7,425
7,425
—
—
Average capacity factor, excluding peakers
35.5
%
43.2
%
(7.7
)%
(18
)
Steam
Adjusted Heat Rate
7,321
7,277
(44
)
(1
)
West — Commodity Margin in our West segment increased by $74 million, or 7%, for the year ended
December 31, 2017 compared to 2016, primarily due to the expansion of our retail hedging activities following the acquisition of Calpine Solutions in December 2016 and higher generation margin where we realized higher Spark Spreads during hours in which we generated, particularly evening peak times. The year-over-year increase in Commodity Margin was partially offset by receipt of a $40 million natural gas pipeline transportation billing credit during the second quarter of 2016. Generation decreased 16% primarily resulting from an increase in hydroelectric generation in the region and an extended outage at our Delta Energy Center in 2017. Our Delta Energy Center was fully restored to service in the fourth quarter of 2017.
Texas:
2017
2016
Change
% Change
Commodity
Margin (in millions)
$
665
$
655
$
10
2
Commodity
Margin per MWh generated
$
15.42
$
14.04
$
1.38
10
MWh
generated (in thousands)
43,117
46,646
(3,529
)
(8
)
Average availability
89.3
%
90.3
%
(1.0
)%
(1
)
Average
total MW in operation
8,853
9,191
(338
)
(4
)
Average capacity factor, excluding peakers
55.6
%
57.8
%
(2.2
)%
(4
)
Steam
Adjusted Heat Rate
7,137
7,143
6
—
Texas — Commodity Margin in our Texas segment increased by $10 million, or 2%, for the year
ended December 31, 2017 compared to 2016, primarily due to higher market Spark Spreads in the Houston Zone. The year-over-year increase in Commodity Margin was partially offset by lower contribution from hedges and the retirement of our 400 MW Clear Lake Power Plant in February 2017. Generation decreased 8% primarily resulting from higher natural gas prices during the year ended December 31, 2017 compared to 2016.
43
East:
2017
2016
Change
% Change
Commodity
Margin (in millions)
$
978
$
958
$
20
2
Commodity
Margin per MWh generated
$
34.87
$
27.88
$
6.99
25
MWh
generated (in thousands)
28,051
34,362
(6,311
)
(18
)
Average availability
86.7
%
89.7
%
(3.0
)%
(3
)
Average
total MW in operation
8,915
9,752
(837
)
(9
)
Average capacity factor, excluding peakers
46.2
%
50.4
%
(4.2
)%
(8
)
Steam
Adjusted Heat Rate
7,568
7,617
49
1
East — Commodity Margin in our East segment increased by $20 million, or 2%, for the year
ended December 31, 2017 compared to 2016, primarily due to the expansion of our retail hedging activities following the acquisitions of Calpine Solutions in December 2016 and North American Power in January 2017, higher regulatory capacity revenue in ISO-NE and the positive effect of a new PPA associated with our Morgan Energy Center which became effective in February 2016. The year-over-year increase in Commodity Margin was partially offset by the sales of the 375 MW Mankato Power Plant in October 2016 and the 599 MW Osprey Energy Center in January 2017, the expiration of a PPA associated with our York Energy Center in May 2017 and lower Spark Spreads during the year ended December 31, 2017 compared to 2016. Generation decreased 18% primarily resulting from the power plant sales previously discussed.
The following tables show our Commodity Margin and related operating performance metrics by segment for the years ended December 31, 2016 and 2015 (exclusive of the noncontrolling interest). In the comparative tables below, favorable variances are shown without brackets while unfavorable variances are shown with brackets. The MWh generated by segment below represent generation from power plants that we both consolidated and operate. Generation, average availability and Steam Adjusted Heat Rate exclude
power plants and units that are inactive.
West:
2016
2015
Change
% Change
Commodity
Margin (in millions)
$
991
$
1,106
$
(115
)
(10
)
Commodity
Margin per MWh generated
$
37.74
$
31.75
$
5.99
19
MWh
generated (in thousands)
26,256
34,836
(8,580
)
(25
)
Average availability
92.0
%
89.2
%
2.8
%
3
Average
total MW in operation
7,425
7,475
(50
)
(1
)
Average capacity factor, excluding peakers
43.2
%
56.8
%
(13.6
)%
(24
)
Steam
Adjusted Heat Rate
7,277
7,320
43
1
West — Commodity Margin in our West segment decreased by $115 million, or 10%, for the year
ended December 31, 2016 compared to the year ended December 31, 2015, primarily due to lower contribution from hedges, as we realized lower power prices at our Geysers Assets resulting from lower forward natural gas prices. Also contributing to the year-over-year decrease in Commodity Margin was the expiration of a PPA and a resource adequacy contract at our Pastoria Energy Center in December 2015 and the expiration of the operating lease related to the Greenleaf power plants in June 2015. The year-over-year decrease in Commodity Margin was partially offset by the receipt of a $40 million natural gas pipeline transportation billing credit during the second quarter of 2016. Generation decreased 25% primarily due to the suspension of operations at our Sutter Energy Center in 2016,
the reclassification of our South Point Energy Center to inactive reserve in 2016 and an increase in hydroelectric generation in the region during the year ended December 31, 2016 compared to the same period in 2015.
44
Texas:
2016
2015
Change
% Change
Commodity
Margin (in millions)
$
655
$
736
$
(81
)
(11
)
Commodity
Margin per MWh generated
$
14.04
$
15.37
$
(1.33
)
(9
)
MWh
generated (in thousands)
46,646
47,873
(1,227
)
(3
)
Average availability
90.3
%
89.4
%
0.9
%
1
Average
total MW in operation
9,191
9,191
—
—
Average capacity factor, excluding peakers
57.8
%
59.5
%
(1.7
)%
(3
)
Steam
Adjusted Heat Rate
7,143
7,089
(54
)
(1
)
Texas — Commodity Margin in our Texas segment decreased by $81 million, or 11%, for the year ended
December 31, 2016 compared to the year ended December 31, 2015, primarily due to lower realized Spark Spreads resulting from a decrease in hedge value and lower market liquidations, partially offset by positive contribution from our retail hedging activity following the acquisitions of Champion Energy and Calpine Solutions in October 2015 and December 2016, respectively.
East:
2016
2015
Change
% Change
Commodity
Margin (in millions)
$
958
$
944
$
14
1
Commodity
Margin per MWh generated
$
27.88
$
32.06
$
(4.18
)
(13
)
MWh
generated (in thousands)
34,362
29,441
4,921
17
Average availability
89.7
%
89.0
%
0.7
%
1
Average
total MW in operation
9,752
9,119
633
7
Average capacity factor, excluding peakers
50.4
%
48.8
%
1.6
%
3
Steam
Adjusted Heat Rate
7,617
7,663
46
1
East — Commodity Margin in our East segment increased by $14 million for the year ended December
31, 2016 compared to the year ended December 31, 2015, primarily due to the net year-over-year effect of our portfolio management activities, including the acquisition of our 695 MW Granite Ridge Energy Center on February 5, 2016, the commencement of commercial operations at our 309 MW Garrison Energy Center in June 2015, partially offset by the sale of our 375 MW Mankato Power Plant in October 2016. Also contributing to the year-over-year increase in Commodity Margin was the positive effect of a new PPA associated with our Morgan Energy Center, which became effective in February 2016, and higher contribution from our retail hedging activity during 2016 following the acquisitions of Champion Energy and Calpine Solutions in October 2015 and December 2016, respectively. The year-over-year increase in Commodity Margin was partially offset by lower contribution from hedges
in 2016 compared to 2015 and lower regulatory capacity revenue in PJM. Generation increased 17% primarily due to the acquisition of our 695 MW Granite Ridge Energy Center and the commencement of commercial operation at our 309 MW Garrison Energy Center.
45
LIQUIDITY AND CAPITAL RESOURCES
We maintain a strong focus on liquidity. We manage our liquidity to help provide access to sufficient funding to meet our business needs and financial obligations throughout business cycles.
Our business is capital intensive. Our ability to successfully implement our strategy is dependent on the continued availability
of capital on attractive terms. In addition, our ability to successfully operate our business is dependent on maintaining sufficient liquidity. We believe that we have adequate resources from a combination of cash and cash equivalents on hand, cash expected to be generated from future operations and availability under our Corporate Revolving Facility to continue to meet our obligations as they become due.
Liquidity
The following table provides a summary of our liquidity position at December 31, 2017 and 2016 (in millions):
2017
2016
Cash
and cash equivalents, corporate(1)
$
228
$
345
Cash and cash equivalents, non-corporate
56
73
Total
cash and cash equivalents
284
418
Restricted cash
159
188
Corporate Revolving Facility availability(2)
1,161
1,255
CDHI
letter of credit facility availability
56
50
Total current liquidity availability(3)
$
1,660
$
1,911
____________
(1)
Includes
$4 million and $16 million of margin deposits posted with us by our counterparties at December 31, 2017 and 2016, respectively. See Note 10 of the Notes to Consolidated Financial Statements for further information related to our collateral.
(2)
Our ability to use availability under our Corporate Revolving Facility is unrestricted.
(3)
Our ability to use corporate cash and cash
equivalents is unrestricted. See Note 3 of the Notes to Consolidated Financial Statements for a description of the restrictions on our use of non-corporate cash and cash equivalents and restricted cash. Our $300 million CDHI letter of credit facility is restricted to support certain obligations under PPAs and power transmission and natural gas transportation agreements.
Our principal source for future liquidity is cash flows generated from our operations. We believe that cash on hand and expected future cash flows from operations will be sufficient to meet our liquidity needs for our operations, both in the near and longer term. See “Cash Flow Activities” below for a further discussion of our change in cash and cash equivalents.
Our principal uses of liquidity and capital resources, outside of those required for our operations, include, but are not limited
to, collateral requirements to support our commercial hedging and optimization activities, debt service obligations including principal and interest payments, capital expenditures for construction, project development and other growth initiatives and opportunistically repaying debt to manage our balance sheet.
Cash Management — We manage our cash in accordance with our cash management system subject to the requirements of our Corporate Revolving Facility and requirements under certain of our project debt and lease agreements or by regulatory agencies. Our cash and cash equivalents, as well as our restricted cash balances, are invested in money market funds that are not FDIC insured. We place our cash, cash equivalents and restricted cash in what we believe to be creditworthy financial institutions.
We have never paid cash dividends on our common stock. Future
cash dividends, if any, may be authorized at the discretion of our Board of Directors and will depend upon, among other things, our future operations and earnings, capital requirements, general financial condition, contractual and financing restrictions and such other factors as our Board of Directors may deem relevant.
Liquidity Sensitivity
Significant changes in commodity prices and Market Heat Rates can affect our liquidity as we use margin deposits, cash prepayments and letters of credit as credit support (collateral) with and from our counterparties for commodity procurement and risk management activities. Utilizing our portfolio of transactions subject to collateral exposure, we estimate that as of December 31, 2017, an increase of $1/MMBtu in natural gas prices would result in a
decrease of collateral required by approximately $44 million. If natural gas prices decreased by $1/MMBtu, we estimate that our collateral requirements would increase by approximately $110
46
million. Changes in Market Heat Rates also affect our liquidity. For example, as demand increases, less efficient generation is dispatched, which increases the Market Heat Rate and results in increased collateral requirements. Historical relationships of natural gas and Market Heat Rate movements for our portfolio of assets have been volatile over time and are influenced by the absolute price of natural gas and the regional characteristics of each power market. We estimate that at December 31, 2017,
an increase of 500 Btu/KWh in the Market Heat Rate would result in an increase in collateral required by approximately $57 million. If Market Heat Rates were to fall at a similar rate, we estimate that our collateral required would decrease by $54 million. These amounts are not necessarily indicative of the actual amounts that could be required, which may be higher or lower than the amounts estimated above, and also exclude any correlation between the changes in natural gas prices and Market Heat Rates that may occur concurrently. These sensitivities will change as new contracts or hedging activities are executed.
In order to effectively manage our future Commodity Margin, 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 2018 and beyond. In addition to the price of natural gas, our Commodity Margin is highly dependent on other factors such as:
•
the level of Market Heat Rates;
•
our continued ability to successfully hedge our Commodity Margin;
•
changes
in U.S. macroeconomic conditions;
•
maintaining acceptable availability levels for our fleet;
•
the effect of current and pending environmental regulations in the markets in which we participate;
•
improving the efficiency and profitability of our operations;
•
increasing
future contractual cash flows; and
•
our significant counterparties performing under their contracts with us.
Additionally, scheduled outages related to the life cycle of our power plant fleet in addition to unscheduled outages may result in maintenance expenditures that are disproportionate in differing periods. In order to manage such liquidity requirements, we maintain additional liquidity availability in the form of our Corporate Revolving Facility (noted in the table above), letters of credit and the ability to issue first priority liens for collateral support. It is difficult to predict
future developments and the amount of credit support that we may need to provide should such conditions occur, we experience another economic recession or energy commodity prices increase significantly.
Letter of Credit Facilities
The table below represents amounts issued under our letter of credit facilities at December 31, 2017 and 2016 (in millions):
2017
2016
Corporate
Revolving Facility(1)
$
629
$
535
CDHI
244
250
Various
project financing facilities
196
206
Total
$
1,069
$
991
____________
(1)
The
Corporate Revolving Facility represents our primary revolving facility.
47
Major Maintenance and Capital Spending
Our major maintenance and capital spending remains an important part of our business. Our expected expenditures for 2018 are as follows (in millions):
2018
Major
maintenance expense
$
180
Maintenance capital expenditures
230
Growth related capital expenditures
185
Total major maintenance expense and capital spending
595
Less:
Amounts expected to be funded with financing
(50
)
Net major maintenance expense and capital spending
$
545
NOLs
We have significant NOLs that are expected to provide future tax deductions when we generate sufficient taxable income during the applicable carryover periods. At December 31, 2017,
our consolidated federal NOLs totaled approximately $6.6 billion. If a subsequent ownership change, such as the ownership change associated with the impending Merger, were to occur as a result of future transactions in our stock, our ability to utilize the NOL carryforwards will be limited. Although we have not completed our analysis, it is reasonably possible that our federal NOLs available to offset future taxable income could materially decrease. This reduction will be offset by an adjustment to the existing valuation allowance for an equal and offsetting amount. Given the offsetting adjustments to the existing valuation allowance, any ownership change is not expected to have an adverse material effect on our financial condition, results of operations or cash flows. See Note 11 of the Notes to Consolidated Financial Statements for further discussion of our NOLs.
Cash
Flow Activities
The following table summarizes our cash flow activities for the years ended December 31, 2017, 2016 and 2015 (in millions):
2017
2016
2015
Beginning
cash and cash equivalents
$
418
$
906
$
717
Net cash provided by (used in):
Operating
activities
931
1,030
876
Investing activities
(181
)
(1,919
)
(841
)
Financing
activities
(884
)
401
154
Net (decrease) increase in cash and cash equivalents
(134
)
(488
)
189
Ending
cash and cash equivalents
$
284
$
418
$
906
2017 — 2016
Net Cash Provided By Operating Activities
Cash
provided by operating activities for the year ended December 31, 2017, was $931 million compared to $1,030 million for the year ended December 31, 2016. The decrease was primarily due to:
•
Working capital employed — Working capital employed increased by $107 million for the year ended December 31, 2017, compared to the same period in 2016, after adjusting for changes in debt, restricted cash and mark-to-market related balances which did not affect cash provided by operating activities. The increase was primarily due to lower recovery of cash
margin posted by Calpine Solutions through position netting and LC conversion opportunities in 2017 compared to 2016.
•
Interest paid — Cash paid for interest decreased by $9 million to $575 million for the year ended December 31, 2017, from $584 million for the year ended December 31, 2016. The decrease was primarily due to our refinancing activities and timing of interest payments.
Net Cash Used In Investing Activities
Cash used in investing
activities was $181 million for the year ended December 31, 2017 compared to cash used in investing activities of $1,919 million for the year ended December 31, 2016. The decrease was primarily attributable to:
48
•
Acquisition of Retail Electric Providers — During the year ended December 31, 2017, we purchased the retail electric provider North American Power for a net purchase price paid of $111 million as compared to the
purchase of Calpine Solutions, formerly Noble Solutions, for $1.15 billion during the year ended December 31, 2016.
•
Acquisition and Divestiture of Power Plants — During the year ended December 31, 2017, we received net proceeds of $162 million for the sale of Osprey Energy Center. During the year ended December 31, 2016, we purchased Granite Ridge Energy Center for a net purchase price of $526 million partially offset by the sale of Mankato Power Plant for net proceeds after the pay-down of Steamboat project debt of approximately $164 million.
•
Capital
expenditures — Capital expenditures for the year ended December 31, 2017, were $305 million, a decrease of $184 million, compared to expenditures of $489 million for the year ended December 31, 2016. The decrease was primarily due to lower expenditures on construction projects.
Net Cash Provided By (Used In) Financing Activities
Cash used in financing activities for the year ended December 31, 2017, was $884 million compared to cash provided by financing activities of $401 million for the year ended December 31, 2016. The decrease was primarily due to:
•
Refinancing
and Debt Paydown Activity — During the year ended December 31, 2017, we utilized cash on hand to repay our outstanding $550 million 2017 First Lien Term Loan. Additionally, we received proceeds of $396 million from the issuance of the 2019 First Lien Term Loan using the proceeds, together with cash on hand, to redeem $453 million of the 2023 First Lien Notes. During the year ended December 31, 2016, we received proceeds of $545 million from the issuance of the 2017 First Lien Term Loan used to partially fund the purchase of Calpine Solutions and redeemed $120 million of the 2023 First Lien Notes.
•
Project financing,
notes payable and other — During the year ended December 31, 2016, we refinanced and upsized Steamboat project debt following the sale of Mankato Power Plant. The refinancing resulted in net proceeds received of $20 million after the noncash pay-down of the debt in the amount of $243 million in conjunction with the sale of Mankato and proceeds received from the upsizing and refinancing in the amount of $263 million. There were no similar activities during the year ended December 31, 2017.
2016 — 2015
Net Cash Provided By Operating Activities
Cash provided by operating activities for the year ended December
31, 2016, was $1,030 million compared to $876 million for the year ended December 31, 2015. The increase was primarily due to:
•
Income from operations — Income from operations, adjusted for non-cash items, decreased by $136 million for the year ended December 31, 2016, compared to the same period in 2015. Non-cash items consist primarily of depreciation and amortization, income from unconsolidated subsidiaries, gain on sale of assets and mark-to-market activity. The decrease in income from operations was primarily driven by a $186 million decrease
in Commodity revenue, net of Commodity expense, excluding non-cash amortization, partially offset by a $41 million decrease in operating and maintenance expense. See “Results of Operations for the Year Ended December 31, 2016 and 2015” above for further discussion of these changes.
•
Working capital employed — Working capital employed decreased by $202 million for the year ended December 31, 2016, compared to the same period in 2015, after adjusting for changes in debt, restricted cash and mark-to-market related balances
which did not affect cash provided by operating activities. The decrease was primarily due to the recovery of cash margin posted by Calpine Solutions through position netting and letter of credit conversion opportunities.
•
Interest paid — Cash paid for interest decreased by $36 million to $584 million for the year ended December 31, 2016, from $620 million for the year ended December 31, 2015. The decrease was primarily due to our refinancing activities and timing of interest payments.
•
Debt
modification & extinguishment payments — During the year ended December 31, 2016, we made cash payments of $5 million related to the repurchase penalties for a portion of the 2023 First Lien Notes and the refinancing and upsizing of Steamboat project debt as compared to $34 million during the year ended December 31, 2015, associated with the repurchase penalties for a portion of the 2023 First Lien Notes and debt modification costs related to the issuance of the 2024 First Lien Term Loan.
49
Net Cash Used In Investing Activities
Cash
used in investing activities for the year ended December 31, 2016, was $1,919 million compared to $841 million for the year ended December 31, 2015. The increase was primarily due to:
•
Purchase of Calpine Solutions and Champion Energy — During the year ended December 31, 2016, we purchased the retail electric provider Calpine Solutions, formerly Noble Solutions, for $1.15 billion compared to the purchase of Champion Energy for $296 million during the year ended December 31, 2015.
•
Purchase
of Granite Ridge Energy Center — During the year ended December 31, 2016, we purchased a natural gas-fired combined-cycle power plant located in Londonderry, New Hampshire for $526 million. There were no similar acquisitions during the year ended December 31, 2015.
•
Proceeds from the sale of Mankato Power Plant — During the year ended December 31, 2016, we received net proceeds after the pay-down of Steamboat project debt of approximately $164 million for the sale of Mankato Power Plant. There were no power plants sold during the year ended December
31, 2015.
•
Capital expenditures — Capital expenditures for the year ended December 31, 2016, were $489 million, a decrease of $76 million, compared to expenditures of $565 million for the year ended December 31, 2015. The decrease was primarily due to lower expenditures on construction projects and outages.
Net Cash Provided By Financing Activities
Cash provided by financing activities for the year ended December 31, 2016, was $401 million compared to $154 million
for the year ended December 31, 2015. The increase was primarily due to:
•
First Lien Term Loans, First Lien Notes and Senior Unsecured Notes — During the year ended December 31, 2016, we received proceeds of $545 million from the issuance of the 2017 First Lien Term Loan used to partially fund the purchase of Calpine Solutions and redeemed $120 million of the 2023 First Lien Notes. In addition, we utilized proceeds from the issuance of a portion of our 2023 First Lien Term Loans and 2026 First Lien Notes to repay a portion of our First Lien Term Loans maturing in 2019 and 2020 totaling $1.2 billion. During the year ended December
31, 2015, we received proceeds of $650 million from the issuance of the 2024 Senior Unsecured Notes, proceeds of $545 million from the issuance of 2023 First Lien Term Loan used to fund the purchase of Granite Ridge Energy Center and repurchased $267 million of the 2023 First Lien Notes. In addition, we utilized proceeds from the issuance of the 2024 First Lien Term Loan to repay the 2018 First Lien Term Loan of $1.6 billion.
•
Stock repurchases — During the year ended December 31, 2016, we repurchased an immaterial amount of common stock as compared to $529 million paid to repurchase our common stock during the year ended December
31, 2015.
•
Project financing, notes payable and other — During the year ended December 31, 2016, we refinanced and upsized Steamboat project debt following the sale of Mankato Power Plant. The refinancing resulted in net proceeds received of $20 million after the noncash pay-down of the debt in the amount of $243 million in conjunction with the sale of Mankato and proceeds received from the upsizing and refinancing in the amount of $263 million. There were no similar activities during the year ended December 31, 2015.
Credit
Considerations
Our credit rating has, among other things, generally required us to post significant collateral with our hedging counterparties. Our collateral is generally in the form of cash deposits, letters of credit or first liens on our assets. See also Note 10 of the Notes to Consolidated Financial Statements for our use of collateral. Our credit rating reduces the number of hedging counterparties willing to extend credit to us and reduces our ability to negotiate more favorable terms with them. However, we believe that we will continue to be able to work with our hedging counterparties to execute beneficial hedging transactions and provide adequate collateral. At December 31, 2017, our First Lien Notes, First Lien Term Loans, Corporate Revolving Facility, Senior Unsecured Notes and our corporate rating had the following ratings
and commentary from Standard and Poor’s and Moody’s Investors Service:
50
Standard and Poor’s
Moody’s Investors
Service
First Lien Notes, First Lien Term Loans and Corporate Revolving Facility rating
BB
Ba2
Senior
Unsecured Notes
B
B2
Corporate rating
B+
Ba3
Commentary
Stable
Negative
Off Balance Sheet Arrangements
Our power plant operating lease is not reflected
on our Consolidated Balance Sheets and contains customary restrictions on dividends up to Calpine Corporation, additional debt and further encumbrances similar to those typically found in project finance debt instruments. See Note 16 of the Notes to Consolidated Financial Statements for the future minimum lease payments under our power plant operating lease.
Some of our unconsolidated equity method investments have debt that is not reflected on our Consolidated Balance Sheets. As of December 31, 2017, our investments in Greenfield LP and Whitby had aggregate debt outstanding of $256 million. Based on our pro rata share of each of the investments, our share of such debt would be approximately $128 million. All such debt is non-recourse to
us.
Guarantee Commitments — As part of our normal business operations, we enter into various agreements providing, or otherwise arranging, financial or performance assurance to third parties on behalf of our subsidiaries in the ordinary course of such subsidiaries’ respective business. Such arrangements include guarantees, standby letters of credit and surety bonds for power and natural gas purchase and sale arrangements, retail contracts, contracts associated with the
development, construction, operation and maintenance of our fleet of power plants and our Accounts Receivable Sales Program. See Note 16 of the Notes to Consolidated Financial Statements for further information on our guarantee commitments.
Contractual Obligations — Our contractual obligations as of December 31, 2017, are as follows (in millions):
Total
Less than 1
Year
1-3 Years
3-5 Years
More than 5
Years
Operating
lease obligations(1)
$
327
$
48
$
82
$
29
$
168
Purchase
obligations:
Commodity purchase obligations(2)
$
1,501
$
458
$
374
$
145
$
524
LTSA(3)
297
32
67
63
135
Water
agreements(4)
393
25
52
50
266
Other
purchase obligations(5)
336
122
82
64
68
Total
purchase obligations
$
2,527
$
637
$
575
$
322
$
993
Debt
$
11,569
$
226
$
1,110
$
1,194
$
9,039
Other
contractual obligations:
Interest payments on debt(6)
$
3,536
$
572
$
1,125
$
1,045
$
794
Liability
for uncertain tax positions
16
7
4
2
3
Interest
rate hedging instruments(6)
37
18
13
6
—
Total
other contractual obligations
$
3,589
$
597
$
1,142
$
1,053
$
797
Total
contractual obligations
$
18,012
$
1,508
$
2,909
$
2,598
$
10,997
___________
(1)
Included
in the total are future minimum payments for power plant, office, land and other operating leases. See Note 16 of the Notes to Consolidated Financial Statements for more information.
(2)
The amounts presented here include contracts for the purchase, transportation or storage of commodities accounted for as executory contracts and therefore not recognized on our Consolidated Balance Sheet.
(3)
The
amounts presented here are based on the stated payment terms in the contracts at the time of execution, subject to an annual inflationary adjustment.
(4)
The amounts presented here are based on contractually obligated amounts over the life of the contracts.
51
(5)
The
amounts presented here include costs to complete construction projects, turbine commitments, parts supply agreements, maintenance agreements, information technology agreements and other purchase obligations.
(6)
Amounts are projected based upon interest rates at December 31, 2017.
Pursuant to applicable transaction agreements, we have established certain
of our entities separate from Calpine Corporation and our other subsidiaries. In accordance with applicable accounting standards, we consolidate these entities with the exception of Calpine Receivables (see Note 3 and 6 of the Notes to Consolidated Financial Statements for further information related to Calpine Receivables). As of the date of filing of this Report, these entities included: Russell City Energy Company, LLC, Otay Mesa Energy Center, LLC and Calpine Receivables.
52
RISK MANAGEMENT AND COMMODITY
ACCOUNTING
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. A description of risk management activities is included under Item 1. “Business — Marketing, Hedging and Optimization Activities.” See Note 9 of the Notes to Consolidated Financial Statements for further discussion of our derivative instruments.
During the third quarter of 2017, we elected to begin offsetting fair value amounts associated with our derivative instruments and related cash collateral and margin deposits on our Consolidated Balance Sheets that are executed with the same counterparty under master netting arrangements. Our netting arrangements include a right to set off or net together purchases and sales of similar products in the margining or settlement process. In
some instances, we have also negotiated cross commodity netting rights which allow for the net presentation of activity with a given counterparty regardless of product purchased or sold. We also post cash collateral in support of our derivative instruments which may also be subject to a master netting arrangement with the same counterparty. See Note 3 of the Notes to Consolidated Financial Statements for a further description of the change in accounting principle associated with our election to offset fair value amounts associated with our derivative instruments.
The primary factors affecting our market risk and the fair value of our derivatives at any point in time are the volume of open derivative positions (MMBtu, MWh and $ notional amounts); changing commodity market prices, primarily for power and natural gas; our credit standing and that of our counterparties for energy commodity derivatives; and prevailing interest rates
for our interest rate hedging instruments. Since prices for power and natural gas and interest rates are volatile, there may be material changes in the fair value of our derivatives over time, driven both by price volatility and the changes in volume of open derivative transactions. Our derivative assets have decreased to approximately $392 million at December 31, 2017, when compared to approximately $521 million at December 31, 2016, and our derivative liabilities have increased to approximately $316 million at December 31, 2017, when compared to approximately $287 million at December 31, 2016.
The fair value of our level 3 derivative assets and liabilities at December 31, 2017 represents approximately 46% and 14% of our total assets and liabilities measured at fair value, respectively, with the majority of that value attributable to the fair value of our retail sales contracts accounted for as derivatives. See Note 8 of the Notes to Consolidated Financial Statements for further information related to our level 3 derivative assets and liabilities.
The change in fair value of our outstanding commodity and interest rate hedging instruments from January 1, 2017, through December 31, 2017, is
summarized in the table below (in millions):
Commodity
contract settlements consist of the realization of previously recognized gains on contracts not designated as hedging instruments of $100 million (represents a portion of Commodity revenue and Commodity expense as reported on our Consolidated Statements of Operations) and $25 million related to current period losses from other changes in derivative assets and liabilities not reflected in OCI or earnings.
(2)
Interest rate settlements consist of $25 million related to realized losses from settlements of designated cash flow hedges and $2 million related to realized
losses from settlements of undesignated interest rate hedging instruments (represents a portion of interest expense as reported on our Consolidated Statements of Operations).
(3)
Fair value attributable to new contracts includes $24 million and $18 million of fair value related to commodity contracts and interest rate hedging instruments, respectively, which are not reflected in OCI or earnings.
(4)
Net
commodity and interest rate derivative assets and liabilities reported in Notes 8 and 9 of the Notes to Consolidated Financial Statements.
Commodity Price Risk — Commodity price risks result from exposure to changes in spot prices, forward prices, price volatilities and correlations between the price of power, steam and natural gas. We manage the commodity price risk and the variability in future cash flows from forecasted sales of power and purchases of natural gas of our entire portfolio of generating assets and contractual positions by entering into various derivative and non-derivative instruments.
53
The net fair value of outstanding derivative commodity instruments,
net of allocated collateral, at December 31, 2017, based on price source and the period during which the instruments will mature, are summarized in the table below (in millions):
Fair Value Source
2018
2019-2020
2021-2022
After 2022
Total
Prices
actively quoted
$
—
$
—
$
—
$
—
$
—
Prices
provided by other external sources
(89
)
(29
)
3
—
(115
)
Prices
based on models and other valuation methods
76
89
23
8
196
Total
fair value
$
(13
)
$
60
$
26
$
8
$
81
We
measure the energy commodity price risk in our portfolio on a daily basis using a VAR model to estimate the potential one-day risk of loss based upon historical experience resulting from potential market movements. Our VAR is calculated for our entire portfolio comprising energy commodity derivatives, expected generation and natural gas consumption from our power plants, PPAs, and other physical and financial transactions. We measure VAR using a variance/covariance approach based on a confidence level of 95%, a one-day holding period and actual observed historical correlation. While we believe that our VAR assumptions and approximations are reasonable, different assumptions and/or approximations could produce materially different estimates.
The table below presents the high, low and average of our daily VAR for the years ended December 31, 2017
and 2016 (in millions):
2017
2016
Year ended December 31:
High
$
39
$
39
Low
$
16
$
14
Average
$
22
$
23
As
of December 31
$
24
$
20
Due to the inherent limitations of statistical measures such as VAR, the VAR calculation may not capture the full extent of our commodity price exposure. As a result, actual changes in the value of our energy commodity portfolio could be different from the calculated VAR, and could have a material effect on our financial results. In order to evaluate the risks of our portfolio on a comprehensive basis and augment our VAR
analysis, we also measure the risk of the energy commodity portfolio using several analytical methods including sensitivity analysis, non-statistical scenario analysis, including stress testing, and daily position report analysis.
We utilize the forward commodity markets to hedge price risk associated with our power plant portfolio. Our ability to hedge relies in part on market liquidity and the number of counterparties with which to transact. While the number of counterparties in these markets has decreased, to date this occurrence has not had a material adverse effect on our results of operations or financial condition. However, should these conditions persist or increase, it could decrease our ability to hedge our forward commodity price risk and create incremental volatility in our earnings. The effects of declining liquidity in the forward commodity markets is also mitigated by our retail subsidiaries
which provides us with an additional outlet to transact hedging activities related to our wholesale power plant portfolio.
Liquidity Risk — Liquidity risk arises from the general funding requirements needed to manage our activities and assets and liabilities. Fluctuating natural gas prices or Market Heat Rates can cause our collateral requirements for our wholesale and retail activities to increase or decrease. Our liquidity management framework is intended to maximize liquidity access and minimize funding costs during times of rising prices. See further discussion regarding our uses of collateral as they relate to our commodity procurement and risk management activities in Note 10 of the Notes to Consolidated Financial Statements.
Credit Risk — Credit risk relates to the risk of loss resulting from nonperformance or non-payment by our
counterparties or customers related to their contractual obligations with us. Risks surrounding counterparty and customer performance and credit could ultimately affect the amount and timing of expected cash flows. We also have credit risk if counterparties or customers are unable to provide collateral or post margin. We monitor and manage our credit risk through credit policies that include:
•
credit approvals;
•
routine monitoring of counterparties’ and customer’s credit limits and their overall credit ratings;
•
limiting
our marketing, hedging and optimization activities with high risk counterparties;
•
margin, collateral, or prepayment arrangements; and
54
•
payment netting arrangements, or master netting arrangements that allow for the netting of positive and negative exposures of various contracts
associated with a single counterparty.
We have concentrations of credit risk with a few of our wholesale counterparties and retail customers relating to our sales of power and steam and our hedging, optimization and trading activities. We believe that our credit policies and portfolio of transactions adequately monitor and diversify our credit risk, and currently our counterparties and customers are performing and financially settling timely according to their respective agreements. We monitor and manage our total comprehensive credit risk associated with all of our contracts irrespective of whether they are accounted for as an executory contract, a normal purchase normal sale or whether they are marked-to-market and included in
our derivative assets and liabilities on our Consolidated Balance Sheets. Our counterparty and customer credit quality associated with the net fair value of outstanding derivative commodity instruments is included in our derivative assets and (liabilities), net of allocated collateral, at December 31, 2017, and the period during which the instruments will mature are summarized in the table below (in millions):
Primarily
comprised of the fair value of derivative instruments held with customers that are not rated by third party credit agencies due to the nature and size of the customers.
Interest Rate Risk — We are exposed to interest rate risk related to our variable rate debt. Interest rate risk represents the potential loss in earnings arising from adverse changes in market interest rates. Our variable rate financings are indexed to base rates, generally LIBOR. The following table summarizes the contract terms as well as the fair values of our debt instruments exposed to interest rate risk as of December 31, 2017. All outstanding balances and fair market values are shown gross of applicable premium or discount, if
any (in millions):
Projection
based upon forward LIBOR rates inferred from spot rates at December 31, 2017.
Interest rate risk represents the potential loss in earnings arising from adverse changes in market interest rates. Our interest rate hedging instruments are with counterparties we believe are primarily high quality institutions, and we do not believe that our interest rate hedging instruments expose us to any significant credit risk. Holding all other factors constant, we estimate that a 10% decrease in interest rates would result in a change in the fair value of our interest rate hedging instruments hedging our variable rate debt of approximately $(24) million at December 31, 2017.
APPLICATION
OF CRITICAL ACCOUNTING POLICIES
The preparation of financial statements in accordance with U.S. GAAP requires management to make certain estimates and assumptions which are inherently imprecise and may differ significantly from actual results achieved. We believe the following are our more critical accounting policies due to the significance, subjectivity and judgment involved in determining our estimates used in preparing our Consolidated Financial Statements. See Note 3 of the Notes to Consolidated Financial Statements for a discussion of the application of these and other accounting policies. We evaluate our estimates and assumptions used in preparing our Consolidated Financial Statements on an ongoing basis utilizing historic experience, anticipated future events or trends, consultation with third party advisors or other methods that involve judgment as determined appropriate under the circumstances.
55
The resulting effects of changes in our estimates are recorded in our Consolidated Financial Statements in the period in which the facts and circumstances that give rise to the change in estimate become known.
Revenue Recognition
We routinely enter into physical commodity contracts for sales of our generated power to manage risk and capture the value inherent in our generation. Determining the proper accounting for our power contracts can require significant judgment and affect how we recognize revenue. In addition, we determine whether the contract
should be accounted for on a gross or net basis. Determining the proper accounting treatment involves the evaluation of quantitative, as well as qualitative factors, to determine if the contract should be accounted for as one of the following:
Lease Accounting — Revenue from contracts accounted for as operating leases, such as certain tolling agreements, with minimum lease
rentals (capacity payments) which vary over time must be levelized. Generally, we levelize these contract revenues on a straight-line basis over the term of the contract.
Executory and Physical Contracts Exempt from Derivative Accounting — We generally recognize revenue from the sale of power or thermal energy for sale to our customers for use in industrial or other heating operations, upon transmission and delivery to the customer at the contractual price. In addition to revenues from power, host steam revenues and RECs from our Geysers Assets related to generation, our operating revenues also include:
•
power
and steam revenue consisting of fixed and variable capacity payments, including capacity payments received from PJM and ISO-NE capacity auctions which are not related to generation;
•
other revenues such as RMR Contracts, resource adequacy and certain ancillary service revenues; and
•
other service revenues.
Capacity payments, RMR Contracts,
RECs, resource adequacy and other ancillary revenues, unless qualified as a lease, are recognized when contractually earned and consist of revenues received from our customers either at the market price or a contract price.
Revenues from sales of power to retail customers are recognized upon delivery under the accrual method, unless we apply derivative accounting treatment to the retail contract. Unbilled retail revenues are based upon estimates of customer usage since the date of the last meter reading provided by the ISOs or electric distribution companies by applying the estimated revenue per KWh by customer class to the estimated number of KWhs delivered but not yet billed. Estimated amounts are adjusted when actual usage is known and billed.
See “ — Accounting for Derivative Instruments” directly below for a discussion of the significant judgments and estimates related to accounting for derivative instruments. We apply lease accounting to contracts that meet the definition of a lease and accrual accounting treatment to those contracts that are either exempt from derivative accounting or do not meet the definition of a derivative instrument.
Gross vs. Net Accounting — We determine whether the financial statement presentation of revenues should be on a gross or net basis. Where we act as principal, we record settlement of our physical commodity contracts
on a gross or net basis dependent upon whether the contract results in physical delivery of the underlying product. With respect to our physical executory contracts, where we do not take title to the commodities but receive a variable payment to convert natural gas into power and steam in a tolling operation, we record revenues on a net basis.
Fair Value Measurements
We use fair value to measure certain of our assets, liabilities and expenses in our financial statements. Fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the
measurement date (i.e., the exit price). Generally, the determination of fair value requires the use of significant judgment and different approaches and models under varying circumstances. Under a market based approach, we consider prices of similar assets, consult with brokers and experts or employ other valuation techniques. Under an income based approach, we generally estimate future cash flows and then discount them at a risk adjusted rate.
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Accordingly, the determination of fair value represents a critical accounting policy. Our most significant fair value measurements represent the valuation of our derivative assets and liabilities, which are measured on a recurring basis (each reporting period) and measurements of impairments and acquired assets and
liabilities on a nonrecurring basis. We primarily apply the market approach and income approach for recurring fair value measurements (primarily our derivative assets and liabilities) using the best available information. We primarily utilize the income approach for nonrecurring fair value measurements such as impairments of our assets as market prices for similar assets may not be readily available and may not incorporate the expected future returns from our assets. We utilize valuation techniques that seek to maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the observability of those inputs. U.S. GAAP establishes a fair value hierarchy which classifies fair value measurements from level 1 through level 3 based upon the inputs used to measure fair value:
Level 1 — Quoted prices (unadjusted) are available in active markets for
identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 — Pricing inputs include quoted prices for similar assets and liabilities in active markets, and inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
Level 3 — Pricing inputs include significant inputs that are generally less observable or from unobservable sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.
Derivative Instruments and Valuation Techniques
The
primary factors affecting the fair value of our derivative instruments at any point in time are the volume of open derivative positions (MMBtu, MWh and $ notional amounts); changing commodity market prices, primarily for power and natural gas; our credit standing and that of our counterparties and customers for energy commodity derivatives; and prevailing interest rates for our interest rate hedging instruments. Prices for power and natural gas and interest rates are volatile, which can result in material changes in the fair value measurements reported in our financial statements in the future. Derivative contracts can be exchange-traded or OTC. For OTC derivatives that trade in liquid markets, model inputs can generally be verified and model selection does not involve significant management judgment. Certain OTC derivatives trade in less liquid markets with limited pricing information,
and the determination of fair value for these derivatives is inherently more difficult.
For our level 2 and level 3 derivative instruments, we may utilize models to measure fair value. Where models are used, the selection of a particular model to value an asset or liability depends upon the contractual terms and specific risks, as well as the availability of pricing information in the market. We generally use similar models to value similar instruments. Valuation models require a variety of inputs, including contractual terms, market prices, yield curves, credit curves and measures of volatility. These models are primarily industry-standard models, including the Black-Scholes option-pricing model. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the
marketplace. In cases where there is no corroborating market information available to support significant model inputs, we initially use the transaction price as the best estimate of fair value.
Our derivative instruments that are traded on the NYMEX or Intercontinental Exchange primarily consist of natural gas swaps, futures and options and are classified as level 1 fair value measurements.
Our derivative instruments that primarily consist of interest rate hedging instruments and OTC power and natural gas forwards for which market-based pricing inputs in the principal or most advantageous market are representative of executable prices for market participants are classified as level 2 fair value measurements. These inputs are observable at commonly quoted intervals for substantially the full term of the instruments.
Our OTC power and natural
gas forwards and options where pricing inputs are unobservable, as well as other complex and structured transactions primarily for the sale of power to both wholesale counterparties and retail customers are classified as level 3 fair value measurements. Complex or structured transactions are tailored to our customers’ needs and can introduce the need for internally-developed model inputs which might not be observable in or corroborated by the market. When such inputs have a significant effect on the measurement of fair value, the instrument is categorized in level 3. At each balance sheet date, we perform an analysis of all instruments subject to fair value measurement and include in level 3 all of those whose fair value is based on significant unobservable inputs.
The determination of fair value of our derivatives also includes consideration of our credit standing, the credit standing of our counterparties and customers and
the effect of credit enhancements, if any. We assess non-performance risk by adjusting
57
the fair value of our derivatives based on our credit standing or the credit standing of our counterparties and customers involved and the effect of credit enhancements, if any. Such valuation adjustments represent the amount of probable loss due to default either by us or a third party. Our credit valuation methodology is based on a quantitative approach which allocates a credit adjustment to the fair value of derivative transactions based on the net exposure of each counterparty or customer. We develop our credit reserve based on our expectation of potential credit exposure. Our calculation of the credit reserve on net asset positions is based on available market information
including credit default swap rates, credit ratings and historical default information. We also incorporate non-performance risk in net liability positions based on an assessment of our potential risk of default.
Impairments
When we determine that an impairment exists, we determine fair value using valuation techniques such as the present value of expected future cash flows. In order to estimate future cash flows, we consider historical cash flows, existing and future contracts and PPAs and changes in the market environment and other factors that may affect future cash flows. To the extent applicable, the assumptions we use are consistent with forecasts that we are otherwise required to make (for example, in preparing our other earnings forecasts). The use of this method involves inherent uncertainty.
We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the effect of such variations could be material.
We also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment including contract terms, tenor and credit risk of counterparts. We may also consider prices of similar assets, consult with brokers, or employ other valuation techniques. We use our best estimates in making these evaluations; however, actual future market prices and project costs could vary from the assumptions used in our estimates, and the effect
of such variations could be material.
Acquisitions of Assets and Liabilities
U.S. GAAP requires that the purchase price for an acquisition, such as the acquisition of Calpine Solutions, be assigned and allocated to the individual assets and liabilities based upon their fair value. Generally, the amount recorded in the financial statements for an acquisition is the purchase price (value of the consideration paid), but a purchase price that exceeds the fair value of the assets acquired can result in the recognition of goodwill. In addition to the potential for the recognition of goodwill, differing fair values will affect the allocations of the purchase price to the individual assets and liabilities and can affect the gross amount and classification of assets and liabilities recorded on our Consolidated Balance Sheet and can affect the timing and the amount of depreciation and amortization
expense recorded in any given period. We utilize our best effort to make our determinations and review all information available including estimated future cash flows and prices of similar assets when making our best estimate. We also may hire independent appraisers to help us make this determination as we deem appropriate under the circumstances.
Accounting for Derivative Instruments
We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Statements of Operations until the period of delivery.
Hedge Accounting — Revenues
and expenses derived from derivative instruments that qualify for hedge accounting are recorded in the period and same financial statement line item as the hedged item. Hedge accounting requires us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting. We present the cash flows from hedging derivatives in the same category as the item being hedged within operating activities on our Consolidated Statements of Cash Flows unless they contain an other-than-insignificant financing element in which case their cash flows are classified within financing activities.
Cash Flow Hedges — We currently apply hedge accounting to certain of our interest rate hedging instruments. We report the effective portion of the mark-to-market gain or loss on our interest rate hedging instruments designated and qualifying as a cash flow hedging instrument as a component of OCI
and reclassify such gains and losses into earnings in the same period during which the hedged forecasted transaction affects earnings. Gains and losses due to ineffectiveness on interest rate hedging instruments are recognized currently in earnings as a component of interest expense. If it is determined that the forecasted transaction is no longer probable of occurring, then hedge accounting will be discontinued prospectively and future changes in fair value are recorded in earnings. If the hedging instrument is terminated or de-designated prior to the occurrence of the hedged forecasted transaction, the net accumulated gain or loss associated with the changes in fair value of the hedge instrument remains deferred in AOCI until such time as the forecasted transaction affects earnings or until it is determined that the forecasted transaction is probable of not occurring.
58
Derivatives
Not Designated as Hedging Instruments — We enter into power, natural gas, interest rate, environmental product and fuel oil transactions that primarily act as economic hedges to our asset and interest rate portfolio, but either do not qualify as hedges under the hedge accounting guidelines or qualify under the hedge accounting guidelines and the hedge accounting designation has not been elected. Changes in fair value of commodity derivatives not designated as hedging instruments are recognized currently in earnings and are separately stated on our Consolidated Statements of Operations in mark-to-market gain/loss as a component of operating revenues (for physical and financial power and Heat Rate and commodity option activity) and fuel and purchased energy expense (for physical and financial natural gas, power, environmental product and fuel oil activity). Changes in fair value of interest rate derivatives not designated as hedging instruments are
recognized currently in earnings as interest expense.
See Notes 8 and 9 of the Notes to Consolidated Financial Statements for further discussion of our derivative instruments.
Accounting for VIEs and Financial Statement Consolidation Criteria
We consolidate all VIEs where we determined that we have both the power to direct the activities of a VIE that most significantly affect the VIE’s economic performance and the obligation to absorb losses or receive benefits from the VIE. We have determined that we hold the obligation to absorb losses and receive benefits in all of our VIEs where we hold the majority equity interest. Therefore, our determination of whether to consolidate is based upon which variable interest holder has the power to direct the most significant
activities of the VIE (the primary beneficiary). Our analysis includes consideration of the following primary activities which we believe to have a significant effect on a power plant’s financial performance: operations and maintenance, plant dispatch, and fuel strategy as well as our ability to control or influence contracting and overall plant strategy. Our approach to determining which entity holds the powers and rights is based on powers held as of the balance sheet date. Contractual terms that may change the powers held in future periods, such as a purchase or sale option, are not considered in our analysis. Based on our analysis, we believe that we hold the power and rights to direct the most significant activities for most of our majority owned VIEs.
Under our consolidation policy and under U.S. GAAP we also:
•
perform
an ongoing reassessment each reporting period of whether we are the primary beneficiary of our VIEs; and
•
evaluate if an entity is a VIE and whether we are the primary beneficiary whenever any changes in facts and circumstances occur such that the holders of the equity investment at risk, as a group, lose the power from voting rights or similar rights of those investments to direct the activities of a VIE that most significantly affect the VIE’s economic performance or when there are other changes in the powers held by individual variable interest holders.
Because we are required to perform ongoing reassessments of whether we are the primary beneficiary, future changes in our assessments
of whether we are the primary beneficiary could require us to consolidate our VIEs that are currently not consolidated or deconsolidate our VIEs that are currently consolidated based upon our reassessments in future periods. Making these determinations can require the use of significant judgment to determine which variable interest holder has the power to direct the most significant activities of the VIE (the primary beneficiary) and can directly affect amounts reported on our Consolidated Financial Statements.
Disclosure Requirements
U.S. GAAP requires separate disclosure on the face of our Consolidated Balance Sheets of the significant assets of a consolidated VIE that can be used only to settle obligations of the consolidated VIE and the significant liabilities of a consolidated VIE for which creditors (or beneficial interest holders) do not have recourse to the general credit
of the primary beneficiary. In determining which assets of our VIEs meet the separate disclosure criteria, we consider that this separate disclosure requirement is met where Calpine Corporation is substantially limited or prohibited from access to assets (primarily cash and cash equivalents, restricted cash and property, plant and equipment), and where our VIEs had project financing that prohibits the VIE from providing guarantees on the debt of others. In determining which liabilities of our VIEs meet the separate disclosure criteria, we consider that this separate disclosure requirement is met where there are agreements that prohibit the debt holders of the VIEs from recourse to the general credit of Calpine Corporation and where the amounts were material to our financial statements.
Unconsolidated VIEs
We have a 50% partnership interest
in Greenfield LP and in Whitby. Greenfield LP and Whitby are also VIEs; however, we do not have the power to direct the most significant activities of these entities and therefore do not consolidate them. We account for these entities under the equity method of accounting and include our net equity interest in investments in unconsolidated subsidiaries on our Consolidated Balance Sheets. Our equity interest in the net income from Greenfield LP and Whitby for the years ended December 31, 2017, 2016 and 2015, are recorded in (income) from unconsolidated subsidiaries.
59
We have a 100% membership interest in Calpine Receivables, a bankruptcy remote entity created for the special purpose of purchasing trade accounts receivable from Calpine Solutions under the Accounts Receivable Sales Program. Calpine Receivables is a VIE as we have determined that we do not have the power to direct the activities of the VIE that most significantly affect the VIE’s economic performance nor the obligation to absorb losses or receive benefits from the VIE. Accordingly, we have determined that we are not the primary beneficiary of Calpine Receivables as we do not have the power to affect its financial performance as the unaffiliated financial institutions that purchase the receivables from Calpine Receivables control the selection criteria of the receivables sold and appoint the servicer of the receivables which controls
management of default. Thus, we do not consolidate Calpine Receivables in our Consolidated Financial Statements and we use the equity method of accounting to record our net interest in Calpine Receivables.
We hold a call option to purchase the Inland Empire Energy Center (a 775 MW natural gas-fired power plant located in California) from GE that may be exercised between years 2017 and 2024. GE holds a put option whereby they can require us to purchase the power plant, if certain plant performance criteria are met by 2025. We determined that we are not the primary beneficiary of the Inland Empire power plant, and we do not consolidate it due to the fact that GE directs the most significant activities of the power plant including operations
and maintenance.
Long-Lived Assets and Depreciation and Amortization Expense
Determination of the appropriate depreciation/amortization method, proper useful lives and salvage values involves significant judgment, estimates, assumptions and historical experience. Changes in our estimates and methods can result in a significant change in the amounts and timing of when we recognize depreciation and amortization expense and therefore significantly affect our financial condition and results of operations from period to period. Different depreciation and amortization methods can affect the timing and amount of depreciation and amortization expense affecting our results of operations and could result in different net book values of assets at a particular time during the useful life of the asset affecting our financial
position. Estimates of useful lives also significantly affect the timing and amounts of depreciation and amortization expense and include significant estimates. If useful lives are too short, then the asset is depreciated/amortized too quickly and depreciation and amortization expense is overstated. Estimated useful lives can significantly decrease if routine maintenance or certain upgrades are not performed, premature mechanical failure of the asset occurs, significant increases in the planned level of usage occur, advances in technology make the asset obsolete, or if there are adverse changes in environmental regulations. Our depreciable cost basis of our assets is reduced by the assets’ estimated salvage values. Dependent upon our ability to accurately estimate salvage values and the timing of disposal, the salvage values actually realized for our assets could significantly increase or decrease resulting in additional gains or losses in the year of disposal.
We
depreciate/amortize our assets under the straight-line method over the shorter of their estimated useful lives or lease term. For our natural gas-fired power plants, we assume an estimated salvage value which approximates 10% of the depreciable cost basis where we own the power plant or have a favorable option to purchase the power plant or take ownership of the power plant at conclusion of the lease term and a de minimis amount of the depreciable costs basis for componentized equipment. For our Geysers Assets, we typically assume no salvage values. We use the component depreciation method for our natural gas-fired power plant rotable parts, certain componentized balance of plant parts and our information technology equipment and the composite depreciation method for the other natural gas-fired power plant asset groups and Geysers Assets. We amortize intangible assets related to acquired retail and wholesale commodity contracts
that were initially recorded under purchase accounting in business combination transactions based on the relative acquisition fair value of the commodity contract over the life of the contract.
Impairment Evaluation of Long-Lived Assets (Including Goodwill, Intangibles and Investments)
We evaluate our long-lived assets, such as property, plant and equipment, equity method investments, turbine equipment and specifically identified intangibles, on an annual basis or when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Examples of such events or changes in circumstances are:
•
a
significant decrease in the market price of a long-lived asset;
•
a significant adverse change in the manner an asset is being used or its physical condition;
•
an adverse action by a regulator or legislature or an adverse change in the business climate;
•
an accumulation of costs significantly
in excess of the amount originally expected for the construction or acquisition of an asset;
•
a current-period loss combined with a history of losses or the projection of future losses; or
•
a change in our intent about an asset from an intent to hold to a greater than 50% likelihood that an asset will be sold or disposed of before the end of its previously estimated useful life.
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When
we believe an impairment condition on long-lived assets such as property, plant and equipment may have occurred, we are required to estimate the undiscounted future cash flows associated with a long-lived asset or group of long-lived assets at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities for long-lived assets that are expected to be held and used. We use a fundamental long-term view of the power market which is based on long-term production volumes, price curves and operating costs together with the regulatory and environmental requirements within each individual market to prepare our multi-year forecast. Since we manage and market our power sales as a portfolio rather than at the individual power plant level or customer level within each designated market, pool or segment, we group our power plants based upon the corresponding market for valuation purposes. If we determine that the undiscounted
cash flows from an asset or group of assets to be held and used are less than the associated carrying amount, or if we have classified an asset as held for sale, we must estimate fair value to determine the amount of any impairment loss.
We have temporarily suspended operations at several of our power plants. While the long-term market forecasted cash flows continue to support the carrying value of the asset, if the forecasted cash flows were to materially deteriorate, this could result in a permanent shut down of the facility and in the recognition of an impairment of the power plants and other plants within the respective market.
When we believe an impairment condition may exist on specifically identifiable finite-lived intangibles or an investment, we must estimate their fair value to determine the amount of any impairment loss. Significant judgment is required in determining
fair value as discussed above in “— Fair Value Measurements.”
We test goodwill and all intangible assets not subject to amortization for impairments at least annually, or more frequently whenever an event or change in circumstances occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount. We test goodwill for impairment at the reporting unit level, which is identified one level below the Company’s operating segments for which discrete financial information is available and management regularly reviews the operating results. We perform an annual impairment assessment in the third quarter of each year, or more frequently if indicators of potential impairment exist, to determine whether it is more likely than not that the fair value of a reporting unit in which goodwill resides is less
than its carrying value. For reporting units in which this assessment concludes that it is more likely than not that the fair value is more than its carrying value, goodwill is not considered impaired and we are not required to perform the two-step goodwill impairment test. Qualitative factors considered in this assessment include industry and market considerations, overall financial performance, and other relevant events and factors affecting the reporting unit.
For reporting units in which the impairment assessment concludes that it is more likely than not that the fair value is less than its carrying value, we perform the first step of the goodwill impairment test, which compares the fair value of the reporting unit to its carrying value. If the fair value of the reporting unit exceeds the carrying value of the net assets assigned to that unit, goodwill is not considered impaired and we are not required to perform additional
analysis. If the carrying value of the net assets assigned to the reporting unit exceeds the fair value of the reporting unit, then we must perform the second step of the goodwill impairment test to determine the implied fair value of the reporting unit’s goodwill. If we determine during the second step that the carrying value of a reporting unit’s goodwill exceeds its implied fair value, we record an impairment loss equal to the difference.
All construction and development projects are reviewed for impairment whenever there is an indication of potential reduction in fair value. If it is determined that it is no longer probable that the projects will be completed and all capitalized costs recovered through future operations, the carrying values of the projects would be written down to their fair value. When we determine that our assets meet the assets held-for-sale criteria, they are reported at the lower of the carrying amount
or fair value less the cost to sell. We are also required to evaluate our equity method investments to determine whether or not they are impaired when the value is considered an “other than a temporary” decline in value.
See Note 3 of the Notes to Consolidated Financial Statements for further discussion of our impairment evaluation of long-lived assets.
Accounting for Income Taxes
To arrive at our consolidated income tax provision and other tax balances, significant judgment and estimates are required. Although we believe that our estimates are reasonable, no assurance can be given that the final tax outcome of these matters will not be different than that which is reflected in our historical tax provisions and accruals. Such differences could have a material
effect on our income tax provision, other tax accounts and net income in the period in which such determination is made.
As of December 31, 2017, our NOL carryforwards consisted primarily of federal NOL carryforwards of approximately $6.6 billion, which expire between 2024 and 2037, and NOL carryforwards in 27 states and the District of Columbia totaling approximately $3.5 billion, which expire between 2018 and 2037. Substantially all of the federal and state NOLs are offset with a full valuation allowance. Certain
of the state NOL carryforwards may be subject to limitations on their annual usage. If a subsequent ownership change, such as the ownership change associated with the impending Merger, were to occur as a result of
61
future transactions in our stock, our ability to utilize the NOL carryforwards will be limited. Although we have not completed our analysis, it is reasonably possible that our federal NOLs available to offset future taxable income could materially decrease. This reduction will be offset by an adjustment to the existing valuation allowance for an equal and offsetting amount. Additionally, our state NOLs available to offset future state income could similarly decrease which would also be offset by an equal and offsetting adjustment to the existing
valuation allowance. Given the offsetting adjustments to the existing valuation allowance, any ownership change is not expected to have an adverse material effect on our Consolidated Financial Statements.
We also have approximately $659 million in foreign NOLs, which expire between 2026 and 2037, and the associated deferred tax asset of approximately $165 million is partially offset by a valuation allowance of $106 million. Under Canadian income tax law, our NOL carryfowards can be utilized to reduce future taxable income subject to certain limitations including new applicable limitations resulting from an ownership change which will result in an increase in the valuation allowance and a related charge
to deferred tax expense. It is reasonably possible that an increase of approximately $59 million in the valuation allowance and a related charge to deferred tax expense would occur as a result of the impending Merger.
In the ordinary course of business, there are many transactions and calculations where the ultimate tax outcome is uncertain. Some of these uncertainties arise as a consequence of the treatment of capital assets, financing transactions, multistate taxation of operations and segregation of foreign and domestic income and expense to avoid double taxation. We recognize the financial statement effects of a tax position when it is more likely than not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater
than 50% likely of being realized upon ultimate settlement with a taxing authority. We reverse a previously recognized tax position in the first period in which it is no longer more likely than not that the tax position would be sustained upon examination. The determination and calculation of uncertain tax positions involves significant judgment in the application of complex tax laws. Resolution of these uncertainties in a manner inconsistent with our expectations could have a material effect on our financial condition or results of operations. As of December 31, 2017, we had $38 million of unrecognized tax benefits from uncertain tax positions.
See Note 11 of the Notes to Consolidated Financial Statements for further discussion of our accounting for income taxes.
New
Accounting Standards and Disclosure Requirements
See Note 3 of the Notes to Consolidated Financial Statements for a discussion of new accounting standards and disclosure requirements.
Item 7A.
Quantitative and Qualitative Disclosures about Market Risk
The information required hereunder is set forth under Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Risk Management and Commodity Accounting.”
Item
8.
Financial Statements and Supplementary Data
The information required hereunder is set forth under “Report of Independent Registered Public Accounting Firm,”“Consolidated Statements of Operations,”“Consolidated Statements of Comprehensive Income,”“Consolidated Balance Sheets,”“Consolidated Statements of Stockholders’ Equity,”“Consolidated Statements of Cash Flows,” and “Notes to Consolidated Financial Statements” included in the Consolidated Financial Statements that are a part of this Report. Other financial information and schedules are included in the Consolidated Financial Statements that are a part of this Report.
Item
9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Controls and Procedures
Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and
communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required financial disclosure.
As of the end of the period covered by this Report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Exchange Act. Based upon, and as of the date of, this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that
62
our disclosure controls and procedures
were effective such that the information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. GAAP.
Our
internal control over financial reporting includes those policies and procedures that:
•
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
•
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and
•
provide
reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on our financial statements.
Management has assessed the effectiveness of our internal control over financial reporting as of December 31, 2017. In making its assessment of internal control over financial reporting, management used the criteria described in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
Based on management’s assessment, management has concluded that our internal control over financial reporting was effective as of December 31,
2017 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external reporting purposes in accordance with U.S. GAAP.
In accordance with guidance issued by the SEC, companies are permitted to exclude acquisitions from their final assessment of internal control over financial reporting for the first fiscal year in which the acquisition occurred. On January 17, 2017 and as further discussed in Note 4 of the Notes to Consolidated Financial Statements, we completed the acquisition of North American Power, which represented approximately 1% of total assets and 2% of revenues of our related consolidated financial statement amounts as of and for the year ended December 31,
2017. We have elected to exclude North American Power’s operations from our assessment of internal control over financial reporting as of December 31, 2017.
The effectiveness of our internal control over financial reporting as of December 31, 2017, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
Changes in Internal Control Over Financial Reporting
During the fourth quarter of 2017, there were no changes in our internal control over financial
reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B.
Other Information
None.
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PART III
Item
10.
Directors, Executive Officers and Corporate Governance
Directors
Set forth in the table below is a list of our directors, together with certain biographical information, including their ages as of the date of this Report.
Mary
L. Brlas became a director of the Company on August 10, 2016. Ms. Brlas served as Executive Vice President and Chief Financial Officer of Newmont Mining Corporation from September 2013 to her retirement in October 2016. From 2006 through July 2013, she served in various executive-level positions at Cliffs Natural Resources, Inc., the largest producer of iron ore pellets in North America, most recently as Executive Vice President and President of Global Operations. Prior to that Ms. Brlas served as Senior Vice President and Chief Financial Officer of STERIS plc, a provider of healthcare products, from 2000 through 2006. From 1995 through 2000, Ms. Brlas held various positions with OfficeMax, Inc., most recently as Senior Vice President and Corporate Controller. Ms. Brlas has served on the board of directors at
Albemarle Corporation since June 2017, where she serves on the Audit Committee and Nominating and Governance Committee, and on the board of directors at Perrigo Company plc since August 2003, where she was appointed chairman of the board in April 2016. Ms. Brlas also served as a director for Nova Chemicals Corporation from September 2008 to July 2009. Ms. Brlas obtained a Bachelor of Science degree in Business Administration from Youngstown State University and is a Certified Public Accountant and Certified Management Accountant. Ms. Brlas is a member of the Audit Committee. Ms. Brlas’ extensive executive experience, most recently as chief financial officer of a publicly traded company, and her experience on boards of other companies, including serving as chairman of the board of a publicly traded company, provide her with strong insight, particularly with regard to finance, accounting, operations and corporate governance, and make her a valuable member of our Board
and of our Audit Committee.
Frank Cassidy became a director of the Company on January 31, 2008 and became Chairman of the Board of Directors in May 2016 after serving as lead independent director since May 2014. From 1969 to his retirement in 2007, Mr. Cassidy was employed at Public Service Enterprise Group, Inc. (“PSEG”), an energy and energy services company. From 1999 to 2007, Mr. Cassidy served as President and Chief Operating Officer of PSEG Power LLC, the wholesale energy subsidiary of PSEG. From 1996 to 1999, Mr. Cassidy was President and Chief Executive Officer of PSEG Energy Technologies, Inc. Prior to 1996, Mr. Cassidy held various positions of increasing responsibility at the
Public Service Electric and Gas Company. Mr. Cassidy obtained a Bachelor of Science degree in Electrical Engineering from the New Jersey Institute of Technology and a Master of Business Administration degree from Rutgers University. Mr. Cassidy is a member of the Compensation Committee and Nominating and Governance Committee. Mr. Cassidy’s approximately 40 years of diversified experience in the power generation and energy industries in various positions of increasing responsibility with PSEG provide him with strong insight, particularly with regard to power operations, power sector strategy, management and corporate governance matters, and make him a qualified Chairman of our Board and an effective member of our Compensation Committee and Nominating and Governance Committee.
Jack A. Fusco became a director of the
Company on August 10, 2008. He currently serves as Director, President and Chief Executive Officer of Cheniere Energy, Inc. since May 2016. He previously served as Executive Chairman of the Company’s Board of Directors from May 2014 to May 2016. From August 2008 to May 2014, Mr. Fusco served as Chief Executive Officer of the Company and as President from August 2008 to December 2012. From July 2004 to February 2006, Mr. Fusco served as the Chairman and Chief Executive Officer of Texas Genco LLC. From 2002 through July 2004, Mr. Fusco was an exclusive energy investment advisor for Texas Pacific Group. From November 1998 until February 2002, he served as President and Chief Executive Officer of Orion Power Holdings, Inc. Prior to his founding of Orion
Power Holdings, Inc., Mr. Fusco was a Vice President at
64
Goldman Sachs Power, an affiliate of Goldman, Sachs & Co. Prior to joining Goldman Sachs, Mr. Fusco was employed by Pacific Gas & Electric Company or its affiliates in various engineering and management roles for approximately 13 years. Mr. Fusco obtained a Bachelor of Science degree in Mechanical Engineering from California State University, Sacramento. Mr. Fusco served as a director on the board of Foster Wheeler Ltd., a global engineering and construction contractor and power equipment supplier, until February 2009 and Graphics Packaging Holdings, a paper and packaging company, until 2008. Mr. Fusco’s more than 30 years of experience in the power industry, including as former Chief Executive
Officer of three independent power companies, including Calpine, provide him with strong insight, particularly with regard to commercial and power operations, power sector strategy, commodities and management matters and make Mr. Fusco a valuable and effective member of our Board.
John B. (Thad) Hill III became a director of the Company and has served as our President and Chief Executive Officer since May 14, 2014. He previously served as our President and Chief Operating Officer from December 2012, as our Executive Vice President and Chief Operating Officer from November 2010 to December 2012 and as our Executive Vice President and
Chief Commercial Officer from September 2008 to November 2010. Prior to joining the Company, Mr. Hill served as Executive Vice President of NRG Energy, Inc. from February 2006 to September 2008 and President of NRG Texas LLC from December 2006 to September 2008. Prior to joining NRG Energy, Inc., Mr. Hill was Executive Vice President of Strategy and Business Development at Texas Genco LLC from 2005 to 2006. From 1995 to 2005, Mr. Hill was with Boston Consulting Group, Inc., where he rose to Partner and Managing Director and led the North American energy practice, serving companies in the power and natural gas sectors with a focus on commercial and strategic issues. Mr. Hill received his Bachelor of Arts degree from Vanderbilt University and a Master of Business Administration degree from the Amos Tuck School of Dartmouth College. Mr. Hill’s expertise in the power sector, power operations
and energy commodities along with his knowledge of the Company’s day-to-day operations and overall strategic plan make him a valuable member of our Board.
Michael W. Hofmann became a director of the Company on May 10, 2013. From 1991 until his retirement in 2012, Mr. Hofmann was employed in various capacities at Koch Industries, Inc. (“Koch”), one of the largest private companies in America active in refining, chemicals and biofuels; forest and consumer products; fertilizers; polymers and fibers; process and pollution control equipment and technologies; commodity trading and services; minerals;
ranching; and investments. From 2005 until 2012, Mr. Hofmann served as Vice President and Chief Risk Officer at Koch and also held the position of Chief Risk Officer since 2000 after serving as Chief Market Risk Officer during 1999. Prior to 1999, Mr. Hofmann held various positions of increasing responsibility at Koch, including in its commodity trading operations. Before joining Koch, he had a seven-year audit career with KPMG Peat Marwick. Mr. Hofmann previously served as a member of the economic advisory council for the Federal Reserve Bank of Kansas City and as a member of the Board of Trustees of the Global Association of Risk Professionals, a globally recognized membership association for risk managers. Mr. Hofmann obtained a Master of Business Administration degree as well as a Bachelor of Business Administration degree in Accounting from Wichita State University. He is a Certified Public Accountant and National Association of Corporate Directors Board Leadership
Fellow. Mr. Hofmann’s knowledge and expertise in enterprise risk management and commodity trading operations developed during his 21 years at Koch provide him with strong insight, particularly with regard to strategy, commodities, finance and valuation matters and make him a valuable member of our Board and of our Audit Committee and Compensation Committee.
David C. Merritt became a director of the Company on February 8, 2006. Mr. Merritt is a private investor and consultant. Mr. Merritt was an audit and consulting partner of KPMG LLP from 1985 to 1999. Mr. Merritt also serves as a director of Taylor Morrison Home Corporation, where he serves as a member of the audit committee, and Charter
Communications, Inc., where he serves as chairman of the audit committee. Mr. Merritt previously served as director of Outdoor Channel Holdings, Inc. from 2003 to 2013. Mr. Merritt obtained a Bachelor of Science degree in Business and Accounting from California State University, Northridge. Mr. Merritt’s knowledge and expertise in accounting developed during his 14 years as a partner in a major accounting firm and his service on other boards of directors, including as chairman of other board audit committees provide him with strong insight, particularly with regard to accounting and financial matters, and make him a valuable member of our Board and an effective Chairman of our Audit Committee.
W. Benjamin Moreland became a director of the
Company on January 31, 2008. Until December 31, 2017, Mr. Moreland served as Executive Vice Chairman of Crown Castle International Corp., a provider of wireless communications infrastructure in Puerto Rico and the United States, and, prior to that, as President and Chief Executive Officer from July 2008 to May 2016 and Executive Vice President and Chief Financial Officer since 2000. Mr. Moreland is also a director at Crown Castle International. Prior to joining Crown Castle International in 1999, he held various positions in corporate finance and real estate investment banking with Chase Manhattan Bank from 1984 to 1999. He was also a director of Monogram Residential Trust, Inc., until its privatization in September 2017. Mr. Moreland obtained a Bachelor of Business Administration degree from the University of Texas and a Master of Business Administration degree from
the University of Houston. Mr. Moreland is a member of the Audit Committee. Mr. Moreland’s successful leadership and executive experience as an Executive Vice Chairman, Chief Executive
65
Officer and Chief Financial Officer provide him with strong insight, particularly with regard to finance, equity markets, valuation and management matters, and make him a valuable member of our Board and of our Audit Committee.
Robert A. Mosbacher, Jr. became a director of the Company on February 11, 2009. Mr. Mosbacher is the Chairman of Mosbacher Energy Company, a privately-held
independent oil and gas exploration and production company located in Houston, Texas. Prior to that, Mr. Mosbacher was appointed by President George W. Bush in 2005 as the President and Chief Executive Officer of the Overseas Private Investment Corporation (“OPIC”), an independent U.S. government agency that helps small, medium and large American businesses expand into developing nations and emerging markets around the globe; he served in that position through January 2009. From 1986 until 2005, he served as President and Chief Executive Officer of Mosbacher Energy Company. From 1995 to 2003, Mr. Mosbacher also served as Vice Chairman of Mosbacher Power Group LLC. From August 1999 to October 2005, Mr. Mosbacher served as a Director of the Devon Energy Corporation. He also served on Devon’s Compensation Committee from June 2003 to October 2005. In April 2009, Mr. Mosbacher resumed his role as a director of Devon, and in June 2009 he resumed his role as a member
of Devon’s Compensation Committee and currently serves as Chairman of the Governance Committee. Mr. Mosbacher obtained a Bachelor of Arts degree in Political Science from Georgetown University and a Juris Doctorate from Southern Methodist University. Mr. Mosbacher is Chairman of the Compensation Committee and a member of the Nominating and Governance Committee. Mr. Mosbacher’s extensive and varied management experience in the energy sector including natural gas and independent power generation, his experience with the Federal government at OPIC, and his service as a member of other boards and board committees provide him with strong insight, particularly with regard to energy, management and government and community relations matters, and make him a valuable member of our Board and of our Nominating and Governance Committee, in addition to being an effective Chairman of our Compensation Committee.
Denise M. O’Leary
became a director of the Company on January 31, 2008. Since 1996, she has been a private venture capital investor in a variety of early stage companies. From 1983 to 1996, Ms. O’Leary was an associate, then general partner, at Menlo Ventures, a venture capital firm providing long-term capital and management services to development stage companies. From 2002 to 2006, Ms. O’Leary was a member of the Board of Directors of Chiron Corporation, at which time the company was sold to Novartis AG. Previously a director of U.S. Airways Group Inc., Ms. O’Leary became a director of American Airlines Group Inc. in December 2013 upon the completion of the merger of the two airlines and American Airlines’ emergence from bankruptcy. She is also a director of Medtronic
plc., where she serves as a member of the Nominating and Governance Committee. She obtained a Bachelor of Science degree in Industrial Engineering from Stanford University and obtained a Master of Business Administration degree from Harvard Business School. Ms. O’Leary’s knowledge and understanding of capital markets as a result of her experiences as a venture capital investor as well as her experience serving as a director and member of committees of other boards of directors provide her with strong insight, particularly with regard to corporate governance, ethics and financial matters, and make her a valuable member of our Board and our Compensation Committee, in addition to being an effective Chair of our Nominating and Governance Committee.
Identification of Executive Officers
Set forth in the table below is a list of our executive officers, together with certain biographical
information, including their ages as of the date of this Report:
Senior Vice President and Chief Accounting Officer
Andrew Novotny
41
Senior Vice
President of Commercial Operations
Caleb Stephenson
43
Senior Vice President of Wholesale Origination and Commercial Analytics
___________
(1)
Mr. Hill’s biographical information can be found under “Directors” above.
Zamir
Rauf has served as our Executive Vice President and Chief Financial Officer since December 17, 2008, after serving as Interim Chief Financial Officer from June 4, 2008. Previously, he served as our Senior Vice President, Finance and Treasurer from September 2007 until his appointment as Interim Chief Financial Officer. Since joining the Company in February 2000, Mr. Rauf has served as Manager, Finance from February 2000 to April 2001, Director, Finance from April 2001 to December 2002, Vice President, Finance from December 2002 to July 2005 and Senior Vice President, Finance from July 2005 to September
66
2007.
Prior to joining the Company, Mr. Rauf held various accounting and finance roles with Enron North America and Dynegy Inc., as well as credit and lending roles with Comerica Bank. Mr. Rauf earned his Bachelor of Arts degree in Business and Commerce and Masters in Business Administration – Finance degree from the University of Houston.
W. Thaddeus Miller has served as our Executive Vice President, Chief Legal Officer and Secretary since August 12, 2008. Prior to joining the Company, Mr. Miller served as Executive Vice President and Chief Legal Officer of Texas Genco LLC from December 2004 until February 2006. From 2002 to 2004, Mr. Miller was a consultant to Texas Pacific Group, a private
equity firm. From 1999 to 2002, he served as Executive Vice President and Chief Legal Officer of Orion Power Holdings, Inc., an independent power producer. From 1994 to 1999, Mr. Miller was a Vice President of Goldman Sachs & Co., where he focused on wholesale electric and other energy commodity trading. Before joining Goldman Sachs & Co., Mr. Miller was a partner in a New York law firm. Mr. Miller earned his Bachelor of Science degree from the U.S. Merchant Marine Academy and his Juris Doctor degree from St. John’s School of Law. In addition, Mr. Miller was an officer in the U.S. Coast Guard from 1973 through 1976.
W.G. (Trey) Griggs III has served as our Executive Vice President and President, Calpine Retail since February 2017, after serving as our Executive Vice President and Chief Commercial Officer since June 2015. As President, Calpine Retail, he oversees our retail subsidiaries
comprising Calpine Solutions, Champion Energy and North American Power. Before joining Calpine, Mr. Griggs was a Managing Director at Goldman Sachs & Co., leading its North American Energy Risk Management Franchise activities and its Houston Trading Office beginning in 2011. Prior to that, he served in various roles with Goldman Sachs’ commodities group in New York. From 1995-2000, he was an attorney at law firms in Houston and Greenville, S.C. Mr. Griggs holds an MBA from the Wharton School of the University of Pennsylvania, a Juris Doctorate from University of Houston School of Law, and a Bachelor of Arts degree from Vanderbilt University. As previously announced, Mr. Griggs will be leaving Calpine subsequent to the consummation of the Merger.
Charles M. Gates joined Calpine as Executive Vice President of Power Operations in April 2016. Previously, Mr. Gates had served as Senior Vice President
and Chief Fossil/Hydro Officer for Duke Energy Corporation (“Duke”) since August 2014. He had been Duke’s Senior Vice President of Power Generation Operations since July 2012, when Progress Energy, Inc. merged with Duke. Mr. Gates had served in a similar capacity for Progress Energy, Inc. since January 2012 after being promoted from Vice President of Fossil Generation for Progress Energy, Inc. for the Carolinas and Florida. He was previously General Manager of Progress Energy Florida from the time the company merged with Carolina Power & Light Company in 2001 to 2006. Mr. Gates began his power industry career with Carolina Power & Light in 1982 as an associate engineer and moved up through increasingly responsible positions to become General Manager of five fossil fuel plants in 2000. Mr. Gates’ other industry leadership roles include serving as Chairman of the Generation
Council for the Electric Power Research Institute. He earned bachelor’s degrees in chemical engineering from North Carolina State University and in political science from the University of North Carolina.
Jeff Koshkin has served as Calpine’s Senior Vice President and Chief Accounting Officer since August 1, 2015. He joined Calpine in December 2008 and has served in a number of leadership roles including the Controller of Commercial Operations and Controller of Corporate and Plant Accounting, as well as in interim roles heading Financial Planning and Analysis and as Chief Risk Officer. Prior to Calpine, Mr. Koshkin was a Senior Manager in the Regulatory and Capital Markets practice for Deloitte and Touche, LLP. He holds a master’s degree in Professional Accounting from the University
of Texas at Austin. Mr. Koshkin is a Certified Public Accountant and a member of the American Institute of Certified Public Accountants and the Texas Society of Certified Public Accountants.
Andrew Novotny has served as Calpine’s Senior Vice President of Commercial Operations since May 2014. In this role, he leads the company’s asset portfolio trading team, which includes power and gas trading and logistics across North America. Mr. Novotny joined Calpine in April 2012 as Vice President of Power Trading. In this role, he led the Energy Trading Risk Management system team and took on responsibility for the financial trading group in December 2012. In 2013, he oversaw Calpine’s Southeast power trading group and financial gas hedging. Before joining Calpine, Mr. Novotny served as Vice President of Financial Gas and Power
Trading for the BG Group beginning in 2007. Prior to his time at the BG Group, Mr. Novotny was a Vice President with Duke Energy. Mr. Novotny received a Bachelor of Arts from Vanderbilt University, graduating magna cum laude with high honors in Economics. He also received a Master of Business Administration from Rice University, where he was named a Jones Scholar.
Caleb Stephenson has served as Calpine’s Senior Vice President of Wholesale Origination and Commercial Analytics since February 2017. In this role, he is responsible for the teams who develop wholesale customer relationships and new power projects as well as those who analyze factors affecting the company’s commodity margin performance, including market, regulatory, contractual and operational factors. Mr. Stephenson joined Calpine in October 2008 as Vice President
of Commercial Analytics and became Senior Vice President of Commercial Analytics in May 2014. He came to Calpine from PA Consulting Group’s Global Energy Practice, where he advised merchant power industry participants on energy market outlook and risk management issues.
67
He holds a bachelor’s degree in history and social studies from Oral Roberts University and a Master of Business Administration in finance from Washington University.
Section 16(a) of the Exchange Act requires our directors and executive officers, and beneficial owners of more than 10% of any class of our equity securities including our common stock,
to file with the SEC initial reports of beneficial ownership and reports of changes in beneficial ownership of common stock and other equity securities of the Company, and to provide the Company with a copy of those reports.
Based solely upon our review of the copies of such reports furnished to the Company and written representations that no other reports were required, we are not aware of any instances of noncompliance with the Section 16(a) filing requirements by any director, executive officer or beneficial owner of more than 10% of any class of the Company’s equity securities during the
year ended December 31, 2017, except an inadvertent untimely filing to report 177,627 shares sold by Mr. Miller for proceeds of approximately $2.7 million.
Code of Conduct and Ethics
Our Code of Conduct and Corporate Governance Guidelines regulate related party transactions and apply to all directors, officers and employees. The Code of Conduct requires that each individual deal fairly, honestly and constructively with governmental and regulatory bodies, customers, suppliers and competitors. It prohibits any individual’s taking unfair advantage through manipulation, concealment, abuse of privileged information or misrepresentation of material facts. Further, it imposes an express duty to act in the best interests of the Company and to avoid influences,
interests or relationships that could give rise to an actual or apparent conflict of interest. If any question as to a potential conflict of interest arises, employees are directed to notify their supervisors and the Chief Legal Officer and, in the case of directors and the Chief Executive Officer, the Audit Committee of our Board of Directors. We require our executives to comply with our Code of Conduct as a condition of employment.
Our Code of Conduct also prohibits directors, officers and employees from competing with us, using Company property or information, or such employee’s position, for personal gain, and taking corporate opportunities for personal gain. Waivers of our Code of Conduct must be explicit. The director, officer or employee seeking a waiver must provide his supervisor and the Chief Legal Officer with all pertinent information and, if the Chief Legal Officer recommends approval of a waiver, it shall present
such information and the recommendation to the Audit Committee of our Board of Directors. A waiver may only be granted if (i) the Audit Committee is satisfied that all relevant information has been provided and (ii) adequate controls have been instituted to assure that the interests of the Company remain protected. In the case of our Chief Executive Officer and our directors, any waiver must also be approved by both the Audit Committee and the Nominating and Governance Committee. Any waiver that is granted, and the basis for granting the waiver, will be publicly communicated as appropriate, including posting on our website, as soon as practicable. We granted no waivers under our Code of Conduct in 2017. Our Code of Conduct is posted on our website
at investor.calpine.com/investor-relations/corporate-governance/governance-documents/default.aspx. We intend to post any amendments to and any waivers of our Code of Conduct on our website within four business days.
Shareholder Proposals and Nominations for the 2018 Annual Meeting
As previously announced, if the Merger is consummated prior to the Company’s 2018 annual meeting of shareholders, the Company will not hold an annual meeting of shareholders in 2018 and there will be no public participation in any future meetings of our shareholders because, following the Merger, our common stock will be
delisted from the NYSE and will be deregistered under the Exchange Act, and we will no longer be a publicly-held company. However, if the Merger is not consummated prior to our 2018 annual meeting of shareholders, the following deadlines, as disclosed in the Company’s proxy statement relating to the 2017 annual meeting of shareholders, apply to the submission of shareholder proposals to be considered at Calpine’s 2018 annual meeting of shareholders:
•
Our bylaws provide that no business or director nomination may be brought before our annual meeting of shareholders, unless it is specified
in the notice of meeting or is otherwise brought before the meeting by or at the direction of our board of directors or by a shareholder of record entitled to notice of and to vote at such meeting who has delivered notice and such notice is received by the Corporate Secretary (containing certain information specified in our bylaws about the shareholder and the proposed business or director nomination, as applicable) not less than 90 days nor more than 120 days prior to the anniversary date of the prior year’s annual meeting of shareholders. In the event that our annual meeting of shareholders is called for a date that is not within 30 days before or after such anniversary date, such notice must be received by the Corporate Secretary not later than the close of business on the tenth day following the day on which such notice of the date of the annual meeting was mailed or such public
announcement of the date of the annual meeting was made, whichever first occurs. For business or a director nomination proposed
68
by a shareholder to be eligible to be brought before our 2018 annual meeting of shareholders and for any nominations submitted pursuant to the proxy access provisions of our bylaws, the shareholder’s notice of proposed business or director nomination, as applicable, must not be received by our Corporate Secretary earlier than January 10, 2018 nor later than February 9, 2018.
•
Shareholder
proposals intended to be considered for inclusion in our proxy statement and voted on at our 2018 annual meeting of shareholders must be received at our corporate headquarters by our Corporate Secretary on or before November 29, 2017. Applicable SEC rules and regulations govern the submission of shareholder proposals and our consideration of them for inclusion in the 2018 notice of annual meeting of shareholders and the 2018 proxy statement.
Proposals should be submitted in writing to our Corporate Secretary at our principal executive offices at 717 Texas Avenue, Suite 1000, Houston, Texas77002,
Attn: Corporate Secretary.
Audit Committee
Our Board has a separately designated audit committee established in accordance with Section 3(a)(58)(A) of the Exchange Act. The members of the Audit Committee are David C. Merritt, who serves as chair, Mary L. Brlas, Michael W. Hoffman and W. Benjamin Moreland. The Board has also determined that each member of the Audit Committee has sufficient knowledge and understanding of the Company’s financial statements to serve on the Audit Committee, is independent and is financially literate within the meaning of the
NYSE listing standards as interpreted by the Board. The Board has further determined that each member of the Audit Committee satisfies the definition of “audit committee financial expert” as defined under the federal securities laws.
69
Item 11.
Executive Compensation
COMPENSATION DISCUSSION AND ANALYSIS
This Compensation Discussion
and Analysis section of this Report explains how our executive compensation programs are designed and operate with respect to the following officers identified in the “Summary Compensation Table” below (the “named executive officers”):
Executive Vice President and Chief Financial Officer
W.
Thaddeus Miller
Executive Vice President, Chief Legal Officer and Secretary
W.G. (Trey) Griggs III
Executive Vice President and President, Calpine Retail
Charles M. Gates
Executive Vice President, Power Operations
Executive Summary
Our goal is to be recognized as the premier competitive power company in the United States and our Compensation Committee believes that our executive compensation program is instrumental in helping us achieve this goal. We maintain simple, straightforward compensation programs pursuant to which
our named executive officers’ compensation consists almost entirely of base salary, annual cash incentives and equity grants.
During 2017, we achieved strong operational and financial results despite challenging environments in the competitive wholesale markets in which we operate. Our executive management team remains focused on executing the Company’s strategic plan to create long-term value. The compensation decisions made by the Compensation Committee in 2017 reflect our commitment to aligning executive compensation with shareholder value and focus on incentivizing our executives to improve financial and operating performance.
On August 17, 2017, we entered into the Merger Agreement with Volt Parent, LP (“Volt Parent”) and Volt Merger Sub,
Inc. (“Merger Sub”), a wholly-owned subsidiary of Volt Parent, pursuant to which Merger Sub will merge with and into Calpine, with Calpine surviving the Merger as a subsidiary of Volt Parent. On December 15, 2017, the Merger was approved by our shareholders representing a majority of the outstanding shares of Calpine common stock.
At the effective time of the Merger, each share of Calpine common stock outstanding as of immediately prior to the effective time of the Merger (excluding certain shares as defined in the Merger Agreement) will cease to be outstanding and be converted into the right to receive $15.25 per share in cash or approximately $5.6 billion in total. Calpine currently expects the Merger to be completed in the first quarter of 2018, subject to the receipt of certain
regulatory approvals and the satisfaction or waiver of certain other customary closing conditions.
Our Compensation Program Objectives and Guiding Principles
The Compensation Committee believes that the compensation program for our named executive officers emphasizes at-risk, performance-based compensation without motivating imprudent risk taking. The Compensation Committee believes that our executive compensation program also helps Calpine recruit, retain and motivate a highly talented team of executives with the requisite set of skills and experience to successfully lead the Company in creating value for our shareholders. In addition, the Compensation Committee believes that the mix and structure of compensation for our
executives strikes an appropriate balance to promote long-term returns without motivating or rewarding excessive risk taking. The compensation objectives and principles that govern the Company’s compensation decisions include:
•
Alignment with Shareholders’ Interests. Our long-term incentive awards are equity-based, linking a significant portion of our named executive officers’ pay to share price performance.
•
Pay for Performance.
A significant portion of compensation for our named executive officers is linked to share price performance and the achievement of corporate operating and financial objectives which we believe drive shareholder value.
•
Emphasis on Performance over Time. The compensation program for our named executive officers is designed to minimize excessive short-term decision making and risk taking. The value of long-term incentives is substantially greater than the annual cash incentive bonus and our annual incentive plan limits the maximum cash incentive bonus
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that
can be earned in a given year. The Compensation Committee also retains the discretionary power to reduce annual incentive awards below calculated values.
•
Recruitment, Retention and Motivation of Key Leadership Talent. We provide an appropriate combination of fixed and variable compensation designed not only to attract and motivate the most talented executives for Calpine, but also to encourage retention by vesting equity awards over three years.
The following charts illustrate the mix of pay for our Chief Executive Officer (“CEO”) and our other named executive officers (“Other NEOs”). A significant portion of each named executive officer’s compensation is tied
to performance-based short- and long-term incentives.
Results of the 2017 Advisory Vote on Executive Compensation (“say-on-pay”)
At
the Company’s Annual Meeting of Shareholders held in May 2017, our shareholders were asked to approve the Company’s fiscal 2016 executive compensation programs. A substantial majority (96%) of the votes cast on the “say-on-pay” proposal at that meeting were voted in favor of the proposal. As Calpine regularly engages shareholders to discuss a variety of aspects of our business and welcomes shareholder input and feedback, the “say-on-pay” vote serves as an additional tool to guide the Board and the Compensation Committee in ensuring alignment of Calpine’s executive compensation programs with shareholder interests. The Compensation Committee believes that these results reaffirm our shareholders’ support of the
Company’s approach to executive compensation.
The Compensation Committee continues working to ensure that the design of the Company’s executive compensation program is focused on long-term shareholder value creation, emphasizes pay for performance and does not encourage imprudent short-term risks. The Compensation Committee also continues to use the “say-on-pay” vote as a guidepost for shareholder sentiment and believes it is critical to maintain and continually develop this program to promote ongoing shareholder engagement, communication and transparency.
Determining Executive Compensation
The Compensation Committee bases any adjustments to current pay levels on several
factors, including the scope and complexity of the functions an executive officer oversees, the contribution of those functions to our overall performance, individual experience and capabilities, individual performance and competitive pay practices. Any variations in compensation among our executive officers reflect differences in these factors.
Compensation Consultant
The Compensation Committee has authority to retain compensation consulting firms to assist it in the evaluation of executive officer and employee compensation and benefit programs. Since 2012, the Compensation Committee has retained Meridian Compensation Partners, LLC (“Meridian”) as its independent compensation advisor. Meridian reports exclusively to the
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Compensation
Committee, which has sole authority to engage, dismiss and approve the terms of engagement of its consultant. Meridian provides an objective perspective as to the reasonableness of our executive compensation programs and practices and their effectiveness in supporting our business and compensation objectives. During 2017, Meridian regularly participated in Compensation Committee meetings and advised the Compensation Committee with respect to compensation trends and best practices, incentive plan design, competitive pay levels, our proxy disclosure, and individual pay decisions with respect to our named executive officers and other executive officers.
While Meridian regularly consults with management in performing work requested by the Compensation Committee, Meridian did not perform any separate additional services for management. The CEO meets with the Compensation Committee and the compensation consultant to discuss performance
objectives and review compensation recommendations for executive officers directly reporting to him, including the other NEOs. Thereafter, the Compensation Committee meets privately with the independent compensation consultant to review the compensation recommendations. Final decisions on compensation for the NEOs are made solely by the Compensation Committee. The Compensation Committee has assessed the independence of Meridian pursuant to applicable SEC rules and concluded that no conflict of interest exists that would prevent Meridian from independently representing the Compensation Committee.
Comparator Group
We believe it is appropriate to provide industry-competitive total compensation opportunities to our named executive officers in order to attract and retain top executive talent. However, we do not rely on this information to target any specific pay percentile for our executive
officers. Instead, we use this information to provide a general overview of market practices and to ensure that we make informed decisions regarding our executive pay programs.
To help the Compensation Committee establish target compensation levels for the named executive officers, Meridian prepared an analysis that compared the then current level of compensation for our named executive officers and compensation paid to comparable positions at companies in an industry comparator group approved by the Compensation Committee. The primary criteria used to identify this 2017 comparator group were: (1) industry and energy portfolio – we compete for talent with energy and utility companies that have significant generation portfolios and significant non-regulated energy operations, and (2) financial scope – our compensation opportunities should compare competitively against companies that have similar financial characteristics.
Historically,
other IPPs comprise our closest pool of direct competitors. However, due to consolidation in our industry over the last decade, the number of other IPPs has recently been limited to two companies: Dynegy Inc. and NRG Energy, Inc. In order to evaluate competitive compensation data more closely aligned with our direct competitors, our Compensation Committee uses a primary group consisting only of IPP peer companies and a supplemental broader group of companies consisting of 32 electric companies (including Dynegy Inc., NRG Energy, Inc. and TransAlta Corporation from the primary group of IPP peer companies) that participate in a nationally recognized executive compensation survey. Our Compensation Committee used these two comparator groups to assist in setting 2017 compensation for our named executive officers. We believe that the 2017 comparator group provided an appropriate reference for compensation data for companies with which Calpine competes for talent.
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Our 2017 primary comparator group consisted of IPP peer companies:
The AES Corporation
NRG Energy, Inc.
Dynegy Inc.
TransAlta Corporation
Our 2017 supplemental comparator group consists of the following
companies:
Alliant Energy Corporation
National Fuel Gas Company
Ameren Corporation
Nextera Energy, Inc.
American Electric Power Company, Inc.
NRG Energy, Inc.
Centerpoint
Energy, Inc.
OGE Energy Corp.
CMS Energy Corporation
ONE Gas, Inc.
Direct Energy
Pinnacle West Capital Corporation
Dominion Resources, Inc.
PNM Resources, Inc.
Duke Energy Corporation
PPL
Corporation
Dynegy Inc.
Sempra Energy
Edison International
Southwest Gas Corporation
Eversource Energy
Spire Inc.
Exelon Corporation
The Southern Company
FirstEnergy
Corp.
TransAlta Corporation
Hawaiian Electric Industries, Inc.
Vectren Corporation
Just Energy Group Inc.
WEC Energy Group, Inc.
MDU Resources Group, Inc.
Xcel Energy Inc.
The
Compensation Committee considered pay data from the appropriate position matches within the 2017 comparator group for our named executive officers, including the effect on compensation, if any, of specific company size differences. The 2017 comparator group allowed us to monitor the compensation practices of our competitors for executive talent. We do not formally target total compensation, or any specific element of compensation to a specific percentile of the comparator group. Instead, the market data is used to provide a competitive range of pay levels and to obtain a general understanding of current compensation practices in our industry.
Role of Executive Officers in Executive Compensation Decisions
The Chief Executive Officer reviews the compensation data gathered from the compensation surveys, considers each other executive officer’s performance and makes a recommendation
to the Compensation Committee on base salary, annual bonus and equity awards for each named executive officer other than himself. The Chief Executive Officer participates in Compensation Committee meetings at the Compensation Committee’s request to provide background information regarding the Company’s strategic objectives and to evaluate the performance of and compensation recommendations for the other executive officers. The Committee utilizes the information provided by the Chief Executive Officer along with input from Meridian and the knowledge and experience of the Committee’s members in making compensation decisions. Executive officers do not propose or seek approval for their own compensation. The Chairman of the Compensation Committee, with input from the Chairman of the Board of Directors, recommends the Chief Executive Officer’s compensation to the Compensation Committee in
an executive session, not attended by the Chief Executive Officer.
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Elements of Compensation
Compensation for the named executive officers primarily consists of:
Type
Purpose
Base Salary
Provide a minimum, fixed level of cash
compensation to compensate executives for services rendered during the fiscal year.
Annual Cash Incentives
Drive achievement of annual corporate goals including key financial and operating results and strategic goals that drive value for shareholders.
Long-Term Incentives
Align executive officers’ interests with the interests of shareholders by rewarding increases in the value of our share price.
Post-Employment Compensation
Assist executive officers and other eligible employees to prepare financially for retirement, to offer benefits that are competitive and tax-efficient,
and to provide a benefits structure that allows for reasonable certainty of future costs.
Help retain executive officers and certain other qualified employees, maintain a stable work environment and provide financial security in the event of a change in control or in the event of a termination of employment in connection with or without a change in control.
Allocation and Distribution of Each Element of Compensation
The portion of total compensation delivered in the form of base salary and benefits is intended to provide a competitive foundation and fixed rate of pay for the work being performed by each named executive officer and the associated level of responsibility and contributions to Calpine. The compensation opportunity beyond those pay elements is at risk and must be earned through achievement of
annual goals, which represent performance expectations of the Board and management and long-term value creation for shareholders. In setting target compensation, the Compensation Committee focuses on the total compensation opportunity for the executive. The proportion of compensation designed to be delivered in base salary versus variable pay depends on the executive’s position and the ability of that position to influence overall Company performance. The more senior the level of the executive, the greater is the percentage of total pay opportunity that is variable.
Details of Each Element of Compensation
Base Salary. The 2017 base salary of each of our named executive officers was set following an annual review, during which adjustments were made to reflect performance-based factors, as well as competitive considerations. During its
annual review of base salaries, the Compensation Committee primarily considers:
•
our budget for annual merit increases;
•
the appropriateness of each executive officer’s compensation, both individually and relative to the other executive officers;
•
the individual performance of each executive officer; and
•
pay
data from our comparator group of companies provided by our independent compensation advisor.
We do not apply specific formulas to determine increases to base salary, which are granted to recognize individual performance and contributions to the improved strategy and operations of the Company. Adjustments to executive salaries are generally effective with the first payroll period after the adjustment is determined. Base salaries and percentage increases from the previous year’s base salary for our named executive officers are indicated below for 2017:
Reflects the percentage increase from the base salary in effect prior to the effective date of Mr. Hill’s amended and restated employment agreement on May 16, 2017.
Annual Incentive — Calpine Incentive Plan. Our annual incentive program, the CIP, is designed to promote the achievement of annual corporate goals including key financial, operating and strategic goals that, in turn, drive value for shareholders. Most regular full-time, non-collective bargaining unit employees hired prior to October
1, 2017, were eligible to participate in the CIP including all our named executive officers. The Compensation Committee assigned to each executive officer a target incentive opportunity, expressed as a percentage of eligible earnings (base salary amount paid in 2017), which is dependent on the level of the employee’s position and the scope of the employee’s responsibilities. Target annual incentive levels for each named executive officer are shown in a table below. The total target CIP incentive pool is the sum of all participants’ target annual incentive amounts.
CIP Funding. Funding of the CIP incentive pool is triggered only if we meet a minimum corporate performance target established by the Compensation Committee. For fiscal 2017, this minimum corporate performance target was $1,498 million of Adjusted EBITDA, which was 80% of our fiscal 2017 Adjusted EBITDA goal of $1,873 million. We use Adjusted
EBITDA because it is a metric used by our Board of Directors and senior management in evaluating our financial performance. Our Adjusted EBITDA of $1,855 million exceeded our minimum corporate performance target for fiscal 2017. As a result, the 2017 CIP incentive was funded.
Adjusted EBITDA represents net income before interest, income taxes and depreciation and amortization adjusted for the effects of impairment losses, gains or losses on sales, dispositions or retirements of assets, any mark-to-market gains or losses from accounting for derivatives, adjustments to exclude the Adjusted EBITDA related to the noncontrolling interest, stock-based compensation expense, operating lease expense, non-cash gains and losses from foreign currency translations, major maintenance expense, gains or losses on the repurchase or extinguishment of debt, non-cash GAAP-related adjustments to levelize revenues from tolling agreements and any
unusual or non-recurring items plus adjustments to reflect the Adjusted EBITDA from our unconsolidated investments.
Determination of CIP Bonus Pool. The size of the CIP incentive pool is based on the extent to which we achieve the corporate performance goals that are established annually by the Compensation Committee. The Compensation Committee selected these performance goals to reflect a balanced evaluation of annual financial and operating performance. Specific performance metrics include cash generation, cost containment, safety and achievement of key goals that drive the creation of shareholder value. The 2017 performance goals and the actual results are shown in the following table and discussed in further detail below:
CIP Performance Score Calculation ($ in millions) for 2017
Performance
Level Performance Score
Threshold
Target
Maximum
Results
Score
Weight
Weighted
Score
Commodity Margin
$
2,775
$
2,875
$
3,075
$
2,791
66.3
%
35.0
%
23.2
%
Expenses
$
1,088
$
1,003
$
768
$
936
125.7
%
35.0
%
44.0
%
CAPEX/Maintenance
$
461
$
436
$
378
$
429
111.0
%
10.0
%
11.1
%
TRIR
1.3
0.75
0.45
0.86
92.0
%
10.0
%
9.2
%
Average
EFOF
4.76
%
2.8
%
0.91
%
4.99
%
—
%
5.0
%
—
%
Regulatory
Compliance (Pass/Fail)
No material non-compliance events
PASS
100.0
%
5.0
%
5.0
%
Overall
Performance Score
100
%
92.5
%
Board Discretionary Increase Factor
1.07
Final
Performance Score
99.2
%
Explanation of Performance Measures.
•
Commodity Margin, as used for purposes of determining our CIP goal, is a financial measure that includes power and steam revenues, sales of purchased power and physical natural gas, capacity revenues, renewable energy credit revenue, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel
transportation expense, environmental compliance expenses, ancillary retail expense and realized settlements from marketing, hedging, optimization and trading activities, but excludes mark-to-market activity. Commodity Margin is a key operational measure of profit used to assess the performance of our business. This amount differs from “Commodity Margin” as reported under FASB Accounting Standards Codification 280 in this Report as it also includes other revenue, as referenced in the CIP performance score calculation, Adjusted EBITDA from Calpine’s unconsolidated operations at Greenfield and Whitby, and certain other adjustments.
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•
Expenses,
as used solely for purposes of determining our CIP pool, are composed of Operating and Maintenance Expense (excluding major maintenance, scrap and stock-based compensation), Royalty Expense from Calpine’s geothermal operations, General & Other Administrative Expense (excluding stock-based compensation), and Other Operating Expense (excluding amortization, stock-based compensation and Merger-related costs), in each case, as calculated in accordance with U.S. GAAP and included in the amounts reported on our Consolidated Statement of Operations for the year ended December 31, 2017 in this Report. We believe that Expenses are a useful tool for assessing the performance of our core operations and are a key operational measure reviewed by our management.
•
CAPEX/Maintenance
refers to Calpine’s Capital Expenditure and Major Maintenance Expense related to the refurbishment of major turbine generator equipment and other plant-related facilities inclusive of Calpine’s unconsolidated operations at Greenfield and Whitby. CAPEX is capitalized into Property, Plant and Equipment and Maintenance is recorded as a component of Operating and Maintenance Expense. We monitor these expenditures and establish targets as useful tools to measure our operating performance. We believe that monitoring our Capital Expenditure and Major Maintenance Expense allows us to ensure that planned capital projects are not experiencing cost overruns.
•
Average EFOF refers to Equivalent Forced Outage Factor, which is a measure
indicating the percent of time that our power plants are not capable of reaching full capacity due to forced outages and forced equipment limitations and is a key operating measure to assess plant availability.
•
TRIR refers to Total Recordable Incident Rate, which is a measure of operational safety. We place a high priority on the safety of our employees. TRIR is calculated as the sum of our lost time, restricted duty and other recordable cases as well as any fatality incidents during the year multiplied by 200,000 and then divided by total hours worked during the year.
•
Regulatory
Compliance refers to the Compensation Committee evaluation of overall regulatory compliance based on consultation with the Chief Compliance Officer to ensure compliance with all applicable statutes in the operation of our business.
•
Board Discretionary Increase/Decrease Factor represents the Board’s consideration of the quantitative outcomes of the Performance Measures and the strategic achievements in what was an important transition year for the Company. Therefore, in its discretion, the Board applied a strategic premium to the other calculated outcomes to yield a 99.2% score.
Determination
of Individual Award Payouts. Based on the extent to which we achieved the performance goals, as shown above, approximately $46 million was funded to the total CIP bonus pool for 2017 for allocation among the plan participants. Threshold incentive levels under the CIP are set at 60% of the target incentive percentage for all participants. The following table shows the incentive eligible earnings and target and maximum incentive percentages and actual payout amounts for each named executive officer:
The
maximum incentive as a percentage of base salary is set forth in the employment agreement or letter agreement for these named executive officers.
(2)
Messers. Griggs’ and Gates’ maximum incentive is consistent with the terms of the CIP.
(3)
Incremental Incentive Rate equals the additional percentage of eligible earnings for each percent that Overall Performance Score exceeds 100%. Rate is calculated as the ratio of the difference between maximum and target incentive percentage and maximum and target Performance Score.
(4)
From
2017 CIP performance score calculation shown above.
(5)
Incentive % equals sum of Target Incentive plus product of excess of Overall Performance Score over 100% multiplied by Incremental Incentive Rate.
Long-Term Incentives. Effective January 31, 2008, our Board of Directors adopted, and our shareholders approved, the 2008 Equity Plan. Effective May 10, 2017, our Board of Directors adopted, and our shareholders approved, the 2017 Equity Plan
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which
replaced the 2008 Equity Plan. All equity grants to our named executive officers on or after May 10, 2017 will be made under the 2017 Equity Plan. The Equity Plans are administered by the Compensation Committee, which has authority to grant the following types of awards to our directors, executive officers, employees and consultants: stock options, stock appreciation rights, restricted stock, restricted stock units, performance compensation awards, other stock-based awards or any combination of these types of awards. Equity grants directly align our named executive officers’ interests with the interests of shareholders by rewarding increases in the value of our share price. Such grants enable us to attract and retain highly qualified individuals for positions of responsibility.
The Compensation Committee generally approves annual equity grants to the named executive officers
at its February meeting. Equity award vesting is generally subject to continued employment, with exceptions in some cases for a change in control or termination due to death or retirement.
Determination of Target Value of Long-Term Incentives. On an annual basis, during its February meeting of each calendar year, the Compensation Committee determines, and makes its recommendations to the Board regarding, the form and amounts of long-term incentive compensation for our executive officers. In February 2017, the Board approved annual awards of restricted stock units, stock options and PSUs, as applicable, to our named executive officers. The target value of annual equity awards granted to each of the named executive officers is generally determined based on internal equity considerations, data regarding similar positions at other companies within our industry, differences in responsibilities within our
Company for each of the named executive officers and their respective contributions to our overall corporate success. In 2017, the target value of each named executive officer’s equity awards expressed as a percentage of base salary was 300% for Mr. Hill and 200% of base salary for Messrs. Rauf, Griggs, Miller and Gates. The equity awards granted in 2017 to Messrs. Hill, Rauf, Griggs, Miller and Gates consisted 40% of restricted stock units, 30% of stock options and 30% of PSUs. See “ — Grants of Plan-Based Awards.”
Restricted Stock Unit Grants. Restricted stock units granted to our named executive officers in February 2017 were conditioned upon shareholder approval of the 2017 Equity Plan, which was obtained on May 10, 2017. As a result, the restricted stock units granted to Messrs. Hill, Rauf, Gates and Griggs vest over a service period which
commenced on May 10, 2017 and concludes on February 15, 2020. One-third of the award will vest on February 15th of each year over the service period, subject to forfeiture upon termination and acceleration upon certain events including death or disability. The restricted stock units granted to Mr. Miller in 2017 vested 100% on December 31, 2017 in accordance with his employment agreement, which was in effect on the grant date.
Stock Option Grants. Stock options granted to Messrs. Hill, Rauf, Gates and Griggs in February 2017 vest over a three year service period and are subject to forfeiture upon termination and acceleration upon certain events including death or disability. The stock options granted to Mr. Miller in 2017 vested 100% on December
31, 2017 in accordance with his employment agreement which was in effect on the grant date. The stock options have an exercise price that is at least equal to 100% of the fair market value of the common stock on the grant date and have a ten-year term.
Performance Share Unit Grants. In February 2017, the Compensation Committee approved a new PSU program based on absolute shareholder return performance standards which it believes continues its ongoing commitment to deliver performance-based compensation aligned with shareholder interests. The new PSU program includes the following features:
•
a grant of PSUs that each track the value and distributions of a Calpine common share of stock;
•
a
three-year performance period and cliff vesting requirement subject to certification of the performance goals by the Compensation Committee following the completion of the performance period;
•
an opportunity to earn between 0% and 150% of the awarded PSUs based on Calpine’s absolute shareholder returns over the performance period as shown below:
Calpine Annualized TSR
Percent
of PSUs Earned
+15% (maximum)
150%
+8% (target)
100%
-10% (threshold)
50%
Less than -10%
0%
The PSUs granted
to our named executive officers in 2017 will vest and be paid in cash based on the Company’s absolute shareholder returns over the period from January 1, 2017 through December 31, 2019 and are conditioned upon continued employment (other than with respect to Mr. Miller whose PSUs are no longer subject to forfeiture as of December 31, 2017 in
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accordance with his employment agreement which was in effect on the grant date). Actual amounts of awards granted in February 2017 are disclosed in the “Summary Compensation Table”
and the “Grants of Plan-Based Awards” table.
Grant of Equity Awards in connection with Employment Agreement. On May 16, 2017, we entered into an amended and restated employment agreement with Mr. Hill which provided for a special supplemental grant of long-term incentive awards under the 2017 Equity Plan. Thus, on May 16, 2017, Mr. Hill received a grant of 9,677 shares of restricted stock, 15,571 stock options and 6,706 performance share units. See “Executive Compensation — Summary of Employment Agreements” for a further description of these awards.
Settlement of Equity Awards in connection with the Merger. Upon consummation of the Merger, all equity awards will be treated as follows:
•
all
vested and unvested stock options will become canceled and the holders of the stock options will receive a cash payment equal to the intrinsic value based on a share price of $15.25 per share less any applicable withholding taxes;
•
all restricted stock and restricted stock units will become vested and canceled and the holders will receive a cash payment equal to a share price of $15.25 per share less any applicable withholding taxes;
•
all
PSUs, including the PSUs awarded in 2015 for the measurement period of January 1, 2015 through December 31, 2017, will become vested and canceled in exchange for a cash payment with the payout value based on the greater of target value or actual performance over the truncated period using a share price of $15.25 per share less any applicable withholding taxes.
For further information on the Merger Agreement, please refer to the Current Report on Form 8-K filed on August 22, 2017 and the proxy statement filed on November 14, 2017 by Calpine.
Perquisites and Other Personal Benefits. We offer a very limited
amount of perquisites and other personal benefits to our named executive officers. The Compensation Committee believes that these perquisites are reasonable and consistent with prevailing market practice and the Company’s overall compensation program. Perquisites are not a material part of our compensation program. The Compensation Committee periodically reviews the levels of perquisites and other personal benefits provided to our named executive officers. See “— Summary Compensation Table — All Other Compensation.”
Post-Employment Compensation Arrangements
To promote retention and recruiting, we offer various arrangements that provide certain post-employment benefits in order to alleviate concerns that may arise in the event of an employee’s separation from service with us and enable employees
to focus on Company duties while employed by us. These post-employment severance benefits are provided through employment agreements and letter agreements as described more fully below under “— Summary of Employment Agreements” and “— Potential Payments Upon Termination or Change in Control.”
Retirement Benefits. Our executive officers participate in retirement plan programs provided to all Calpine employees and do not receive special retirement plans or benefits. Our primary objectives for providing retirement benefits is to assist employees in preparing financially for retirement, to offer benefits that are competitive and to provide a benefits structure that allows for reasonable certainty of future costs. Except for certain employees represented by a collective bargaining agreement, Calpine does not have a defined benefit plan for employees, including our named executive officers.
Our
primary retirement benefit is the Calpine Corporation Retirement Savings Plan (the “401(k) Plan”), a defined contribution plan. For our executive officers as well as all other non-bargaining unit employees, we match employee contributions 100% up to 5% of eligible earnings, subject to all applicable regulatory limits, and the match vests immediately. In addition, if an employee leaves our employment due to retirement, the employee can use any money remaining in his or her health reimbursement account to pay for post-employment medical insurance.
Severance Benefits. We maintain the Severance Plan that provides certain severance benefits to our executive officers and other qualified employees. The purpose of the Severance Plan is to help retain our executive officers and other qualified employees, maintain a stable work environment and provide financial security to our executive officers and certain
other employees of the Company in the event of a change in control or in the event of a termination of employment in connection with or without a change in control. The Severance Plan does not provide for the payment of an excise tax gross-up under any circumstances.
For a further discussion of the Severance Plan, see “— Potential Payments Upon Termination or Change in Control” below. For a further discussion of the Employment Agreements, see “— Summary of Employment Agreements” below.
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Report of the Compensation Committee
The
Compensation Committee has reviewed and discussed the “Compensation Discussion and Analysis” section of this Report with the Company’s management. Based on this review and discussion, the Compensation Committee recommended to our Board of Directors that the “Compensation Discussion and Analysis” section be included in this Report.
The following table provides certain information concerning the compensation for services rendered to us during the years ended December 31, 2017, 2016 and 2015 by (i) each person serving as a principal executive officer during the year ended December 31, 2017, (ii) each person serving as a principal financial officer during the year ended December
31, 2017 and (iii) each of the three other most highly-compensated individuals who were serving as executive officers as of December 31, 2017 (collectively, the “named executive officers”):
The
amounts set forth next to each award represent the aggregate grant date fair value of awards computed in accordance with FASB Accounting Standards Codification Topic 718. The stock awards granted in 2017 were issued in the form of restricted stock, restricted stock units and PSUs. For discussion of the assumptions used in these valuations, see Note 13 of the Notes to Consolidated Financial Statements. Assuming the maximum performance levels were probable on the grant date for the PSUs, the grant date fair values for each of our named executive officers for PSUs awarded in 2017 would be as follows: $1,651,165 for Mr. Hill, $559,846 for Mr. Rauf, $761,983 for Mr. Miller, $459,451 for Mr. Griggs and $412,388 for Mr. Gates.
(2)
Bonus paid pursuant
to the CIP and/or the named executive officer’s employment agreement or letter agreement, as applicable.
(3)
For 2017, the amounts set forth under “All Other Compensation” represents $13,500 in employer contributions to the Company’s 401(k) Plan.
(4)
Represent a one-time cash sign-on bonus in 2016 for Mr. Gates in conjunction with the commencement of his employment on April 1, 2016.
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Grants of Plan-Based Awards
The following table sets forth the information concerning the grants of any plan-based compensation to each named executive officer during 2017. The non-equity awards described below were made under the CIP. The equity awards described below were made under the Equity Plans.
Estimated
Future Payouts Under Non-Equity Incentive Plan Awards(1)
Estimated Future Payouts Under Equity Incentive Plan Awards(2)
All other Stock Awards: Number of Shares of Stock or Units (#)
All other Option Awards: Number of Securities Underlying Options (#)
Exercise or Base Price of Option Awards ($/Sh)
Grant Date Fair Value of Stock and Option Awards ($)
Amounts
represent estimated possible payments under the CIP. Actual amounts paid under the CIP for 2017 are shown in the “Non-Equity Incentive Plan Compensation” column of the “Summary Compensation Table.” For more information on the performance metrics applicable to these awards, see “Compensation Discussion and Analysis — Details of Each Element of Compensation — Annual Incentive — Calpine Incentive Plan.”
(2)
Represents PSUs granted on February 15, 2017 with payouts in cash that range from 0 to 150% of the target award based on the Calpine’s total shareholder return over the three year performance period.
(3)
Grants
made on February 15, 2017 were granted pursuant to the 2008 Equity Plan. Grants made on May 10, 2017 and May 16, 2017 were granted pursuant to the 2017 Equity Plan.
(4)
Threshold amount represents performance at -10% for Calpine’s total shareholder return and actual performance below this level would result in no cash payout of the PSUs.
Represents
restricted stock granted to Mr. Hill on May 16, 2017, vesting ratably on each of the first three anniversary dates of the grant date.
Summary of Employment Agreements
Certain of the amounts shown in the “Summary Compensation Table” and the “Grants of Plan-Based Awards” table are provided for in employment or letter agreements, as the case may be. The material terms of those agreements are summarized below:
On May
16, 2017, we entered into an amended and restated employment agreement with John B. (Thad) Hill III, the Company’s President and Chief Executive Officer (the “Hill Employment Agreement”), which replaced the original employment agreement entered into between the Company and Mr. Hill, effective as of the Company’s 2014 annual meeting of shareholders (the “Prior Agreement”). The Hill Employment Agreement has a three-year term. Under the Hill Employment Agreement, Mr. Hill is entitled to an annual base salary of at least $1,200,000 and an annual target cash performance bonus equal to 110% of annual base salary, with
a maximum annual performance bonus opportunity of two times Mr. Hill’s target bonus. The Hill Employment Agreement provides that Mr. Hill is entitled to receive a special supplemental grant of long-term incentive awards under the 2017 Equity Plan with a target value equal to 25% of his base salary, composed of the following types of awards: 40% restricted stock, 30% stock options and 30% PSUs. The restricted stock awards vest ratably over a three-year service period on each of the first, second and third anniversaries of the grant date subject to forfeiture upon termination and acceleration upon certain events including death, disability, and a change in control. The stock options (which have an exercise price equal to the grant-date price) have a three-year cliff vesting requirement subject to acceleration upon certain events including death, disability, and a change in control. The PSUs will vest and be paid in cash based on the
Company’s absolute shareholder returns over the period from May 16, 2017 through May 15, 2020, subject to the Compensation Committee’s certification of performance results following the completion of the performance cycle, subject to acceleration upon certain events including death, disability, and a change in control.
Upon a termination of Mr. Hill’s employment by the Company without “cause” or by Mr. Hill for “good reason” (each as defined in the Hill Employment Agreement), the Hill Employment Agreement provides that Mr. Hill will be entitled to receive: (i) all accrued obligations; (ii) a lump-sum cash payment equal to 2.0 times the sum of (A) Mr. Hill’s highest base salary in the three years preceding the termination, plus
(B) Mr. Hill’s highest target bonus for the year of termination; (iii) a pro-rata annual bonus calculated based on actual performance for such year relative to the performance goals applicable to Mr. Hill and the number of days in the year of termination that Mr. Hill was employed by the Company; (iv) reimbursement of outplacement benefits for 24 months; (v) pro-rata vesting of all equity and equity-based awards, calculated based on the portion of the vesting period that Mr. Hill was employed with the Company, and for PSUs, based on actual performance for the full performance period; and (vi) a monthly payment for a period of 24 months equal to the full monthly premium paid by other former employees for continuation coverage under the
Company’s health plans, as well as a tax gross-up on such payments (the “Additional Payment”). In the event Mr. Hill experiences the same termination of employment in connection with a change in control, the Hill Employment Agreement provides that he will be entitled to receive the same payments described immediately above, except that: (x) the multiple for his lump-sum cash payment will be 2.99 rather than 2.0 and the portion of such payment calculated based on his annual bonus will be calculated based on the higher of his target bonus for the year of termination or the year of the change in control, and (y) Mr. Hill will be entitled to the Additional Payment for a period of 36 months rather than 24 months.
In the event Mr. Hill experiences a disability or death during the term of the Hill Employment Agreement, the Company will
pay him or his estate: (i) all accrued obligations; (ii) a full annual bonus calculated based on actual performance for such year relative to the target performance goals applicable to Mr. Hill; (iii) full vesting of all equity and equity-based awards, including deeming the PSUs fully earned at the target level and settled on the date of death or disability, as applicable; and (iv) payment of the Additional Payment for a period of 18 months.
If either the Company or Mr. Hill provides the other party with notice of non-renewal of the Hill Employment Agreement at least six months prior to the end of the Hill Employment Agreement’s term and Mr. Hill’s employment terminates on the last day of the Hill Employment Agreement’s term, then upon such termination: (A) all stock options, stock appreciation rights, and performance share units outstanding
as of the last day of the term of the Hill Employment Agreement will continue to vest pursuant to their terms as if Mr. Hill were still employed through each remaining vesting date or the end of the performance period, as applicable, and (B) all restricted stock, restricted stock units, and other awards outstanding on the last day of the term of the Hill Employment Agreement and not addressed in the preceding clause will vest and be settled upon such termination of employment.
In the event of a change in control, all equity and equity-based awards outstanding and held by Mr. Hill as of such date will vest. All PSUs outstanding will be settled based on the greater of the actual achievement of the applicable performance conditions and 100% of target, measured through the date immediately prior to the change in control.
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Mr.
Hill is generally required to sign a release of claims in order to receive the termination benefits described above but he will not be required to execute a release of claims as a condition of receiving any benefits upon his termination of employment in connection with a change in control. Further, if any benefit payable to Mr. Hill is subject to the excise tax imposed by Section 4999 of the Code, then such payments shall be reduced until the payments are no longer subject to such tax; provided, however, that if the net amount of such payments after all such excise taxes are paid would be greater than the reduced amount, the Company will pay the full amount due to Mr. Hill without any reductions.
The Hill Employment Agreement contains an affirmation that the terms of the restrictive covenant agreement dated September
1, 2008 are incorporated in the Hill Employment Agreement by reference. In addition, Mr. Hill will be required to repay any after-tax portion of this annual cash bonus received for any year in which he commits a willful and intentional act that directly results in a material restatement of the Company’s earnings. Amounts paid pursuant to the Hill Employment Agreement will also be subject to clawback by the Company to the extent necessary to comply with applicable law and/or any policy adopted by the Board of Directors of the Company.
Executive
Vice President and Chief Financial Officer
In connection with the appointment of Mr. Rauf as Executive Vice President and Chief Financial Officer, we entered into a letter agreement with Mr. Rauf effective December 11, 2008. Under the agreement, Mr. Rauf is entitled to a bi-weekly base salary of $18,269 (annualized at $475,000). In addition, Mr. Rauf is eligible to participate in the CIP, which provides for an annual cash target performance bonus equal to 90% of pro-rated annual base salary, with a maximum annual performance bonus opportunity of 200% of annual base salary. In December 2008, Mr. Rauf received, in accordance with his letter agreement, options to purchase 100,000 shares of common stock under the 2008 Equity Plan. These options have a ten-year term and vest ratably over a three-year period on the first, second and third anniversaries of the grant date. Mr. Rauf
is a Tier 3 participant under our Severance Plan which is described in more detail below under “Potential Payments Upon Termination or Change in Control — Change in Control and Severance Benefit Plan.”
W. Thaddeus Miller
Executive Vice President, Chief Legal Officer and Secretary
On December 18, 2015, we entered into an amended and restated employment agreement with Mr. Miller (the “Miller Employment Agreement”) which replaced the employment agreement between him and the Company dated August 11, 2008, as amended on December 21, 2012 and February
28, 2013. Mr. Miller continued to serve, pursuant to the Miller Employment Agreement as Executive Vice President and Chief Legal Officer through December 31, 2017 (the “Miller Employment Term”). The Miller Employment Agreement expired on December 31, 2017. Pursuant to a letter dated as of December 29, 2017 (the “Miller Letter Agreement”), following such expiration, Mr. Miller will continue to serve in his current role as an at-will employee. Mr. Miller will continue to receive his current annual base salary and be eligible for incentive compensation and employee benefits as were provided for in the Miller Employment Agreement described below and under the Company’s programs.
The
Miller Employment Agreement provided that Mr. Miller was entitled to receive an annual base salary during the Miller Employment Term of $829,242 (to be increased annually commensurate with pay increases made to other executive vice presidents of the Company) and an annual cash target performance bonus equal to 90% of annual base salary, with a maximum annual performance bonus opportunity of 200% of his base salary. Mr. Miller’s annual cash bonus awards for 2016 and 2017 were deemed earned as of December 31, 2016 and 2017, respectively, based on Mr. Miller’s continued employment on the applicable December 31st of such year. Such cash bonus awards were calculated and payable in a manner consistent with that of other executive vice presidents of the
Company. Mr. Miller will be required to repay any after-tax portion of this annual cash bonus received for any year in which he commits a willful and intentional act that directly results in a material restatement of our earnings.
The Miller Employment Agreement also provided for the grant of restricted stock awards and PSUs to Mr. Miller in February 2016 and February 2017 in a quantity to be calculated on the same basis as the annual grants made to other executive vice presidents of the Company. The restricted stock awards granted in February 2016 and February 2017 vested on December 31, 2016 and 2017, respectively, based on Mr. Miller’s continued employment through such dates. Similarly,
employment requirements on PSUs granted to Mr. Miller in February 2016 and February 2017 lapsed on December 31, 2016 and 2017, respectively.
Pursuant to the term of the Miller Employment Agreement, in the event that Mr. Miller’s employment was terminated by us without “cause” or if he resigns for “good reason” (each as defined in the Miller Employment Agreement), or if he remained employed through the end of the Miller Employment Term, the restricted stock would have, and did, immediately become fully vested, and any outstanding PSUs are no longer subject to continued service conditions and will be settled on their original payment dates in cash based on actual performance. If Mr. Miller’s employment was terminated by reason of disability or death, any PSUs
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and restricted stock would have immediately become fully vested, and the PSUs would have been settled following the termination date in cash based on performance at 100% target level. In the event that Mr. Miller’s employment was terminated by the Company for cause or by Mr. Miller without good reason, all of his unvested PSUs and restricted stock would have been forfeited.
In the event Mr. Miller was terminated by us without cause or if he had resigned for good reason, in each case during the Employment Term, in addition to the vesting of the equity-based awards described above, he would have also been entitled to certain severance payments and benefits, including (i) a prorated bonus for the year in
which such termination had occured, with such amount determined based on actual performance for such year relative to the performance goals applicable to Mr. Miller; (ii) a lump sum cash severance payment equal to 1.5 times the sum of (a) his highest base salary in the three years preceding termination and (b) his target bonus with respect to the year of termination; (iii) continuation of certain health and welfare benefits for a period of 18 months following the date of termination; and (iv) outplacement services for a period of up to 18 months following such termination. In the event Mr. Miller’s employment was terminated without cause or for good reason during the 24-month period following a change in control of the Company or within the six-month period following a potential change in control (provided a change in control had occurred within nine months following the potential change
in control), Mr. Miller generally would have been entitled to the same payments and benefits as set forth in the preceding sentence, except that the applicable severance multiplier would have been three instead of 1.5 and the provision of health and welfare benefits would have continued for a period of up to three years following such termination.
If any amounts payable under the Miller Employment Agreement would have become subject to the excise tax imposed by Code Section 4999, then such amounts would have been reduced so as not to become subject to such excise tax, but only if the net amount of such payments as so reduced would have been greater than or equal to the net amount of such payments without such reduction.
The Miller Employment Agreement also contained (i) non-solicitation covenants, which remain in effect during the Employment Term and for 12 months following termination
of employment, provided that such covenants will not apply following a change in control; (ii) a non-disparagement clause; and (iii) trade secrets, work product and post-termination cooperation clauses.
Following the expiration of the Miller Employment Agreement, pursuant to the Miller Letter Agreement, Mr. Miller will be entitled to separation benefits as a Tier 3 participant under the Severance Plan, which is described further below under “— Potential Payments Upon Termination or Change in Control — Change in Control Severance Benefits Plan”. The Miller Letter Agreement also provides that in the event Mr. Miller is terminated without “cause” or if he terminates his employment for “good reason” (as defined in the Severance Plan), he will be entitled to receive a pro-rated annual bonus for the year of termination, to be paid at the time his annual bonus would otherwise have been paid (but in no event later
than 60 days following the end of the calendar year in which his termination occurs), and shall be determined based on the Company’s actual performance for such year relative to the target performance goals applicable to Mr. Miller.
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Outstanding Equity Awards at Fiscal Year-End
The following table sets forth certain information concerning unexercised options, unvested stock and equity incentive plan awards outstanding as of December 31, 2017, for each named
executive officer:
Option Awards
Stock
Awards
Name
Number of Securities Underlying Unexercised Options (#)
Option Exercise Price ($)
Option Expiration Date
Number of Shares or Units of Stocks That Have Not Vested
Market
Value of Shares or Units of Stock That Have Not Vested(1)
Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested
Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested(1)
The amount listed in this column represents the product of the closing market price of the Company’s stock as of December 31, 2017 ($15.13) multiplied by the number of shares of stock subject to the award.
(2)
Granted on May 7, 2009 and vested 100% on the
third anniversary of the date of grant.
(3)
Granted on November 3, 2010 and vested 100% on the third anniversary of the date of grant.
(4)
Granted on February 15, 2017 and vests 100% on the third anniversary of the date of grant.
(5)
Granted
on May 16, 2017 and vests 100% on the third anniversary of the date of grant.
(6)
Granted on February 26, 2015 and vests ratably on each of the first three anniversaries of the date of grant.
(7)
Granted on February 22, 2016 and vests ratably on each of the first three anniversaries of the date of grant.
Granted on May 16, 2017 and vests ratably on each of the first three anniversaries of the date of grant.
(10)
Number of shares shown in the table is based on actual TSR performance
relative to the S&P 500 companies and represents the threshold award level. The actual number of shares earned (if any) will be based on TSR performance at the end of the applicable performance period. PSUs are settled in cash, in a range of 0% to 200%, following the Compensation Committee’s certification of performance. For Mr. Griggs, any cash payment in connection with these PSUs is not payable until June 1, 2018. See “Compensation Discussion and Analysis — Elements of Compensation — Long-Term Incentives” for further information on the settlement of the 2015 PSUs associated with the pending Merger.
(11)
Number of shares shown in the table is based on actual TSR performance relative
to the S&P 500 companies assuming a truncated performance measurement period of January 1, 2016 through December 31, 2017 and represents the threshold award level. The actual number of shares earned (if any) will be based on TSR performance at the end of the applicable performance period. Performance cycle concludes on December 31, 2018, and PSUs are settled in cash, in a range of 0% to 200%, following the Compensation Committee’s certification of performance. For Mr. Gates, any cash payment in connection with these PSUs is not payable until April 1, 2019. See “Compensation Discussion and Analysis — Elements of Compensation — Long-Term Incentives” for further information on the settlement of the 2016 PSUs associated with the pending Merger.
(12)
Number
of shares shown in the table is based on actual Calpine annualized TSR performance assuming a truncated performance measurement period of January 1, 2017 through December 31, 2017 and represents the maximum award level. The actual number of shares earned (if any) will be based on TSR performance at the end of the applicable performance period. Performance cycle concludes on December 31, 2019, and PSUs are settled in cash, in a range of 0% to 150%, following the Compensation Committee’s certification of performance. See “Compensation Discussion and Analysis — Elements of Compensation — Long-Term Incentives” for further information on the settlement of the February 2017 PSUs associated with the pending Merger.
(13)
Number
of shares shown in the table is based on actual Calpine annualized TSR performance assuming a truncated performance measurement period of May 16, 2017 through December 31, 2017 and represents the maximum award level. The actual number of shares earned (if any) will be based on TSR performance at the end of the applicable performance period. Performance cycle concludes on May 15, 2020, and PSUs are settled in cash, in a range of 0% to 150%, following the Compensation Committee’s certification of performance.
(14)
Granted on January 31, 2008 and vested
50% every 18 months from the date of grant.
Granted on June 1, 2015 and vests ratably on each of the first three anniversaries of the date of grant.
(22)
Granted on April 1, 2016 and vests ratably on each of the first three anniversaries of the date of grant.
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Option Exercises and Stock Vested
The following table provides information concerning vesting of stock awards during 2017 for each named executive officer (no option exercises took place in 2017 for our named executive officers):
Potential
Payments Upon Termination or Change in Control
Effective January 31, 2008, we adopted our Severance Plan, which provides eligible employees, including executive officers, whose employment is involuntarily terminated by us without “cause”, by the employee with “good reason” (each as defined in the Severance Plan), or in connection with a change in control, with certain severance benefits, including a lump sum payment based upon (i) the employee’s position and (ii) base salary and target bonus. In 2012, the Board approved an amendment to the Severance Plan, pursuant to which Tier 1, Tier 2 and Tier 3 participants will no longer be entitled to a gross-up payment in the event that any benefit or payment by the Company (whether paid or payable or distributed or distributable pursuant
to the terms of the Severance Plan or otherwise, including any acceleration of vesting or payment) is determined to be subject to the excise tax imposed by Code Section 4999. Effective November 4, 2013, the Board approved an amendment to and restatement of the Severance Plan that, among other things, provides for accelerated vesting of equity in the event of a change in control or a participant’s death or disability, entitles Tier 1 participants to a pro-rated annual cash bonus for a termination by the participant for good reason or by us without cause, and revises the requirements for participants to receive benefits for a termination in connection with a change in control. In addition, Mr. Hill has an agreement with us that provides for certain severance benefits as described below. The amount of compensation payable to each named executive officer in the event of a termination of employment, or a change in control,
on December 31, 2017, is described below under “— Quantification of Potential Payments Upon Termination or Change in Control.”
Change in Control and Severance Benefits Plan
Under the Severance Plan, amended and restated as of November 4, 2013, employees who are Senior Vice Presidents or above are eligible for certain post-employment benefits, which vary depending upon (i) the tier assigned to the employee and (ii) whether a change in control or termination of employment occurs. As of December 31, 2017, Messrs. Rauf, Griggs and Gates participated as Tier 3 participants in the Severance Plan. Any severance benefits for which Mr. Hill may be eligible would be provided under the Hill Employment Agreement and not under the Severance
Plan. Prior to December 31, 2017, any severance benefits for which Mr. Miller may be eligible would have been provided under the Miller Employment Agreement and not under the Severance Plan. Subsequent to December 31, 2017, Mr. Miller participated as Tier 3 participant in the Severance Plan.
Severance and Benefits in Connection with a Change in Control. With respect to each participant in the Severance Plan, upon the occurrence of a change in control, notwithstanding the provisions of any other benefit plan or agreement:
•
each outstanding option held by a participant shall become automatically
vested and exercisable;
•
options outstanding as of January 31, 2008, shall remain exercisable by such participant until the later of the 15th day of the third month following the date at which, or December 31 of the calendar year in which, the option would have otherwise expired, but in no event beyond the original term of such option;
•
options granted after January 31, 2008, shall remain exercisable by such participant
for a period of (i) three years in the case of a Tier 1 participant, (ii) two years in the case of a Tier 2 participant or (iii) one year in the case of a Tier 3 participant, beyond the date at which the option would have otherwise expired, but in no event beyond the original term of such option; and
•
the vesting restrictions on all other awards relating to common stock (including but not limited to restricted stock, restricted stock units and stock appreciation rights) held by a participant shall immediately lapse and in the case of restricted stock units and stock appreciation rights shall become immediately payable.
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•
each
PSU held by a participant will immediately be deemed fully earned, each stock appreciation right held by a participant will immediately vest, the restrictions on all other awards relating to common stock held by a participant will immediately lapse, and all such awards will be immediately payable.
In the event that a participant’s employment is terminated within 24 months following a change in control or within six months following a potential change in control (provided that a change in control occurs within nine months following such potential change in control) and upon the occurrence of a participant’s termination of employment by us without cause, or by such participant for good reason, then such participant (or his or her beneficiary) is entitled to receive, subject to certain conditions outlined in the Severance Plan:
•
a
lump sum payment within 60 days following termination in an amount equal to 2.99 times (in the case of a Tier 1, Tier 2 or Tier 3 participant) or 1.99 times (in the case of a Tier 4 participant) the sum of (i) the participant’s highest annual salary in the three years preceding the termination and (ii) the participant’s target bonus for the year of termination or for the year in which the change in control occurred, whichever is larger; plus
•
in the case of Tier 1 participants only, a pro-rated annual bonus for the year of termination, to be paid at such time as we pay annual bonuses generally; plus
•
a
lump sum payment for all “accrued obligations,” defined as all unused vacation time and all accrued but unpaid compensation earned by such participant as of the termination date, to be paid as soon as practicable following the termination date; and
•
continued coverage for the participant and his or her dependents under all health care, medical, dental and life insurance plans and programs (excluding disability) maintained by us under which the participant was covered immediately prior to his or her termination date, to be provided (concurrently with any health care benefit required under COBRA), in the case of a Tier 1, Tier 2 or Tier 3 participant, for a period of 36 months following termination, and, in the case of a Tier 4 participant,
for a period of 24 months following termination, at the same cost sharing between us and such participant as applies to a similarly situated active employee.
Severance and Benefits Not in Connection with a Change in Control. In the event that a participant’s employment is terminated by the participant for good reason or by us without cause, and not in connection with a change in control, as described above, then such participant (or his or her beneficiary) is entitled to receive, subject to certain conditions outlined in the Severance Plan:
•
In the case of a Tier 1 participant, (i) a lump sum payment within 60 days following termination in an amount equal to 2.0 times the sum
of (a) the participant’s highest annual salary in the three years preceding termination and (b) the participant’s highest target bonus for the year of termination; plus (ii) payment of all accrued obligations as soon as practicable following the termination date; plus (iii) a pro-rated annual bonus for the year of termination, to be paid at such time as we pay annual bonuses generally;
•
In the case of a Tier 2 or Tier 3 participant, (i) a lump sum payment within 60 days following termination in an amount equal to 1.5 times the sum of (a) the participant’s highest annual salary in the three years preceding termination and (b) the participant’s highest target bonus for the year of termination; plus (ii) payment of all accrued obligations as soon
as practicable following the termination date; and
•
In the case of a Tier 4 participant, (i) a lump sum payment within 60 days following termination in an amount equal to the sum of (a) the participant’s highest annual salary in the three years preceding termination and (b) the participant’s highest target bonus for the year of termination; plus (ii) payment of all accrued obligations as soon as practicable following the termination date.
In addition to the above, for a period of 24 months (Tier 1), 18 months (Tier 2 and Tier 3) or 12 months (Tier 4), following the termination date, the participant and his or her dependents shall receive continued health care benefits at the same
cost sharing between us and such participant as a similarly situated active employee, to be provided concurrently with any health care benefit required under COBRA.
Provisions Applicable Whether or Not Termination is in Connection with a Change in Control. In addition, participants entitled to benefits in connection with a severance or change in control are also entitled to receive outplacement benefits at our expense beginning on such participant’s termination date for a period of 24 months (Tier 1), 18 months (Tier 2 and Tier 3) or 12 months (Tier 4).
As a condition to receiving benefits under the Severance Plan, participants will be subject to certain conditions, including entering into non-solicitation, non-disclosure, non-disparagement and release agreements with us.
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Additional
Considerations. Tier 1, Tier 2 and Tier 3 participants are not entitled to a gross-up payment in the event that any benefit or payment by the Company (whether paid or payable or distributed or distributable pursuant to the terms of the Severance Plan or otherwise, including any acceleration of vesting or payment) is determined to be subject to the excise tax imposed by Code Section 4999. If any amounts will become subject to the excise tax imposed by Code Section 4999, then such amounts will be reduced so as not to become subject to such excise tax, but only if the net amount of such payments as so reduced is greater than or equal to the net amount of such payments without such reduction. A Tier 4 participant is not entitled to receive a gross-up payment under the Severance Plan, and any severance payments to a Tier 4 participant shall be reduced to the extent
necessary so that no portion of the severance payments is subject to the excise tax, but only if the net after-tax payments as so reduced are at least equal to the unreduced payments that the Tier 4 participant would have received after payment of all taxes, including the excise tax.
In the event of a participant’s death or disability, all stock options will vest and remain exercisable for the period set forth in the applicable plan or agreement, each PSU held by a participant will immediately be deemed fully earned, each stock appreciation right held by a participant will immediately vest, the restrictions on all other awards relating to common stock held by a participant will immediately lapse, and all such awards will be immediately payable.
If any participant is a “specified employee” under Section 409A of the IRC, any benefits to be paid or received under the Severance
Plan are to be delayed in accordance with the IRC.
Pursuant to the Hill Employment Agreement, described further above under “— Summary of Employment Agreements,” if Mr. Hill’s employment is terminated by us without cause or by his resignation for good reason, he will be entitled to certain severance payments and benefits, as follows:
•
a prorated bonus for the year in which such termination occurs;
•
a
lump sum cash severance payment equal to 2.0 times the sum of (i) his highest base salary in the three years preceding termination and (ii) his highest target bonus with respect to the year of termination;
•
a monthly payment for a period of 24 months following the date of termination equal to the full monthly premium paid by other former employees for continuation coverage under the Company’s health plans, as well as a tax gross-up on such payments;
•
outplacement
services for a period of up to 24 months following such termination; and
•
a time-based pro-rata portion of unvested equity and equity-based awards computed in accordance with the Hill Agreement.
In the event Mr. Hill’s employment terminates without cause or for good reason during the 24-month period following a change in control or within the six-month period following a potential change in control (provided a change in control occurs within nine months following the potential change in control), Mr. Hill generally will be entitled to the same payments and benefits as set forth above, except that the applicable severance multiplier in the second bullet point above will be 2.99 instead
of 2.0 and the provision of health and welfare benefits in the third bullet point above will continue for a period of up to three years following such termination.
In addition, with respect to the equity-based awards granted to Mr. Hill pursuant to the Hill Employment Agreement:
•
in the event of a change in control of the Company, all equity and equity-based awards outstanding and held by Mr. Hill as of such date will immediately vest, and all PSUs outstanding will be immediately settled based on the greater of the actual achievement of the applicable performance conditions and 100% of target, measured through the date immediately prior
to the change in control;
•
if Mr. Hill’s employment is terminated by us without cause or by him for good reason, a time-based pro-rata portion of all equity and equity-based awards will vest, and PSUs will vest based on actual performance for the full performance period, computed, in each case, in accordance with the Hill Employment Agreement;
•
if Mr. Hill’s employment terminates by reason of disability or death, all equity and equity-based awards will immediately become fully vested, and all PSUs will be deemed fully
earned at the target level and settled on the date of death or disability, as applicable; and
•
if either the Company or Mr. Hill provides the other party with notice of non-renewal of the Hill Employment Agreement at least six months prior to the end of the Hill Employment Agreement’s term and Mr. Hill’s employment terminates
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on the last day of the Hill Employment Agreement’s term, then upon such termination: (A) all stock options
and stock appreciation rights outstanding as of the last day of the term of the Hill Employment Agreement will continue to vest pursuant to their terms as if Mr. Hill were still employed through each remaining vesting date or the end of the performance period, as applicable, (B) any PSUs outstanding as of the last day of the term of the Hill Employment Agreement will continue to vest such that at the end of the applicable performance period, a number of PSUs will vest and become immediately payable equal to the number of PSUs that would have vested had Mr. Hill’s employment continued through the end of the applicable performance period, and (C) all restricted stock, restricted stock units, and other awards outstanding on the last day of the term of the Hill Employment Agreement and not addressed in the preceding clauses (A) or (B) will vest and be settled upon such termination of employment.
W. Thaddeus Miller
Pursuant
to our agreement with Mr. Miller, described further above under “— Summary of Employment Agreements,” if Mr. Miller was terminated by us without cause or if he resigned for good reason, he would have been entitled to certain severance payments and benefits, as follows:
•
a prorated bonus for the year in which such termination would have occurred;
•
a lump sum cash severance payment equal to 1.5 times the sum of (i) his highest base salary in the three years preceding termination and (ii) his target bonus with respect to the year
of termination;
•
continuation of certain health and welfare benefits for a period of 18 months following the date of termination; and
•
outplacement services for a period of up to 18 months following such termination.
In the event Mr. Miller’s employment was terminated without cause or for good reason during the 24-month period following a change in control or within the six-month period following a potential change in control (provided a change in control
would have occurred within nine months following the potential change in control), Mr. Miller generally would have been entitled to the same payments and benefits as set forth above, except that the applicable severance multiplier would have been three instead of 1.5 and the provision of health and welfare benefits and outplacement services would have continued for a period of up to three years following such termination.
In addition, with respect to the equity-based awards granted to Mr. Miller pursuant to the Miller Employment Agreement:
•
in the event of a change in control of the Company, the PSUs and the restricted stock would have
immediately become fully vested, and the PSUs would have been settled in accordance with the applicable award agreement;
•
if Mr. Miller’s employment was terminated by us without cause or by him for good reason or if he remained employed through the end of the Miller Employment Term, (i) the restricted stock units and stock options would have, and did, immediately become fully vested, and (ii) the PSUs are no longer subject to continued service conditions and will be settled on their original payment dates in cash based on actual performance during the relevant performance period;
•
if
Mr. Miller’s employment had terminated by reason of disability or death, the PSUs and restricted stock would have immediately become fully vested, and the PSUs would have been settled following the termination date in cash based on performance at 100% target level; and
•
if Mr. Miller’s employment was terminated by us for cause or by Mr. Miller without good reason, all of his unvested PSUs, stock options and restricted stock units would have been forfeited.
The Miller Employment Agreement expired pursuant to its terms on December 31, 2017. Following the expiration of the Miller Employment Agreement, pursuant to the Miller Letter Agreement,
Mr. Miller will be entitled to separation benefits as a Tier 3 participant under the Severance Plan, which is described further above under “— Potential Payments Upon Termination or Change in Control — Change in Control Severance Benefits Plan”. The Miller Letter Agreement also provides that in the event Mr. Miller is terminated without “cause” or if he terminates his employment for “good reason” (as defined in the Severance Plan), he will be entitled to receive a pro-rated annual bonus for the year of termination, to be paid at the time his annual bonus would otherwise have been paid (but in no event later than 60 days following the end of the calendar year in which his termination occurs), and shall be determined based on actual performance for such year relative to the target performance goals applicable to Mr. Miller.
Effect of Termination Events or Change in Control on Unvested Equity Awards
The
equity awards granted to our named executive officers through December 31, 2017, were granted under the Equity Plans. Unvested options issued under the Equity Plans terminate upon termination of employment and optionees generally have three months following termination of employment to exercise their vested options (unless the option terminates earlier pursuant to its terms). Unless otherwise set forth in an award agreement, unvested restricted stock is forfeited upon a termination of
90
employment. Unvested options and restricted stock fully vest upon a change in control. Amounts payable to each of our executive officers based on a termination event or a change in control are set forth below under “— Quantification
of Potential Payments Upon Termination or Change in Control.”
Quantification of Potential Payments Upon Termination or Change in Control
The following table sets forth potential benefits that each named executive officer would be entitled to receive in the event that the executive’s employment with us is terminated for any reason, including a termination for “cause”, resignation without “good reason” (each as defined in the Severance Plan, the Hill Employment Agreement and the Miller Employment Agreement, as applicable), a termination without cause, resignation with good reason, termination without cause or resignation with good reason in each case in connection with a change in control, change in control without termination, and death or disability. The amounts shown in the table are the
amounts that would have been payable under existing plans and arrangements if the named executive officer’s employment had terminated, and/or a change in control occurred on December 31, 2017. “Cash Compensation” includes payments of salary, bonus, non-equity annual incentive plan compensation, severance or death benefit amounts payable in the applicable scenario.
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The actual amounts that would be payable in these circumstances can only be determined at the time of the executive’s termination or a change in control and accordingly, may differ from the estimated amounts set forth in the table below:
Named
Executive Officer
Termination by Company for Cause or Resignation by Executive Without Good Reason
Termination by Company Without Cause
Resignation by Executive with Good Reason
Termination by Company Without Cause, or Resignation by Executive With Good Reason, in Connection with Change in Control
Amounts
disclosed in the table assume that no executive received any severance or termination benefit which would decrease the amount of the above payments, where applicable. These amounts would primarily be paid as a lump sum but have been calculated without any present-value discount and assuming that base pay would continue at 2017 rates.
(2)
Using generally accepted accounting principles for purposes of the Company’s financial statements, continued health and welfare benefits were valued at the amount of $2,522 per month (for family coverage) which applied to Messrs. Hill, Rauf and Griggs and $1,773 per month (for employee and spouse coverage) which applied to Messrs.
Miller and Gates. Outplacement services were valued at $50,000 for 18 months of coverage and $55,000 for 24 and 36 months of coverage.
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(3)
The value of unvested option awards represents the difference between the closing price on the NYSE of our common stock on December 31, 2017 ($15.13) and the exercise price of all unvested options that would vest upon the triggering event. In the event of a change in control, all unvested options will immediately vest in full, whether or not the executive’s employment terminates. In the
event of termination by Company without cause or resignation by executive with good reason other than in connection with a change in control, a pro-rata portion of Mr. Hill’s option awards will vest in accordance with the Hill Employment Agreement.
(4)
The value of unvested stock awards represents the closing price on the NYSE of our common stock on December 31, 2017 ($15.13), of all shares of restricted stock that would vest upon the triggering event. In the event of a change in control, all unvested stock awards will immediately vest in full, whether or not the executive’s employment terminates. In the event of termination by Company without cause or resignation by executive with good reason
other than in connection with a change in control, a pro-rata portion of Mr. Hill’s stock awards will vest in accordance with the Hill Employment Agreement.
(5)
The value of unvested PSUs represents the estimated payout value based on the closing price on the NYSE of our common stock on December 31, 2017 ($15.13). For Mr. Miller, in the event of termination by Company without cause or resignation by executive with good reason other than in connection with a change in control, the PSUs will no longer be subject to continued service conditions and will be settled in cash based on actual performance during the relevant performance period stipulated in the PSU agreement. In the event of death or disability,
the PSUs will be paid at target of 100% following the termination date. In the event of a change in control, all unvested PSUs will immediately vest in full, whether or not the executive’s employment terminates, with the payout value based on the greater of target value or actual performance over the truncated period. In the event of termination by Company without cause or resignation by executive with good reason other than in connection with a change in control, a pro-rata portion of Mr. Hill’s PSUs will vest in accordance with the Hill Employment Agreement.
Compensation and Risk
Our Compensation Committee regularly conducts risk assessments to determine the extent, if any, to which our compensation practices and programs may create incentives for excessive risk taking. Based on these reviews,
we believe that for the substantial majority of our employees the incentive for risk taking is low, because their compensation consists largely of fixed cash salary and a cash bonus that has a capped payout. Furthermore, the majority of these employees do not have the authority to take action on our behalf that could expose us to significant business risks.
In 2017, as part of its assessment, the Compensation Committee reviewed the compensation program for employees that engage in certain hedging and optimization activities. While these employees have increased potential for risk taking because a part of their compensation is linked to the profitability of these activities, the Compensation Committee concluded that the business risk from these activities is not significant because these employees’ activities are subject to controls that limit excessive risk taking, such as value-at-risk limits that are monitored and enforced
on a daily basis by our Chief Risk Officer.
The Compensation Committee also reviewed the cash and equity incentive programs for senior executives and concluded that certain aspects of the programs actually reduce the likelihood of excessive risk taking. These aspects include the use of long-term equity awards to create incentives for senior executives to work for long-term growth of the Company, including limited claw-back provisions contained in employment agreements limiting the incentive to take excessive risk for short-term gains by imposing caps on CIP bonuses, requiring compliance with our Code of Conduct and giving the Compensation Committee the power to reduce discretionary bonuses.
For these reasons, we do not believe that our compensation policies and practices create risks that are reasonably
likely to have a material adverse effect on us.
Pay Ratio Disclosure
At December 31, 2017, we had approximately 2,290 employees, with all of these individuals located in the United States. Our diverse employee population varies significantly in experience, education and specialized training. Regardless of the employee’s role in the organization or their location, the process for determining salaries is the same: local market competitive data is reviewed to set base pay rates. Individual salaries are then adjusted from these base pay rates to reflect the individual’s role and responsibilities as well as his or her experience, education, specialized training and overall performance.
We identified our median employee
for the year ended December 31, 2017, by reviewing compensation data reflected in our payroll records consisting of:
•
base salary,
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•
compensation under the annual incentive program or equivalent (calculated assuming payouts at the target level for employees hired in 2017 who were not eligible for an incentive payment
in 2017),
•
grant date fair value of equity and equity-based awards, and
•
employer contributions to the Company’s 401(k) Plan.
We identified our median employee using the above compensation data, which was consistently applied to all of our employees included in the calculation. We identified this payment information for all current full and part-time employees employed on
December 31, 2017; thus, we used December 31, 2017 as the measurement date in determining our median employee. Since all of our employees, as well as our President and Chief Executive Officer, are located in the United States, we did not make any cost of living adjustments in identifying the median employee. These results were then ranked, excluding the President and Chief Executive Officer, from lowest to highest, and the median employee was identified. Once we identified our median employee, we combined all of the elements of such employee’s total annual compensation in a manner consistent with total compensation for our NEOs, as presented in the “Summary Compensation Table”. With respect to total annual compensation for our President and Chief Executive Officer, we used the amount reported in the “Total” column of the “Summary Compensation Table”.
The total annual compensation for the year ended December 31, 2017 was $117,742 for our median employee and $6,775,636 for our President and Chief Executive Officer. The ratio of our President and Chief Executive Officer’s pay to that of our median employee for 2017 was approximately 57 times.
DIRECTOR COMPENSATION
The following table provides certain information concerning the compensation for services rendered in all capacities by each non-employee director serving on our Board for the year ended December 31, 2017:
The amounts set forth next to each award represent the aggregate grant date fair value of such awards computed in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718 (“FASB ASC Topic 718”). For discussion
of the assumptions used in these valuations, see Note 13 of the Notes to Consolidated Financial Statements. Represents 8,410 restricted stock units granted to each of Ms. Brlas and Messrs. Fusco, Hofmann, Merritt, Moreland and Mosbacher and 12,615 restricted stock units granted to Mr. Cassidy on May 10, 2017 pursuant to the 2008 Director Plan and 8,410 restricted stock units granted to Ms. O’Leary on May 10, 2017 pursuant to the 2008 Equity Plan, all vesting on the earlier to occur of the first anniversary date of the date of grant or the day immediately preceding the date of the 2018 annual meeting of shareholders. All such grants remained outstanding at December 31, 2017. In addition, the following members of the Board have elected to defer the distribution date of restricted stock units granted prior to 2017 and such
awards remain outstanding at December 31, 2017: Mr. Cassidy – 20,304 shares, Mr. Hofmann – 20,304 shares, Mr. Merritt – 26,671 shares and Ms. Brlas – 527 shares.
Our Corporate Governance Guidelines provide that compensation for our non-employee directors’ services may include annual cash retainers, shares of our common stock and options for such shares; meeting fees; fees for serving as a committee chairman; and fees for serving as a director of a subsidiary. We also reimburse directors for their reasonable out-of-pocket and travel expenses in connection with attendance at Board and committee meetings. Our Compensation Committee reviews director compensation annually and makes recommendations to the Board with respect to compensation and benefits provided to the members of the Board. Our Corporate Governance Guidelines provide that director compensation should
be fair and equitable to enable the Company to attract qualified members to serve on its Board.
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We had the following compensation structure for non-employee directors for 2017:
Annual Retainer
($)
Meeting Fees ($)
Restricted Stock Unit Award Value ($)
Committee Chair Retainer ($)
Outside Board Members
56,000
20,000
100,000(1)
—
Chairman
of the Board
100,000(2)
—
50,000(3)
—
Lead Director
25,000
—
—
—
Audit
Committee
—
14,000
—
20,000
Compensation Committee
—
14,000
—
10,000
Nominating
and Governance Committee
—
14,000
—
10,000
_____________________
(1)
Restricted stock units vest on the earlier to occur, the first anniversary of the date of grant or the day immediately
preceding the date of the next annual meeting of shareholders. Annual equity grants to non-employee directors are generally approved by the Board of Directors during its first meeting of the calendar year. All non-employee directors are generally eligible for annual equity awards granted pursuant to the 2008 Director Plan.
(2)
The independent Chairman of the Board receives this amount in addition to the annual retainer paid to independent outside board members.
(3)
The Chairman of the Board receives this additional amount
in the form of a grant of restricted stock units.
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Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The following table sets forth certain information known to the Company regarding the beneficial ownership
of its common stock as of February 14, 2018, by (i) each person known by the Company to be the beneficial owner of more than 5% of the outstanding shares of its common stock, (ii) each of our directors, (iii) each of our named executive officers and (iv) all of our executive officers and directors serving as a group. Unless otherwise stated, the address of each named executive officer and director is c/o Calpine Corporation, 717 Texas Avenue, Suite 1000, Houston, Texas77002.
Name
Common
Shares Beneficially Owned(1)
Shares Individuals Have the Right to Acquire Within 60 Days
Total Number of Shares Beneficially Owned(1)
Percent of Class
5% or Greater Shareholders
The
Vanguard Group(2)
30,901,060
—
30,901,060
8.6
%
Investment funds affiliated with Energy Capital Partners(3)
The
percentage of shares beneficially owned by such entity, director or named executive officer does not exceed one percent of the outstanding shares of common stock.
(1)
Beneficial ownership is determined in accordance with the rules of the SEC and consists of either or both voting or investment power with respect to securities. Shares of common stock issuable upon the exercise of options, warrants or rights or upon the conversion of convertible securities that are immediately exercisable or convertible or that will become exercisable or convertible within the next 60 days are deemed beneficially owned by the beneficial owner of such options, warrants or rights or convertible securities and are deemed outstanding for the purpose of computing the
percentage of shares beneficially owned by the person holding such instruments, but are not deemed outstanding for the purpose of computing the percentage of any other person. Except as otherwise indicated by footnote, and subject to community property laws where applicable, the persons named in the table have reported that they have sole voting and sole investment power with respect to all shares of common stock shown as beneficially owned by them. A total of 360,543,323 shares of common stock are considered to be outstanding on February 14, 2018, calculated pursuant to Rule 13d-3(d)(1)(i) under the Exchange Act.
(2)
According to Form 13G filed with the SEC on February
7, 2018, The Vanguard Group (“Vanguard”) possesses sole voting power over 192,019 shares, sole dispositive power over 30,690,734 shares, shared voting power over 43,800 shares and shared dispositive power over 210,326 shares. According to filings made with the SEC, the principal business address of Vanguard is 100 Vanguard Boulevard, Malvern, PA19355. Vanguard may have made additional transactions in our common
96
stock since its most recent filings with the
SEC. Accordingly, the information presented may not reflect all of the shares currently beneficially owned by Vanguard.
(3)
Volt Energy Holdings, LP (“Volt Energy”) is the record holder of the securities reported herein. ECP ControlCo, LLC is the sole managing member of Energy Capital Partners, which is the general partner of Energy Capital Partners GP III, LP (“ECP Fund GP”), which is the general partner of each of Energy Capital Partners III, LP, ECP III-A, Energy Capital Partners III-B (Volt IP), LP, Energy Capital Partners III-C, LP (collectively, the “ECP Funds”), which are the sole members of Volt Energy Holdings GP, LLC (“Volt GP”), which is the general partner of Volt Energy. Douglas Kimmelman, Thomas Lane, Andrew Singer, Peter
Labbat, Tyler Reeder and Rahman D’Argenio are the managing members of ECP ControlCo, LLC and share the power to vote and dispose of the securities beneficially owned by ECP ControlCo, LLC. As such, each of ECP ControlCo, LLC, Energy Capital Partners, ECP Fund GP, the ECP Funds, Volt GP, and Messrs. Kimmelman, Lane, Singer, Labbat, Reeder and D’Argenio may be deemed to have or share beneficial ownership of the shares of Calpine common stock held directly by Volt Energy. Each such entity or individual disclaims any such beneficial ownership. The principal business address of each of the entities and individuals listed in this footnote is 51 John F. Kennedy Parkway, Suite 200, Short Hills, NJ07078.
According to information in filings on Schedule 13D made with the SEC, each of BlackRock, Inc. (“BlackRock”) and Canadian Pension Plan Investment Board (“CPPIB”) may be deemed to have formed a “group” (within the meaning of Section 13(d)(3) of the Exchange Act) with Energy Capital Partners. Energy Capital Partners and its affiliates disclaim the existence of any such group and disclaim beneficial ownership of any securities beneficially owned by BlackRock or CPPIB.
(4)
According to Schedule 13D filed with the SEC on August 25, 2017, BlackRock possesses sole voting power over 14,181,952 shares and sole dispositive power over 15,776,301 shares. According to filings made with
the SEC, the principal business address of BlackRock is 55 East 52nd Street, New York, NY10055. BlackRock may have made additional transactions in our common stock since their most recent filings with the SEC. Accordingly, the information presented may not reflect all of the shares currently beneficially owned by BlackRock.
According to information in filings on Schedule 13D made with the SEC, BlackRock may be deemed to have formed a “group” (within the meaning of Section 13(d)(3) of the Exchange Act) with Energy Capital Partners. BlackRock and its affiliates disclaim the existence of any such group and disclaim beneficial ownership
of any securities beneficially owned by Energy Capital Partners.
(5)
According to Schedule 13D filed with the SEC on August 28, 2017, CPPIB possesses sole voting and dispositive power over 2,111,215 shares. According to filings made with the SEC, the principal business address of CPPIB is One Queen Street East, Suite 2500, Toronto, ON M5C 2W5 Canada. CPPIB may have made additional transactions in our common stock since their most recent filings with the SEC. Accordingly, the information presented may not reflect all of the shares currently beneficially owned by CPPIB.
According to information in filings on Schedule 13D made with the SEC, CPPIB may be
deemed to have formed a “group” (within the meaning of Section 13(d)(3) of the Exchange Act) with Energy Capital Partners. CPPIB and its affiliates disclaim the existence of any such group and disclaim beneficial ownership of any securities beneficially owned by Energy Capital Partners.
(6)
Of the total shares reported, Mr. Hill has the right to acquire 400,000 vested option shares consisting of 100,000 shares and 300,000 shares at exercise prices of $9.49 and $12.13 per share, respectively, and Mr. Hill has 126,973 unvested company restricted shares previously granted to him under the 2008 Equity Plan and the 2017 Equity Plan as to which Mr. Hill has voting but not dispositive power. Mr. Hill has 39,544 unvested restricted stock units previously granted
to him under the 2017 Equity Plan vesting on February 15, 2018.
(7)
Of the total shares reported, Mr. Rauf has the right to acquire 479,366 vested option shares (consisting of 21,700 shares, 100,000 shares, 69,963 shares, 149,431 shares and 138,272 shares at exercise prices of $18.38, $8.01, $11.24, $14.30 and $15.31 per share, respectively), and Mr. Rauf has 43,312 unvested company restricted shares previously granted to him under the 2008 Equity Plan as to which Mr. Rauf has voting but not dispositive power. Mr. Rauf has 14,601 unvested restricted stock units previously granted to him under the 2017 Equity Plan vesting on February 15, 2018.
(8)
Of
the total shares reported, 97,867 shares are held directly by Mr. Miller; 169,057 shares are owned by grantor retained annuity trusts and may be deemed to be beneficially owned by Mr. Miller as the sole recipient of the annuity payments and the trustee of such trusts; and 107,891 shares are owned by separate trusts of which Mr. Miller’s children are respective beneficiaries and Mr. Miller and his spouse serve as trustees, and therefore may be deemed to be indirectly beneficially owned by Mr. Miller. Of the total shares reported, Mr. Miller has the right to acquire 246,996 vested option shares consisting of 100,000 shares and146,996 shares at an exercise price of $9.49 and $11.69 per share, respectively, pursuant to the 2008 Equity Plan.
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(9)
Of
the total shares reported, Mr. Griggs has 36,091 unvested company restricted shares previously granted to him under the 2008 Equity Plan as to which Mr. Griggs has voting but not dispositive power. Mr. Griggs has 11,983 unvested restricted stock units previously granted to him under the 2017 Equity Plan vesting on February 15, 2018.
(10)
Of the total shares reported, Mr. Gates has 19,900 unvested company restricted shares previously granted to him under the 2008 Equity Plan as to which Mr. Gates has voting but not dispositive power. Mr. Gates has 10,755 unvested restricted stock units previously granted to him under the 2017 Equity Plan vesting on February
15, 2018.
(11)
On August 10, 2016, Ms. Brlas received an award of 5,995 company restricted stock units pursuant to the 2008 Equity Plan, vesting on May 9, 2017, in connection with her appointment as a member of the Board. Ms. Brlas elected to defer the distribution date of 527 company restricted stock units to her termination of service on the Board or a “Change in Control” as defined in her restricted stock unit agreement.
(12)
On
May 19, 2010, each non-employee member of the Board received an award of 6,367 company restricted stock units pursuant to the 2008 Director Plan, vesting on May 10, 2011. Mr. Merritt elected to defer the distribution date of such restricted stock units to May 19, 2020. On May 10, 2013, each non-employee member of the Board received an award of 4,362 company restricted stock units pursuant to the 2008 Director Plan, vesting on May 10, 2014. Mr. Cassidy elected to defer the distribution date of such company restricted stock units to September 7, 2022, Mr. Merritt elected to defer the distribution date of such restricted stock units to May
19, 2020 and Mr. Hofmann elected to defer the distribution date of such company restricted stock units to his termination of service on the Board or a “Change in Control” as defined in the Restricted Stock Unit Agreement. On May 14, 2014, each non-employee member of the Board received an award of 4,452 company restricted stock units pursuant to the 2008 Director Plan, vesting on May 12, 2015. Mr. Cassidy elected to defer the distribution date of such company restricted stock units to September 7, 2018, and Messrs. Hofmann and Merritt elected to defer the distribution date of such company restricted stock units to their termination of service on the Board or a “Change in Control” as defined in the Restricted Stock Unit Agreement. On May 13, 2015, each non-employee
member of the Board received an award of 4,837 company restricted stock units pursuant to the 2008 Director Plan, vesting on May 10, 2016. Mr. Cassidy elected to defer the distribution date of such company restricted stock units to September 7, 2019, and Messrs. Hofmann and Merritt elected to defer the distribution date of such company restricted stock units to their termination of service on the Board or a “Change in Control” as defined in the Restricted Stock Unit Agreement. On May 11, 2016, each non-employee member of the Board received an award of 6,653 company restricted stock units pursuant to the 2008 Director Plan, vesting on May 9, 2017. Messrs. Cassidy, Hofmann and Merritt elected to defer the distribution date of such company restricted stock units to their
termination of service on the Board or a “Change in Control” as defined in the Restricted Stock Unit Agreement. All company restricted stock units awarded to our directors will be automatically distributed on their elected distribution dates, subject to an earlier distribution upon termination of the director’s service on the Board or a “Change in Control” as defined in the Restricted Stock Unit Agreement.
(13)
Of the total shares reported, 20,000 shares are held under The Michael W. and Lisa S. Hofmann Revocable Trust and are deemed to be beneficially owned by Mr. Hofmann as co-trustee along with Lisa S. Hofmann, his spouse.
(14)
Mr.
Fusco has the right to acquire 300,000 vested option shares at an exercise price of $9.49 per share pursuant to the 2008 Equity Plan.
Securities Authorized for Issuance under Equity Compensation Plans
See “Compensation Discussion and Analysis — Details of Each Element of Compensation — Annual Incentive — Calpine Incentive Plan” and Note 13 of the Notes to Consolidated Financial Statements for a discussion of the equity incentive plans.
Equity Compensation Plans Table
The following table shows information relating to the number of shares authorized for issuance under our equity compensation plans as of December 31, 2017:
Number of Securities to be issued upon exercise of outstanding options, warrants and rights
Weighted average exercise price of outstanding
options, warrants
and rights
Number of securities remaining available
for future issuance
under equity
compensation plans
Equity
compensation plans
Approved by shareholders
10,176,315
(1)(2)
$
13.45
22,165,106
(3)
_________________
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(1)
Includes 9,115,251 shares subject to outstanding awards granted under the 2008 Equity Plan, of which 4,093,583 shares were subject to outstanding options, 5,012,731 shares were subject to outstanding shares of restricted stock and 8,937 shares were subject to outstanding restricted stock unit awards, and 930,710 shares subject to outstanding awards granted under the 2017 Equity Plan, of which 15,571 shares were subject to outstanding options, 18,730 shares were subject to outstanding shares of restricted stock and 896,409 shares were subject to outstanding restricted stock unit awards, and 130,354 shares subject to outstanding restricted stock unit awards under
the 2008 Director Plan.
(2)
The weighted average remaining term for the expiration of stock options is 4.5 years.
(3)
Represents available shares for future issuance of 21,865,106 shares under the 2017 Equity Plan and 300,000 shares under the 2017 Director Plan.
Item
13.
Certain Relationships and Related Transactions, and Director Independence
Certain Relationships and Related Transactions
See “Executive Compensation — Summary of Employment Agreements” for a description of employment agreements between us and certain of the named executive officers.
In February 2017, one of our retail affiliates, Calpine Energy Solutions, LLC, entered into an agreement with two subsidiaries of Cheniere Energy, Inc. (“Cheniere”) to provide retail electricity to Cheniere’s liquefied natural gas facility in Corpus Christi, Texas for a period of approximately five years. The consideration associated with the agreement will be variable based
on electricity usage but is expected to be between approximately $90 million and $110 million over the term of the agreement. Mr. Fusco, a director of Calpine, serves as President and Chief Executive Officer of Cheniere where he also is a member of the board of directors.
As required pursuant to our related persons transactions policy, the Audit Committee reviewed the transaction, determined that it is in the best interest of the Company and recommended that the Board approve the transaction. In making its determination, the Audit Committee considered relevant material facts and circumstances concerning the transaction, including the fact that Mr. Fusco’s interest in the transaction arises solely as a result of his position as a director of the Company and
an executive officer and a member of the board of Cheniere as well as the fact that the agreement is not material to Calpine. Upon receipt of the Audit Committee’s recommendation, the Board approved the agreement with Cheniere as required under our related persons transaction policy. Mr. Fusco did not participate in the negotiation of the agreement or in the Board’s approval of the transaction.
Other than the transaction described above, there were no transactions to be disclosed in which we were a participant and the amount involved exceeded $120,000 and in which any related person, including our executives and directors, had or will have a direct or indirect material interest.
Business Relationships and Related Person Transactions Policy
We have adopted a written policy regarding approval requirements for related person transactions. Under
our related person transactions policy, our Chief Legal Officer is primarily responsible for the development and implementation of processes and controls to obtain information from the directors and executive officers with respect to related person transactions and for then determining, based on the relevant facts and circumstances, whether a related person has a direct or indirect material interest in the transaction. Under our policy, transactions (i) that involve directors, director nominees, executive officers, significant shareholders or other “related persons” in which the Company is or will be a participant and (ii) of the type that must be disclosed under the SEC’s rules must be referred by the Chief Legal Officer to our Audit Committee for the purpose of determining whether such transactions are in the best interests of the
Company. Under our policy, it is the responsibility of the individual directors, director nominees, executive officers and holders of five percent or more of the Company’s common stock to promptly report to our Chief Legal Officer all proposed or existing transactions in which the Company and they, or any related person of theirs, are parties or participants. The Chief Legal Officer (or the Chief Executive Officer, in the event the transaction in question involves the Chief Legal Officer or a related person of the Chief Legal Officer) is then required to furnish to the Chairman of the Audit Committee reports relating to any transaction that, in the Chief Legal Officer’s judgment, may require reporting pursuant to the SEC’s rules or may otherwise be the type of transaction that should be brought to
the attention of the Audit Committee. The Audit Committee considers material facts and circumstances concerning the transaction in question, consults with counsel and other advisors as it deems advisable and makes a determination or recommendation to the Board of Directors and appropriate officers of the Company with respect to the transaction in question. In its review, the Audit Committee considers the nature of the related person’s interest in the transaction, the material terms of the transaction, the relative importance of the transaction to the related person, the relative importance of the transaction to the Company and any other matters deemed important or relevant. Upon receipt of the Audit Committee’s recommendation, the Board of Directors or officers take such action as deemed appropriate
in light of their respective responsibilities under applicable laws and regulations.
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Director Independence
Our independent directors are: Mary L. Brlas, Frank Cassidy, Michael W. Hofmann, David C. Merritt, W. Benjamin Moreland, Robert A. Mosbacher, Jr. and Denise
M. O’Leary. Therefore, the Board has satisfied its objective as set forth in the Corporate Governance Guidelines to have at least two-thirds of the Board consist of independent directors, as well as NYSE listing standards requiring that at least a majority of the Board consist of independent directors.
For a director to be considered independent, the Board must determine that the director does not have any direct or indirect material relationship with us. The Board considers the following transactions, relationships and arrangements in determining director independence in accordance with our Corporate Governance Guidelines. Under these guidelines, a member of the Board of Directors may be considered independent if such member:
•
has
not been employed by the Company within the last three years (other than as interim Chairman of the Board of Directors or interim Chief Executive Officer);
•
does not have an immediate family member who is, or has been, employed by the Company as an executive officer within the last three years;
•
has not received, and does not have an immediate family
member who has received, more than $120,000 in direct compensation from the Company during any twelve-month period within the last three years, other than for services as a member of the Board of Directors or compensation for prior service (including pension or other forms of deferred compensation for prior service, provided such compensation is not contingent in any way on continued service); provided that, compensation received by a director for former service as an interim Chairman or Chief Executive Officer or other executive officer need not be considered in determining independence under this test; provided further that, compensation received by an immediate family member for service as an employee of the Company (other than an executive officer) need not be considered in determining independence
under this test;
•
(i) is not a current partner or employee of a firm that is the Company’s internal or external auditor; (ii) does not have an immediate family member who is a current partner of a firm that is the Company’s internal or external auditor; (iii) does not have an immediate family member who is a current employee of a firm that is the Company’s internal or external auditor and personally works on the
Company’s audit; and (iv) is not, and has not been within the last three years, and does not have an immediate family member who is, or has been within the last three years, a partner or employee of a firm that is the Company’s internal or external auditor and personally worked on Company’s audit within such time;
•
is not, and has not been within the last three years, and does not have an immediate family member who is, or has been within the last three years, employed as an executive officer of a public company where any of the Company’s present executive officers at the
same time serves or served as a member of such public company’s compensation committee;
•
is not, and has not been within the last three years, an employee of a significant customer or supplier of the Company, including any company that has made payments to, or received payments from, the Company for property or services in an amount which, in any of the last three fiscal years, exceeds the greater of $1 million, or 2% of such other company’s consolidated gross revenues, and does not have an immediate family member who is, or has been within the last three years, an executive
officer of such a significant customer or supplier; provided that contributions to not- for-profit organizations shall not be considered payments for purposes of this test;
•
has not had any of the relationships described above with any affiliate of the Company; and
•
has no other material relationship, which, in the business judgment of the Board of Directors, would impair his or her ability to exercise independent judgment.
Notwithstanding
the foregoing, each member of the Board of Directors must meet any mandatory qualifications for membership on the Board, and the Board as a whole must meet the minimum independence requirements imposed by any exchange or market on which our common stock is listed and any other laws and regulations applicable to us. Each member of the Board of Directors is required to promptly advise the Chairman of the Board (or the Lead Director if one has been appointed) and the Nominating and Governance Committee of any matters which, at any time, may affect such member’s qualifications for membership under the criteria imposed by any applicable exchange or market, any other laws and regulations or these guidelines, including such member’s independence.
100
In reaching its
determinations, the Board reviewed the categorical standards listed above, the corporate governance rules of the NYSE and the individual circumstances of each director and determined that each of the directors identified above as independent satisfied each standard.
Item 14.
Principal Accounting Fees and Services
Audit Fees
The following table presents fees for professional services rendered by PwC for the years ended December 31, 2017 and 2016,
respectively. PwC did not bill us for other services during those periods.
2017
2016
(in millions)
Audit Fees(1)(2)
$
6.6
$
6.2
_______________
(1)
Our
Audit fees consisted of approximately $5.5 million and $5.2 million for the audits and quarterly reviews of our consolidated financial statements, registration statements and offerings for Calpine Corporation for 2017 and 2016, respectively, and fees of approximately $1.1 million and $1.0 million for 2017 and 2016, respectively, which were billed for performing audits and reviews of certain of our subsidiaries.
(2)
PwC did not provide us with any material tax consulting services for the years ended December 31, 2017 and 2016.
Audit
Committee Pre-Approval Policies and Procedures
All audit and non-audit services provided by our independent registered public accounting firm must be pre-approved by our Audit Committee. Any service proposals submitted by our independent registered public accounting firm need to be discussed and approved by the Audit Committee during its meetings, which take place at least four times a year. Once a proposed service is approved, we or our subsidiaries formalize the engagement of the service. The approval of any audit and non-audit services to be provided by our independent registered public accounting firm is specified in the minutes of our Audit Committee meetings. In addition, the members of our Board of Directors are briefed on matters discussed by the different Committees of our Board.
Findings of Fact, Conclusions of Law, and Order Confirming Sixth Amended Joint
Plan of Reorganization Pursuant to Chapter 11 of the U.S. Bankruptcy Code (incorporated by reference to Exhibit 2.2 to Calpine’s Current Report on Form 8-K, filed with the SEC on December 27, 2007, File No. 001-12079).
Indenture,
dated January 14, 2011, among Calpine Corporation, the guarantors party thereto and Wilmington Trust Company, as trustee, including the form of the 7.875% senior secured notes due 2023 (incorporated by reference to Exhibit 4.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on January 14 , 2011, File No. 001-12079).
First
Supplemental Indenture dated as of April 26, 2011, among each of New Development Holdings, LLC, Calpine Mid-Atlantic Energy, LLC, Calpine Mid-Atlantic Operating, LLC, Calpine Bethlehem, LLC, Calpine New Jersey Generation, LLC, Calpine Mid-Atlantic Generation, LLC, Calpine Solar, LLC, Calpine Vineland Solar, LLC and Calpine Mid-Atlantic Marketing, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of January 14, 2011, providing for the issuance of 7.875% senior secured notes due 2023 (incorporated by reference to Exhibit 4.6 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended March
31, 2011, filed with the SEC on April 29, 2011, File No. 001-12079).
Second Supplemental Indenture dated as of July 22, 2011, among each of Deer Park Energy Center
LLC, Deer Park Holdings, LLC, Metcalf Energy Center, LLC, Metcalf Holdings, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of January 14, 2011, providing for the issuance of 7.875% senior secured notes due 2023 (incorporated by reference to Exhibit 4.5 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, filed with the SEC on July 29, 2011, File No. 001-12079).
Third
Supplemental Indenture dated as of August 20, 2012, among each of Calpine Energy Services GP, LLC and Calpine Energy Services LP, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of January 14, 2011, providing for the issuance of 7.875% senior secured notes due 2023 (incorporated by reference to Exhibit 4.5 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, filed with the SEC on November 6, 2012, File No. 001-12079).
Fourth
Supplemental Indenture dated as of November 26, 2012, among each of South Point Holdings, LLC, South Point Energy Center, LLC, Broad River Energy LLC, South Point OL-1, LLC, South Point OL-2, LLC, South Point OL-3, LLC, South Point OL-4, LLC, Broad River OL-1, LLC, Broad River OL-2, LLC, Broad River OL-3, LLC and Broad River OL-4, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of January 14, 2011, providing for the issuance of 7.875% senior secured notes due 2023 (incorporated by reference to Exhibit 4.28 to Calpine’s Annual Report on Form 10-K for the year ended December
31, 2012, filed with the SEC on February 13, 2013, File No. 001-12079).
Indenture dated as of October 31, 2013, for the senior secured notes due 2022
among each of Calpine Corporation, the guarantors party thereto and Wilmington Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on October 31, 2013).
Indenture
dated as of October 31, 2013, for the senior secured notes due 2024 among each of Calpine Corporation, the guarantors party thereto and Wilmington Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.2 to Calpine’s Current Report on Form 8-K, filed with the SEC on October 31, 2013).
Indenture, dated as of May 31, 2016,
for the senior secured notes due 2026 among each of the Company, the guarantors party thereto and Wilmington Trust, National Association, as trustee (the “Trustee”) (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed with the SEC on June 1, 2016).
Credit Agreement, dated as of December 10, 2010, among Calpine Corporation, Goldman Sachs Bank USA, as administrative agent, Goldman Sachs Credit Partners L.P., as collateral agent, the lenders party thereto and other parties thereto (incorporated by reference to Exhibit 10.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on December
13, 2010, File No. 001-12079).
Credit
Agreement, dated May 3, 2013 among Calpine Construction Finance Company as borrower and the lenders party thereto, and Goldman Sachs Lending Partners, LLC (“GSLP”) as administrative agent and as collateral agent, CoBank ACB, ING Capital LLC., Royal Bank of Canada, and The Royal Bank of Scotland PLC as co-documentation agents, GSLP, Deutsche Bank Securities Inc., Credit Suisse Securities (USA) LLC, Merrill Lynch, Pierce Fenner and Smith Incorporated and Union Bank, N.A., as joint lead arrangers, joint bookrunners and co-syndication agents, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed with the SEC on May 3, 2013).
Amendment
No. 1 to the December 10, 2010 Credit Agreement, dated as of June 27, 2013, among Calpine Corporation, as borrower, Goldman Sachs Bank USA, as administrative agent, Goldman Sachs Credit Partners L.P., as collateral agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed with the SEC on July 1, 2013).
Amendment
to the Credit Agreement, dated February 20, 2014, among Calpine Construction Finance Company, L.P. as borrower and the lenders party thereto, and Goldman Sachs Lending Partners, LLC (“GSLP”) as administrative agent and as collateral agent, CoBank ACB, ING Capital LLC., Royal Bank of Canada, and The Royal Bank of Scotland PLC as co-documentation agents, GSLP, Deutsche Bank Securities Inc., Credit Suisse Securities (USA) LLC, Merrill Lynch, Pierce Fenner and Smith Incorporated and Union Bank, N.A., as joint lead arrangers, joint bookrunners and co-syndication agents, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, filed with the SEC on May 1, 2014).
Incremental
Term B-2 Loan Commitment Supplement to the Credit Agreement, dated February 26, 2014, among Calpine Construction Finance Company, L.P. as borrower and the lenders party thereto, and Goldman Sachs Lending Partners, LLC as administrative agent and as collateral agent under the Credit Agreement, dated as of May 3, 2013 and as amended on February 20, 2014 (incorporated by reference to Exhibit 10.2 to the Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, filed with the SEC on May 1, 2014).
Amendment No. 2 to the Credit Agreement, dated as of July
30, 2014, among Calpine Corporation, as borrower, Goldman Sachs Bank USA, as administrative agent, Goldman Sachs Credit Partners L.P., as collateral agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on July 31, 2014).
Credit
Agreement, dated as of May 28, 2015 among Calpine Corporation, as borrower, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent, Goldman Sachs Credit Partners L.P., as collateral agent, and Goldman Sachs Bank USA, MUFG Union Bank, N.A., Barclays Bank Plc and Royal Bank of Canada, as co-documentation agents (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on May 28, 2015).
Credit
Agreement, 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 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on December 18, 2015).
Amendment No. 3 to the Credit Agreement,
dated as of February 8, 2016, among Calpine Corporation, as borrower, the guarantors party thereto, Goldman Sachs Bank USA, as administrative agent, Goldman Sachs Credit Partners L.P., as collateral agent, The Bank of Tokyo-Mitsubishi UFJ Ltd, as successor administrative agent, MUFG Union Bank, N.A., as successor collateral agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1.19 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2015, filed with the SEC on February 12, 2016).
Credit
Agreement, dated May 31, 2016 among Calpine Corporation, as borrower, the lenders party thereto, Citibank, N.A., as administrative agent, MUFG Union Bank, N.A., as collateral agent (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on June 1, 2016).
Credit
Agreement, dated December 1, 2016 among Calpine Corporation, as borrower, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent, MUFG Union Bank, N.A., as collateral agent (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on December 2, 2016).
Amendment
No. 4 to the Credit Agreement, dated as of December 1, 2016, among Calpine Corporation, as borrower, the guarantors party thereto, Goldman Sachs Bank USA, as administrative agent, Goldman Sachs Credit Partners L.P., as collateral agent, The Bank of Tokyo-Mitsubishi UFJ Ltd, as successor administrative agent, MUFG Union Bank, N.A., as successor collateral agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on December 2, 2016).
Amendment
No. 1 to Credit Agreement, dated as of December 21, 2016, among Calpine Corporation, as borrower, the guarantors, Credit Suisse AG, as the initial new lender and Morgan Stanley Senior Funding, Inc., as administrative agent, and amends the Credit Agreement dated as of May 28, 2015 entered into among the borrower, the institutions from time to time party thereto as lenders, the administrative agent and MUFG Union Bank, N.A., as collateral agent (incorporated by reference to Exhibit 10.1.18 to the Calpine’s Annual Report on Form 10-K for the year ended December 31, 2016, filed with the SEC on February 10, 2017).
Amendment
No. 1 to Credit Agreement, dated as of December 21, 2016, among Calpine Corporation, as borrower, the guarantors, Credit Suisse AG, as the initial new lender and Morgan Stanley Senior Funding, Inc., as administrative agent, and amends the Credit Agreement dated as of December 15, 2015 entered into among the borrower, the institutions from time to time party thereto as lenders, the administrative agent and MUFG Union Bank, N.A., as collateral agent (incorporated by reference to Exhibit 10.1.19 to the Calpine’s Annual Report on Form 10-K for the year ended December 31, 2016, filed with the SEC on February 10, 2017).
Amendment
No. 1 to Credit Agreement, dated as of December 21, 2016, among Calpine Corporation, as borrower, the guarantors, Credit Suisse AG, as the initial new lender and Citibank, N.A., as administrative agent, and amends the Credit Agreement dated as of May 31, 2016 entered into among the borrower, the institutions from time to time party thereto as lenders, the administrative agent and MUFG Union Bank, N.A., as collateral agent (incorporated by reference to Exhibit 10.1.20 to the Calpine’s Annual Report on Form 10-K for the year ended December 31, 2016, filed with the SEC on February 10, 2017).
Credit
Agreement, dated February 3, 2017 among Calpine Corporation as borrower and the lenders party thereto, and Morgan Stanley Senior Funding, Inc., as administrative agent, MUFG Union Bank, N.A., as collateral agent (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on February 9, 2017).
Amendment
No. 5 to the Credit Agreement, dated as of September 15, 2017, among Calpine Corporation, as borrower, the guarantors party thereto, The Bank of Tokyo-Mitsubishi UFJ Ltd, as administrative agent, MUFG Union Bank, N.A., as collateral agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on September 20, 2017).
Amendment
No. 6 to the Credit Agreement, dated as of October 20, 2017, among the Company, as borrower, the guarantors party thereto, The Bank of Tokyo-Mitsubishi UFJ Ltd, as administrative agent, MUFG Union Bank, N.A., as collateral agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on October 26, 2017).
Credit
Agreement, dated December 15, 2017 among CCFC as borrower, the lenders party hereto, and Credit Suisse AG, Cayman Islands Branch, as administrative agent and collateral agent (incorporated by reference to Exhibit 10.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on December 18, 2017).
Restricted
Stock Agreement Pursuant to the Amended and Restated 2008 Equity Incentive Plan, dated May 13, 2014 among John B. (Thad) Hill and Calpine Corporation (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 15, 2014).†
Calpine
Corporation 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on May 10, 2017). †
Form of Non-Qualified Stock Option Agreement (Pursuant to the 2008 Equity Incentive Plan) (incorporated by reference to Exhibit 10.4.3
to Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, filed with the SEC on May 12, 2008, File No. 001-12079).†
Amended and Restated Calpine Corporation 2008 Director Incentive Plan (incorporated
by reference to Annex A to Calpine’s Definitive Proxy Statement on Schedule 14A filed with the SEC on April 5, 2010, File No. 001-12079).†
Calpine Corporation Equity Compensation Plan for Non-Employee Directors (incorporated by reference to Exhibit 10.2 to Calpine’s Current Report on Form 8-K, filed with the SEC on May 10, 2017). †
Calpine
Corporation Amended and Restated Change in Control and Severance Benefits Plan (incorporated by reference to Exhibit 10.2.8 to the Calpine’s Annual Report on Form 10-K for the year ended December 31, 2016, filed with the SEC on February 10, 2017).†
Form
of Performance Share Unit Award Agreement between the Company and Jack A. Fusco and W. Thaddeus Miller (Pursuant to the Amended and Restated Calpine Corporation 2008 Equity Incentive Plan, dated February 26, 2014) (incorporated by reference to Exhibit 10.6 to the Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, filed with the SEC on May 1, 2014). †
Form
of Performance Share Unit Award Agreement Under Amended and Restated Calpine Corporation 2008 Equity Incentive Plan between the Company and W. Thaddeus Miller (incorporated by reference to Exhibit 10.1 to the Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, filed with the SEC on April 29, 2016). †
Form
of Performance Share Unit Award Agreement Under Amended and Restated Calpine Corporation 2008 Equity Incentive Plan between the Company and Certain Designated Senior Employees (incorporated by reference to Exhibit 10.2 to the Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, filed with the SEC on April 29, 2016). †
Form
of Performance Share Unit Award Agreement Under Amended and Restated Calpine Corporation 2008 Equity Incentive Plan between the Company and Certain Designated Senior Employees (incorporated by reference to Exhibit 10.2.14 to the Calpine’s Annual Report on Form 10-K for the year ended December 31, 2016, filed with the SEC on February 10, 2017). †
Form
of Performance Share Unit Award Agreement Under Amended and Restated Calpine Corporation 2008 Equity Incentive Plan between the Company and W. Thaddeus Miller (incorporated by reference to Exhibit 10.2.15 to the Calpine’s Annual Report on Form 10-K for the year ended December 31, 2016, filed with the SEC on February 10, 2017). †
Form
of Performance Share Unit Award Agreement Under Amended and Restated Calpine Corporation 2008 Equity Incentive Plan between the Company and W. Thaddeus Miller (incorporated by reference to Exhibit 10.2 to the Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, filed with the SEC on April 28, 2017). †
Form
of Performance Share Unit Award Agreement Under Amended and Restated Calpine Corporation 2008 Equity Incentive Plan between the Company and Certain Designated Senior Employees (incorporated by reference to Exhibit 10.3 to the Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, filed with the SEC on April 28, 2017). †
Form
of Non-qualified Stock Option Agreement Under Amended and Restated Calpine Corporation 2008 Equity Incentive Plan between the Company and W. Thaddeus Miller (incorporated by reference to Exhibit 10.4 to the Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, filed with the SEC on April 28, 2017). †
Form
of Non-qualified Stock Option Agreement Under Amended and Restated Calpine Corporation 2008 Equity Incentive Plan between the Company and Certain Designated Senior Employees (incorporated by reference to Exhibit 10.5 to the Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, filed with the SEC on April 28, 2017). †
Form
of Non-qualified Stock Option Agreement Under Amended and Restated Calpine Corporation 2008 Equity Incentive Plan between the Company and Charlie M. Gates (incorporated by reference to Exhibit 10.6 to the Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, filed with the SEC on April 28, 2017). †
Form of Restricted Stock Unit Award Agreement Under Amended and Restated
Calpine Corporation 2017 Equity Incentive Plan between the Company and W. Thaddeus Miller (incorporated by reference to Exhibit 10.1 to the Calpine’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2017, filed with the SEC on July 28, 2017). †
Form
of Restricted Stock Unit Award Agreement Under Amended and Restated Calpine Corporation 2017 Equity Incentive Plan between the Company and Certain Designated Senior Employees (incorporated by reference to Exhibit 10.2 to the Calpine’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2017, filed with the SEC on July 28, 2017). †
Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.‡
Management contract or compensatory plan, contract or arrangement.
Item 16. Form 10-K Summary
None.
108
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Report of Independent Registered Public Accounting Firm
To
the Board of Directors
and Stockholders of Calpine Corporation
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Calpine Corporation and its subsidiaries as of December 31, 2017 and 2016, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2017, including the related notes and financial
statement schedule listed in the index appearing under Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December
31, 2017 and 2016, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2017 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Change in Accounting Principle
As
discussed in Note 3 to the consolidated financial statements, in 2017 the Company elected to change its method of accounting to move from a gross basis of presentation to a net basis for presenting qualifying derivative assets and liabilities, as well as the related fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable), for instruments executed with the same counterparty where a right of setoff exists.
Basis for Opinions
The Company’s management is responsible for these consolidated financial
statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations
of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis,
evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
As described in Management’s Report on Internal Control over Financial Reporting, management has excluded North American
Power and Gas LLC from its assessment of internal control over financial reporting as of December 31, 2017 because it was acquired by the Company in a purchase business combination during 2017. We have also excluded North American Power and Gas, LLC from our audit of internal control over financial reporting. North American Power and Gas, LLC is a wholly-owned subsidiary whose total assets and total revenues excluded from management’s assessment and our audit of internal control over
111
financial reporting represent 1% and 2%, respectively, of the related consolidated financial
statement amounts as of and for the year ended December 31, 2017.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the
company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting
may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Debt,
current portion ($175 and $176 attributable to VIEs)
225
748
Derivative liabilities, current
197
138
Other current liabilities
571
523
Total
current liabilities
1,874
2,205
Debt, net of current portion ($2,238 and $2,944 attributable to VIEs)
11,180
11,431
Long-term derivative
liabilities
119
149
Other long-term liabilities
213
369
Total liabilities
13,386
14,154
Commitments
and contingencies (see Note 16)
Stockholders’ equity:
Preferred stock, $0.001 par value per share; authorized 100,000,000 shares, none issued and outstanding at December 31, 2017 and 2016
—
—
Common
stock, $0.001 par value per share; authorized 1,400,000,000 shares, 361,677,891 shares issued and 360,516,091 shares outstanding at December 31, 2017, and 359,627,113 shares issued and 359,061,764 shares outstanding at December 31, 2016
—
—
Treasury stock, at cost, 1,161,800 and 565,349 shares, respectively
(15
)
(7
)
Additional
paid-in capital
9,661
9,625
Accumulated deficit
(6,552
)
(6,213
)
Accumulated other comprehensive loss
(106
)
(137
)
Total
Calpine stockholders’ equity
2,988
3,268
Noncontrolling interest
79
71
Total stockholders’ equity
3,067
3,339
Total
liabilities and stockholders’ equity
$
16,453
$
17,493
The accompanying notes are an integral part of these Consolidated Financial Statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS — (Continued)
(in millions)
2017
2016
2015
Cash
paid during the period for:
Interest, net of amounts capitalized
$
575
$
584
$
620
Income
taxes
$
12
$
12
$
21
Supplemental
disclosure of non-cash investing and financing activities:
Purchase of King City Cogeneration Plant Lease(4)
$
15
$
—
$
—
Change
in capital expenditures included in accounts payable
$
20
$
(37
)
$
13
Reduction of debt due to sale of Mankato Power Plant(2)
$
—
$
243
$
—
Retirement
of shares held in treasury
$
—
$
—
$
2,885
____________
(1)
Includes
amortization included in Commodity revenue and Commodity expense associated with intangible assets and amortization recorded in interest expense associated with debt issuance costs and discounts.
(2)
On October 26, 2016, we completed the sale of Mankato Power Plant for $407 million, including working capital and other adjustments. We received net proceeds of $164 million after the non-cash reduction of Steamboat project debt of $243 million as the funds were provided directly to the lender in conjunction with the sale of the power plant.
(3)
On
December 1, 2016, we completed the purchase of Calpine Solutions, formerly Noble Solutions, along with a swap contract for approximately $800 million plus approximately $350 million of net working capital at closing. We recovered approximately $250 million in cash subsequent to closing and prior to year end December 31, 2016.
(4)
On April 3, 2017, we completed the purchase
of the King City Cogeneration Plant lease in exchange for a three-year promissory note with a discounted value of $57 million. We recorded a net increase to property, plant and equipment, net on our Consolidated Balance Sheet of $15 million due to the increased value of the promissory note as compared to the carrying value of the lease.
The accompanying notes are an integral part of these Consolidated Financial Statements.
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 (included
in our West segment), Texas (included in our Texas segment) and the Northeast and Mid-Atlantic regions (included in our East segment) of the U.S. We sell power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities and other governmental entities, power marketers as well as retail commercial, industrial, governmental and residential customers. We continue to focus on getting closer to our customers through expansion of our retail platform which began with the acquisition of Champion Energy in 2015 and was followed by the acquisitions of Calpine Solutions in late 2016 and North American Power in early 2017. We purchase primarily natural gas and some fuel oil as fuel for our power plants and engage in related natural gas transportation and storage transactions. We also purchase power for sale to our customers
and purchase electric transmission rights to deliver power to our customers. Additionally, consistent with our Risk Management Policy, we enter into natural gas, power, environmental product, fuel oil and other physical and financial commodity contracts to hedge certain business risks and optimize our portfolio of power plants.
2.
Merger Agreement
On August 17, 2017, we entered into the Merger Agreement with Volt Parent, LP (“Volt Parent”) and Volt
Merger Sub, Inc. (“Merger Sub”), a wholly-owned subsidiary of Volt Parent, pursuant to which Merger Sub will merge with and into Calpine, with Calpine surviving the Merger as a subsidiary of Volt Parent. On December 15, 2017, the Merger was approved by our shareholders representing a majority of the outstanding shares of Calpine common stock.
At the effective time of the Merger, each share of Calpine common stock outstanding as of immediately prior to the effective time of the Merger (excluding certain shares as described in the Merger Agreement) will cease to be outstanding and be converted into the right to receive $15.25 per share in cash or approximately $5.6 billion in total. Calpine currently expects the Merger to be completed in the first quarter of 2018, subject to the
receipt of certain regulatory approvals and the satisfaction or waiver of certain other customary closing conditions.
The Merger Agreement provides that, during the period beginning on August 17, 2017 and continuing through October 2, 2017, Calpine and its subsidiaries could solicit, initiate, facilitate or encourage “Alternative Transaction Proposals” (as defined in the Merger Agreement) from certain third parties. No Alternative Transaction Proposals were received prior to October 2, 2017. On October 2, 2017, we became subject to customary “no shop” restrictions prohibiting us from soliciting, facilitating, encouraging,
discussing, negotiating or cooperating with respect to any “Alternative Transaction Proposals” or providing information to or participating in any discussions or negotiations with third parties regarding “Alternative Transaction Proposals”, subject to certain customary exceptions to permit our Board of Directors to comply with its fiduciary duties in accordance with the terms of the Merger Agreement.
The Merger Agreement contains certain termination rights, including, among others, the right of Calpine to terminate the Merger Agreement to accept a “Superior Proposal”, subject to specified limitations and payment by Calpine of a termination fee. The Merger Agreement also provides that Volt Parent will be required to pay Calpine a reverse termination fee under specified circumstances.
On September 15, 2017, we amended
our Corporate Revolving Facility to, among other things, provide that the Merger does not constitute a “Change of Control” thereunder, effective upon consummation of the Merger. On October 20, 2017, we further amended our Corporate Revolving Facility to extend the maturity of certain revolving commitments and reduce the capacity thereunder from $1.79 billion to $1.47 billion. Both amendments to the Corporate Revolving Facility are effective upon consummation of the Merger.
During the year ended December 31, 2017, we recorded approximately $15 million in Merger-related costs which was recorded in other operating expenses on our Consolidated
Statement of Operations and primarily related to legal, investment banking and other professional fees associated with the Merger.
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3.
Summary of Significant Accounting Policies
Basis of Presentation and Principles of Consolidation
Our Consolidated Financial Statements have been prepared in accordance with U.S. GAAP and include the accounts of all majority-owned subsidiaries
that are not VIEs and all VIEs where we have determined we are the primary beneficiary. Intercompany transactions have been eliminated in consolidation.
Equity Method Investments — We use the equity method of accounting to record our net interests in VIEs where we have determined that we are not the primary beneficiary, which include Greenfield LP, a 50% partnership interest, Whitby, a 50% partnership interest and Calpine Receivables, a 100% membership interest. Our share of net income (loss) is calculated according to our equity ownership percentage or according to the terms of the applicable partnership agreement or limited liability company operating agreement. See Note 6 for further discussion of our VIEs and unconsolidated investments.
Reclassifications — We
have reclassified certain prior period amounts for comparative purposes. These reclassifications did not have a material effect on our financial condition, results of operations or cash flows.
Jointly-Owned Plants — Certain of our subsidiaries own undivided interests in jointly-owned plants. These plants are maintained and operated pursuant to their joint ownership participation and operating agreements. We are responsible for our subsidiaries’ share of operating costs and direct expenses and include our proportionate share of the facilities and related revenues and direct expenses in these jointly-owned plants in the corresponding balance sheet and income statement captions of our Consolidated Financial Statements. The following
table summarizes our proportionate ownership interest in jointly-owned power plants:
Use
of Estimates in Preparation of Financial Statements
The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures included in our Consolidated Financial Statements. Actual results could differ from those estimates.
Fair Value of Financial Instruments and Derivatives
The carrying values of accounts receivable, accounts payable and other receivables and payables approximate their respective fair values due to their short-term maturities. See Note 7 for disclosures regarding the fair value of our debt instruments and Note 8 for disclosures regarding the fair values of our derivative instruments and related margin deposits and certain of our cash balances.
Concentrations
of Credit Risk
Financial instruments that potentially subject us to credit risk consist of cash and cash equivalents, restricted cash, accounts and notes receivable and derivative financial instruments. Certain of our cash and cash equivalents, as well as our restricted cash balances, are invested in money market accounts with investment banks that are not FDIC insured. We place our cash and cash equivalents and restricted cash in what we believe to be creditworthy financial institutions and certain of our money market accounts invest in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities. Additionally, we actively monitor the credit risk of our counterparties and customers, including our receivable, commodity and derivative transactions. Our accounts and notes receivable are concentrated within entities engaged in the energy industry, mainly within the
U.S. We generally have not collected collateral for accounts receivable from utilities and end-user customers; however, we may require collateral in the future. For financial and commodity derivative counterparties and customers, we evaluate the net accounts receivable, accounts payable and fair value of commodity contracts and may require security deposits, cash margin or letters of credit to be posted if our exposure reaches a certain level or their credit rating declines.
Our counterparties and customers primarily consist of four categories of entities who participate in the energy markets:
•
financial institutions and trading
companies;
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•
regulated utilities, municipalities, cooperatives, ISOs and other retail power suppliers;
•
oil, natural gas, chemical and other energy-related industrial companies; and
•
commercial,
industrial and residential retail customers.
We have concentrations of credit risk with a few of our wholesale counterparties and retail customers relating to our sales of power and steam and our hedging, optimization and trading activities. We have exposure to trends within the energy industry, including declines in the creditworthiness of our counterparties and customers for our commodity and derivative transactions. Currently, certain of our counterparties and customers within the energy industry have below investment grade credit ratings. Our risk control group manages counterparty and customer credit risk and monitors our net exposure with each counterparty or customer on a daily basis. The analysis is performed on a mark-to-market basis using forward curves. The net exposure is compared against a credit risk threshold which is determined based on each counterparties’ and customer’s credit rating and
evaluation of their financial statements. We utilize these thresholds to determine the need for additional collateral or restriction of activity with the counterparty or customer. We believe that our credit policies and portfolio of transactions adequately monitor and diversify our credit risk. Currently, our wholesale counterparties and retail customers are performing and financially settling timely according to their respective agreements with the exception of certain retail customers where our credit exposure is not material.
Cash and Cash Equivalents
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have cash and cash equivalents held in non-corporate accounts relating to certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts. These accounts
have been pledged as security in favor of the lenders under such project finance facilities, and the use of certain cash balances on deposit in such accounts is limited, at least temporarily, to the operations of the respective projects.
Restricted Cash
Certain of our debt agreements, lease agreements or other operating agreements require us to establish and maintain segregated cash accounts, the use of which is restricted, making these cash funds unavailable for general use. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent and major maintenance or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted
cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Balance Sheets and Statements of Cash Flows.
The table below represents the components of our restricted cash as of December 31, 2017 and 2016 (in millions):
2017
2016
Current
Non-Current
Total
Current
Non-Current
Total
Debt
service
$
11
$
8
$
19
$
11
$
8
$
19
Construction/major
maintenance
28
16
44
45
6
51
Security/project/insurance
92
—
92
114
—
114
Other
3
1
4
3
1
4
Total
$
134
$
25
$
159
$
173
$
15
$
188
Business
Interruption Proceeds
We record business interruption insurance proceeds when they are realizable and recorded approximately $27 million, $24 million and $2 million of business interruption proceeds in operating revenues for the years ended December 31, 2017, 2016, and 2015, respectively.
Accounts Receivable and Payable
Accounts receivable and payable represent amounts due from customers and owed to vendors, respectively. Accounts receivable are recorded at invoiced amounts, net of reserves and allowances, and do
not bear interest. Receivable balances greater than 30 days past due are reviewed for collectability, depending upon the nature of the customer, and if deemed uncollectible, are charged off against the allowance account after all means of collection have been exhausted and the potential for recovery is considered remote. We use our best estimate to determine the required allowance for doubtful accounts based on a variety of
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factors, including the length of time receivables are past due, economic trends and conditions affecting our customer base, significant one-time events and historical write-off experience. Specific provisions are recorded for individual receivables when we become aware of a customer’s inability to meet its financial obligations.
The
accounts receivable and payable balances also include settled but unpaid amounts relating to our marketing, hedging and optimization activities. Some of these receivables and payables with individual counterparties are subject to master netting arrangements whereby we legally have a right of offset and settle the balances net. However, for balance sheet presentation purposes and to be consistent with the way we present the majority of amounts related to marketing, hedging and optimization activities on our Consolidated Statements of Operations, we present our receivables and payables on a gross basis. We do not have any significant off balance sheet credit exposure related to our customers.
Accounts Receivable Sales Program
On December 1, 2016, in conjunction with our acquisition of Calpine
Solutions, we entered into the Accounts Receivable Sales Program which allows us to sell, at a discount, up to $250 million in certain trade accounts receivable, arising from the sale of power and natural gas, from Calpine Solutions to Calpine Receivables which in turn sells 100% of the receivables to an unaffiliated financial institution, subject to certain contractual limitations. The Accounts Receivable Sales Program expires on November 30, 2018. Calpine Solutions services the receivables sold in exchange for a servicing fee which was not material for the years ended December 31, 2017 and 2016.
We are not the primary beneficiary of Calpine Receivables and, accordingly, do not consolidate this entity in our Consolidated Financial Statements. See Note 6 for a further discussion of our unconsolidated VIEs. Any portion of the purchase price for the sold receivables which is not paid in cash is recorded as a note receivable. The note receivable is recorded at fair value and does not materially differ from the carrying value of the trade accounts receivable held prior to sale due to the short-term nature of the receivables and high credit quality of the retail customers involved. Receivables sold under the Accounts Receivable Sales Program are accounted for as sales and excluded from accounts receivable on our Consolidated Balance Sheets and reflected as cash provided by operating activities on our Consolidated Statements of Cash Flows. Calpine has guaranteed the performance of Calpine Solutions under the Accounts Receivable Sales Program. See Note 16 for a further
description of our guarantees.
At December 31, 2017 and 2016, we had $196 million and $211 million, respectively, in trade accounts receivable outstanding that were sold under the Accounts Receivable Sales Program and $26 million and $32 million, respectively, in notes receivable which was recorded on our Consolidated Balance Sheets. We sold an aggregate of approximately $2.2 billion and $165 million in trade accounts receivable and recorded proceeds of approximately
$2.2 billion and $165 million during the years ended December 31, 2017 and 2016, respectively. Any losses incurred on the sale of trade accounts receivable are recorded in other (income) expense, net on our Consolidated Statements of Operations which were not material during the years ended December 31, 2017 and 2016.
Inventory
Inventory primarily consists of spare parts, stored natural gas and fuel oil, environmental
products and natural gas exchange imbalances. Inventory, other than spare parts, is stated primarily at the lower of cost or net realizable value under the weighted average cost method. Spare parts inventory is valued at weighted average cost and is expensed to operating and maintenance expense or capitalized to property, plant and equipment as the parts are utilized and consumed.
Collateral
We use margin deposits, prepayments and letters of credit as credit support with and from our counterparties and customers for commodity procurement and risk management activities. In addition, we have granted additional first priority liens on the assets previously subject to first priority liens under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility as collateral under certain of our power and natural gas agreements. These agreements qualify as “eligible commodity
hedge agreements” under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. The first priority liens have been granted in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to our counterparties under such agreements. The counterparties under such agreements would share the benefits of the collateral subject to such first priority liens ratably with the lenders under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. Certain of our interest rate hedging instruments relate to hedges of certain of our project financings collateralized by first priority liens on the underlying assets. See Note 10 for a further discussion on our amounts and use of collateral.
Property, Plant and Equipment, Net
Property, plant, and equipment items are recorded at cost. We capitalize costs incurred
in connection with the construction of power plants, the development of geothermal properties and the refurbishment of major turbine generator equipment. When
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capital improvements to leased power plants meet our capitalization criteria they are capitalized as leasehold improvements and amortized over the shorter of the term of the lease or the economic life of the capital improvement. We expense maintenance when the service is performed for work that does not meet our capitalization criteria. Our current capital expenditures at our Geysers Assets are those incurred for proven reserves and reservoir replenishment (primarily water injection), pipeline and power generation assets and drilling of “development wells” as all drilling activity has been
performed within the known boundaries of the steam reservoir. We have capitalized costs incurred during ownership consisting of additions, certain replacements or repairs when the repairs appreciably extend the life, increase the capacity or improve the efficiency or safety of the property. Such costs are expensed when they do not meet the above criteria. We purchased our Geysers Assets as a proven steam reservoir and all well costs, except well workovers and routine repairs and maintenance, have been capitalized since our purchase date.
We depreciate our assets under the straight-line method over the shorter of their estimated useful lives or lease term. For our natural gas-fired power plants, we assume an estimated salvage value which approximates 10% of the depreciable cost basis where we own the power plant or have a favorable option to purchase the power plant or take ownership
of the power plant at conclusion of the lease term and a de mininimis amount of the depreciable costs basis for componentized equipment. For our Geysers Assets, we typically assume no salvage values. We use the component depreciation method for our natural gas-fired power plant rotable parts, certain componentized balance of plant parts and our information technology equipment and the composite depreciation method for the other natural gas-fired power plant asset groups and Geysers Assets.
Generally, upon normal retirement of assets under the composite depreciation method, the costs of such assets are retired against accumulated depreciation and no gain or loss is recorded. For the retirement of assets under the component depreciation method, generally, the costs and related accumulated depreciation of such assets are removed from our Consolidated Balance Sheets and any gain or loss is recorded as operating and maintenance
expense.
Goodwill and Intangible Assets
Goodwill represents the excess of the purchase price over the fair value of the net assets acquired at the time of an acquisition. We assess the carrying amount of our goodwill annually during the third quarter and whenever the events or changes in circumstances indicate that the carrying value may not be recoverable. The change in goodwill by segment during the year ended December 31, 2017 was as follows (in millions):
The
purchase price allocation adjustment in the East segment represents adjustments of $16 million for North American Power and $(9) million for Calpine Solutions.
We record intangible assets, such as acquired contracts, customer relationships and trademark and trade name at their estimated fair values at acquisition. We use all information available to estimate fair values including quoted market prices, if available, and other widely accepted valuation techniques. Certain estimates and judgments are required in the application of the techniques used to measure fair value of our intangible assets, including estimates of future cash flows, selling prices, replacement costs, economic lives and the selection of a discount rate, which
are not observable in the market and represent a Level 3 measurement. All recognized intangible assets consist of contractual rights and obligations with finite lives.
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As of December 31, 2017 and 2016, the components of our intangible assets were as follows (in millions):
Amortization expense related to our intangible assets for the years ended December 31, 2017, 2016 and 2015
was $175 million, $218 million and $91 million, respectively.
The estimated aggregate amortization expense of our intangible assets for the next five years is as follows (in millions):
2018
$
100
2019
$
71
2020
$
44
2021
$
39
2022
$
35
Impairment
Evaluation of Long-Lived Assets (Including Goodwill, Intangibles and Investments)
We evaluate our long-lived assets, such as property, plant and equipment, equity method investments and definite-lived intangible assets for impairment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Equipment assigned to each power plant is not evaluated for impairment separately; instead, we evaluate our operating power plants and related equipment as a whole unit. When we believe an impairment condition may have occurred, we are required to estimate the undiscounted future cash flows associated with a long-lived asset or group of long-lived assets at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities for long-lived assets that are expected to be held and used. We use a fundamental
long-term view of the power market which is based on long-term production volumes, price curves and operating costs together with the regulatory and environmental requirements within each individual market to prepare our multi-year forecast. Since we manage and market our power sales as a portfolio rather than at the individual power plant level or customer level within each designated market, pool or segment, we group our power plants based upon the corresponding market for valuation purposes. If we determine that the undiscounted cash flows from an asset or group of assets to be held and used are less than the associated carrying amount, or if we have classified an asset as held for sale, we must estimate fair value to determine the amount of any impairment loss.
We test goodwill and all intangible assets not subject to amortization for impairments at least annually, or more frequently whenever an event or change in circumstances
occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount. We test goodwill for impairment at the reporting unit level, which is identified one level below the Company’s operating segments for which discrete financial information is available and management regularly reviews the operating results. We perform an annual impairment assessment in the third quarter of each year, or more frequently if indicators of potential impairment exist, to determine whether it is more likely than not that the fair value of a reporting unit in which goodwill resides is less than its carrying value. For reporting units in which this assessment concludes that it is more likely than not that the fair value is more than its carrying value, goodwill is not considered impaired and we are not required to perform the two-step goodwill impairment test. Qualitative
factors considered in this assessment include industry and market considerations, overall financial performance, and other relevant events and factors affecting the reporting unit.
For reporting units in which the impairment assessment concludes that it is more likely than not that the fair value is less than its carrying value, we perform the first step of the goodwill impairment test, which compares the fair value of the reporting unit to its carrying value. If the fair value of the reporting unit exceeds the carrying value of the net assets assigned to that unit, goodwill is not considered impaired and we are not required to perform additional analysis. If the carrying value of the net assets assigned to the reporting unit exceeds the fair value of the reporting unit, then we must perform the second step of the goodwill impairment test to determine the implied fair value of the
reporting unit’s goodwill. If we determine during the second step that
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the carrying value of a reporting unit’s goodwill exceeds its implied fair value, we record an impairment loss equal to the difference. We did not record an impairment of our goodwill during the years ended December 31, 2017, 2016 and 2015.
All construction and development projects are reviewed for impairment whenever there is an indication of potential reduction in fair value. If it is determined that a construction or development project is no longer probable
of completion and the capitalized costs will not be recovered through future operations, the carrying value of the project will be written down to its fair value.
In order to estimate future cash flows, we consider historical cash flows, existing contracts, capacity prices and PPAs, changes in the market environment and other factors that may affect future cash flows. To the extent applicable, the assumptions we use are consistent with forecasts that we are otherwise required to make (for example, in preparing our earnings forecasts). The use of this method involves inherent uncertainty. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions
used in our estimates, and the effect of such variations could be material.
When we determine that our assets meet the assets held-for-sale criteria, they are reported at the lower of their carrying amount or fair value less the cost to sell. We are also required to evaluate our equity method investments to determine whether or not they are impaired when the value is considered an “other than a temporary” decline in value.
Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. We will also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment including contract terms, tenor and credit risk of counterparties. We may
also consider prices of similar assets, consult with brokers, or employ other valuation techniques. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the effect of such variations could be material.
We recorded impairment losses of $41 million during the year ended December 31, 2017 related to power plants in our West and Texas segments and $13 million during the year ended December 31, 2016 related to a power plant
in our West segment. We did not record any impairment losses during the year ended December 31, 2015.
Asset Retirement Obligation
We record all known asset retirement obligations for which the liability’s fair value can be reasonably estimated. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. At December 31, 2017 and 2016, our asset retirement obligation liabilities were $43 million and $53 million, respectively, primarily relating to land leases upon
which our power plants are built and the requirement that the property meet specific conditions upon its return.
Debt Issuance Costs
Costs incurred related to the issuance of debt instruments are deferred and amortized over the term of the related debt using a method that approximates the effective interest rate method. However, when the timing of debt transactions involve contemporaneous exchanges of cash between us and the same creditor(s) in connection with the issuance of a new debt obligation and satisfaction of an existing debt obligation, debt issuance costs are accounted for depending on whether the transaction qualifies as an extinguishment or modification, which requires us to either write-off the original debt issuance costs and capitalize the new issuance costs, or continue to amortize the original debt issuance costs and immediately expense the new issuance costs. Our
debt issuance costs related to a recognized debt liability are presented as a direct deduction from the carrying amount of the related debt liability, which is consistent with the presentation of debt discounts.
Revenue Recognition
Our operating revenues are comprised of the following:
•
power and steam revenue consisting of fixed and variable capacity payments, which are not related to generation including capacity payments received from RTO and ISO capacity auctions, variable payments for power and steam, which are related to generation, retail power revenues, host steam and RECs from our Geysers Assets, other revenues such as RMR Contracts,
resource adequacy and certain ancillary service revenues and realized settlements from our marketing, hedging, optimization and trading activities;
125
•
mark-to-market revenues from derivative instruments as a result of our marketing, hedging, optimization and trading activities; and
•
other service revenues.
Power
and Steam
Physical Commodity Contracts — We recognize revenue primarily from the sale of power and steam thermal energy for sale to our customers for use in industrial or other heating operations upon transmission and delivery to the customer.
We routinely enter into physical commodity contracts for sales of our generated power to manage risk and capture the value inherent in our generation. We apply lease accounting to contracts that meet the definition of a lease and accrual accounting treatment to those contracts
that are either exempt from derivative accounting or do not meet the definition of a derivative instrument. Additionally, we determine whether the financial statement presentation of revenues should be on a gross or net basis.
With respect to our physical executory contracts, where we act as a principal, we take title of the commodities and assume the risks and rewards of ownership by receiving the natural gas and using the natural gas in our operations to generate and deliver the power. Where we act as principal, we record settlement of our physical commodity contracts on a gross basis. Where we do not take title of the commodities but receive a net variable payment to convert natural gas into power and steam in a tolling operation, we record the
variable payment as revenue but do not record any fuel and purchased energy expense.
Capacity payments, RMR Contracts, RECs, resource adequacy and other ancillary revenues, unless qualified as a lease, are recognized when contractually earned and consist of revenues received from our customers either at the market price or a contract price.
Revenues from sales of power to retail customers are recognized upon delivery under the accrual method, unless we apply derivative accounting treatment to the retail contract. See Note 9 for further discussion on our accounting for derivatives. Unbilled retail revenues are based
upon estimates of customer usage since the date of the last meter reading provided by the ISOs or electric distribution companies by applying the estimated revenue per KWh by customer class to the estimated number of KWhs delivered but not yet billed. Estimated amounts are adjusted when actual usage is known and billed.
Realized and Mark-to-Market Revenues from Commodity Derivative Instruments
Realized Settlements of Commodity Derivative Instruments — The realized value of power commodity sales and purchase contracts that are net settled or settled as gross sales and purchases, but could have been net settled, are reflected on a net basis and are included in Commodity revenue on our Consolidated Statements of Operations.
Mark-to-Market
Gain (Loss) — The changes in the mark-to-market value of power-based commodity derivative instruments are reflected on a net basis as a separate component of operating revenues.
Leases — We have contracts, such as certain tolling agreements, which we account for as operating leases under U.S. GAAP. We may levelize certain components of these contract revenues on a straight-line basis over the term of the contract. The total contractual future minimum lease rentals for our contracts
accounted for as operating leases at December 31, 2017, are as follows (in millions):
2018
$
429
2019
320
2020
261
2021
257
2022
224
Thereafter
380
Total
$
1,871
Accounting
for Derivative Instruments
We enter into a variety of derivative instruments including both exchange traded and OTC power and natural gas forwards, options as well as instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) and interest rate hedging instruments. We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for and are designated under the normal purchase normal sale exemption. Accounting for derivatives at fair value requires us to make estimates about future prices during periods
126
for which price quotes may not be available
from sources external to us, in which case we rely on internally developed price estimates. See Note 9 for further discussion on our accounting for derivatives.
During 2008, we established our accounting policy related to the presentation of our derivative instruments on our Consolidated Balance Sheets. Historically, we separately reflected on a gross basis the fair value of our current and long-term derivative assets and liabilities and related cash collateral executed with the same counterparty under a master netting arrangement. Effective September 30, 2017, we reflect on a net basis the fair value amounts associated with our current and long-term derivative assets and liabilities and the related amounts recognized for the right to reclaim, or the obligation to return, cash collateral on our Consolidated Balance Sheets. This policy is preferable as it more accurately reflects
counterparty credit risk, liquidity risk and the contractual rights and obligations under these arrangements.
The revised presentation of our derivative instruments is considered a change in accounting principle; thus, we retroactively applied the new accounting to our Consolidated Balance Sheet as of December 31, 2016 which did not result in a change in our total stockholder’s equity, results of operations or cash flows for any previously reported periods. See Notes 8, 9 and 10 for additional information on the assets and liabilities that are reflected on a net basis in our Consolidated Balance Sheets. The table below reflects the effect of the new accounting on previously reported financial information (in millions):
Consolidated
Statement of Cash Flows for the Year Ended December 31, 2016
Change in operating assets and liabilities, net of effects of acquisitions:
Derivative
instruments, net
$
(82
)
$
(204
)
$
(286
)
Other assets
$
150
$
187
$
337
Accounts
payable and accrued expenses
$
(6
)
$
17
$
11
Net cash provided by operating activities
$
1,030
$
—
$
1,030
Consolidated
Statement of Cash Flows for the Year Ended December 31, 2015
Change in operating assets and liabilities, net of effects of acquisitions:
Derivative
instruments, net
$
(183
)
$
(122
)
$
(305
)
Other assets
$
(120
)
$
109
$
(11
)
Accounts
payable and accrued expenses
$
(208
)
$
13
$
(195
)
Net cash provided by operating activities
$
876
$
—
$
876
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Fuel and Purchased Energy Expense
Fuel and purchased energy expense is comprised of the cost of natural gas and fuel oil purchased from third parties for the purposes of consumption in our power plants as fuel, the cost of power purchased from third parties for sale to retail customers, the cost of power and natural gas purchased from third parties for our marketing, hedging and optimization activities and realized settlements and mark-to-market gains and losses resulting from general market price movements against certain derivative natural gas and power contracts including financial natural gas transactions economically hedging anticipated future power sales that either do not qualify as hedges
under the hedge accounting guidelines or qualify under the hedge accounting guidelines and the hedge accounting designation has not been elected.
Realized and Mark-to-Market Expenses from Commodity Derivative Instruments
Realized Settlements of Commodity Derivative Instruments — The realized value of natural gas purchase and sales commodity contracts that are net settled are reflected on a net basis and included in Commodity expense on our Consolidated Statements of Operations. Power purchase commodity contracts that result in the physical delivery of power, and that also supplement our power generation, are reflected on a gross basis and are included in Commodity expense on our
Consolidated Statements of Operations.
Mark-to-Market (Gain) Loss — The changes in the mark-to-market value of natural gas-based and certain power-based commodity derivative instruments are reflected on a net basis as a separate component of fuel and purchased energy expense.
Operating and Maintenance Expense
Operating and maintenance expense primarily includes employee expenses, utilities, chemicals, repairs and maintenance (including equipment failure and major maintenance), insurance and property taxes. We recognize these expenses when the service is performed or in the period to which the expense relates.
Income Taxes
Income taxes
are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying values of existing assets and liabilities and their respective tax basis and tax credit and NOL carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities due to a change in tax rates is recognized in income in the period that includes the enactment date.
We recognize the financial statement effects of a tax position when it is more-likely-than-not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the
largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority. We reverse a previously recognized tax position in the first period in which it is no longer more-likely-than-not that the tax position would be sustained upon examination. See Note 11 for a further discussion on our income taxes.
Earnings per Share
Basic earnings per share is calculated using the weighted average shares outstanding during the period and includes restricted stock units for which no future service is required as a condition to the delivery of the underlying common stock. Diluted earnings per share is calculated by adjusting the weighted average shares outstanding by the dilutive effect of share-based awards using the treasury stock method. See Note 12 for a further discussion of our earnings
per share.
Stock-Based Compensation
For our restricted stock and restricted stock units, we use our closing stock price on the date of grant, or the last trading day preceding the grant date for restricted stock granted on non-trading days, as the fair value for measuring compensation expense. We use the Black-Scholes option pricing model to estimate the fair value of our employee stock options on the grant date. Our performance share units are measured at fair value using a Monte Carlo simulation model at each reporting date until settlement. We include estimated forfeitures in the calculation of stock-based compensation expense. See Note 13 for a further discussion of our stock-based compensation.
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Treasury
Stock
Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as treasury stock. Upon retirement of treasury stock, the amounts in excess of par value are charged entirely to additional paid-in capital. See Note 15 for a further discussion of treasury stock.
New Accounting Standards and Disclosure Requirements
Revenue Recognition — In May 2014, the FASB issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers.” The comprehensive new revenue recognition standard will supersede all existing revenue recognition guidance. The core principle of the standard is that a company should recognize revenue to depict the transfer of promised
goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard also requires expanded disclosures surrounding revenue recognition. The standard allows for either full retrospective or modified retrospective adoption. In August 2015, the FASB deferred the effective date of Accounting Standards Update 2014-09 for public entities by one year, such that the standard will become effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2017. The standard permits entities to adopt early, but only as of the original effective date. In March 2016, the FASB issued Accounting Standards Update 2016-08 “Principal versus Agent Considerations (Reporting Revenue Gross versus Net)” which clarifies implementation guidance for principal versus agent considerations in the new revenue
recognition standard. In May 2016, the FASB issued Accounting Standards Update 2016-12 “Narrow-Scope Improvements and Practical Expedients” which addresses assessing the collectability of a contract, the presentation of sales taxes and other taxes collected from customers, non-cash consideration and completed contracts and contract modifications at transition. We will adopt the standard in the first quarter of 2018 using the modified retrospective transition approach. We have finalized our evaluation of the effect the revenue recognition standard will have on our revenue contracts such as our PPAs and tolling
agreements and are finalizing the additional disclosure requirements associated with the new standard. Upon adoption, we will elect the practical expedient that would allow an entity to recognize revenue in the amount to which the entity has the right to invoice to the extent we determine that we have a right to consideration from the customer in an amount that corresponds directly with the value provided based on our performance completed to date. The adoption of this standard will result in an immaterial cumulative effect adjustment and will not have a material effect on our financial condition, results of operations or cash flows.
Inventory — In July 2015, the FASB issued Accounting Standards Update 2015-11, “Simplifying the Measurement of Inventory.” The standard changes the inventory valuation
method from the lower of cost or market to the lower of cost or net realizable value for inventory valued under the first-in, first-out or average cost methods. This standard is effective for fiscal years beginning after December 15, 2016, including interim periods and requires prospective adoption with early adoption permitted. We adopted Accounting Standards Update 2015-11 in the first quarter of 2017 which did not have a material effect on our financial condition, results of operations or cash flows.
Leases — In February 2016, the FASB issued Accounting Standards Update 2016-02, “Leases.” The comprehensive new lease standard will supersede all existing lease guidance. The standard requires that a lessee should recognize a right-to-use asset and a lease liability for substantially all operating leases based on the present value of the minimum
rental payments. Entities may make an accounting policy election to not recognize lease assets and liabilities for leases with a term of 12 months or less. For lessors, the accounting for leases remains substantially unchanged. The standard also requires expanded disclosures surrounding leases. The standard is effective for fiscal periods beginning after December 15, 2018, including interim periods within that reporting period and requires modified retrospective adoption with early adoption permitted. In January 2018, the FASB issued Accounting Standards Update 2018-01, “Land Easement Practical Expedient for Transition to Topic 842” that allows an entity to not evaluate existing and expired land easements that were not previously accounted for as leases upon adoption of Accounting Standards Update 2016-02. Any land easements entered into prospectively or modified after adoption should be evaluated to assess whether
they meet the definition of a lease. We expect to adopt the standard in the first quarter of 2019. We have completed our initial evaluation of the standard and believe that the key changes that will affect us relate to our accounting for operating leases that are currently off-balance sheet and tolling contracts which we currently account for as operating leases. Additionally, we are evaluating the potential effects of the removal of the real estate guidance currently applicable to lessors. We are also considering electing the practical expedients in our implementation of the standard; however, this may change as we complete our assessment of the standard.
Statement of Cash Flows — In August 2016, the FASB issued Accounting Standards Update 2016-15, “Classification of Certain Cash Receipts and Cash Payments.”
The standard addresses several matters of diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows including the presentation of debt extinguishment costs and distributions received from equity method investments. The standard is effective for fiscal years beginning after December 15, 2017, and requires modified retrospective adoption. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard.
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Income Taxes — In October 2016, the FASB issued Accounting Standards Update 2016-16, “Intra-Entity Transfers of
Assets Other than Inventory.” The standard requires an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs which differs from the current requirement that prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party. The standard is effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period and requires modified retrospective adoption. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard.
Restricted Cash — In November 2016, the FASB issued Accounting Standards Update 2016-18, “Restricted Cash.” The standard requires restricted cash
to be included with cash and cash equivalents when reconciling the beginning and ending amounts in the statement of cash flows and also requires disclosures regarding the nature of restrictions on cash, cash equivalents and restricted cash. The standard is effective for fiscal years beginning after December 15, 2017, including interim periods and requires retrospective adoption with early adoption permitted. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard.
Intangibles — Goodwill and Other — In January 2017, the FASB issued Accounting Standards Update 2017-04, “Simplifying the Test for Goodwill Impairment.” The standard eliminates the second step in the goodwill impairment test which requires an entity to determine
the implied fair value of the reporting unit’s goodwill. Instead, an entity should recognize an impairment loss if the carrying value of the net assets assigned to the reporting unit exceeds the fair value of the reporting unit, with the impairment loss not to exceed the amount of goodwill allocated to the reporting unit. The standard is effective for annual and interim goodwill impairment tests conducted in fiscal years beginning after December 15, 2019, with early adoption permitted. We adopted Accounting Standards Update 2017-04 in 2017 which did not have a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard.
Derivatives and Hedging — In August 2017, the FASB issued Accounting Standards Update 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” The standard
better aligns an entity’s hedging activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results in the financial statements. The standard will prospectively make hedge accounting easier to apply to hedging activities and also enhances disclosure requirements for how hedge transactions are reflected in the financial statements when hedge accounting is elected. The standard is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We are currently assessing the future effect this standard may have on our financial condition, results of operations or cash flows.
4.
Acquisitions
and Divestitures
Acquisition of North American Power
On January 17, 2017, we, through an indirect, wholly-owned subsidiary, completed the purchase of 100% of the outstanding limited liability company membership interests in North American Power for approximately $105 million, excluding working capital and other adjustments. North American Power is a retail energy supplier for homes and small businesses and is primarily concentrated in the Northeast U.S. where Calpine has a substantial power generation presence and where Champion Energy has a substantial retail sales footprint that is enhanced by the addition of North American Power, which has been integrated into our Champion Energy retail platform. We funded the acquisition
with cash on hand and the purchase price is allocated to the net assets of the business including intangible assets for the value of customer relationships and goodwill. The goodwill recorded associated with our acquisition of North American Power is deductible for tax purposes. The purchase price allocation was finalized during the fourth quarter of 2017 which did not result in any material adjustments. The pro forma incremental effect of North American Power on our results of operations for each of the years ended December 31, 2017 and 2016 is not material.
Acquisition of Calpine Solutions, formerly Noble Solutions
On December 1, 2016, through
our indirect, wholly-owned subsidiaries Calpine Energy Services Holdco II, LLC and Calpine Energy Financial Holdings, LLC, we completed the purchase of Calpine Solutions, formerly Noble Solutions, along with a swap contract from Noble Americas Gas & Power Corp. and Noble Group Limited for approximately $800 million plus approximately $350 million of net working capital. We recovered approximately $250 million in cash subsequent to closing and recovered an additional approximately $200 million through collateral synergies and the runoff of acquired legacy hedges, substantially within the first year. Calpine
Solutions is a commercial and industrial retail electricity provider with customers in 20 states in the U.S., including presence in California, Texas, the Mid-Atlantic and Northeast, where our wholesale power generation fleet is primarily concentrated. The acquisition of this large direct energy sales platform is consistent with our stated goal of getting closer to our end-use customers and expands our retail customer base, complementing our existing retail business while providing
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us a valuable sales channel for reaching a much greater portion of the load we seek to serve. We funded the acquisition with a combination of cash on hand and debt financing. The results of Calpine Solutions are reflected in the
segment which corresponds with the geographic area in which the retail sales occur.
The following table summarizes the consideration paid for Calpine Solutions as well as the preliminary determination of the identifiable assets acquired and liabilities assumed at the December 1, 2016 acquisition date (in millions):
Consideration
$
1,150
Identifiable
assets acquired and liabilities assumed:
Assets:
Current assets
141
Margin deposits and other prepaid expense
518
Derivative assets, current(1)
365
Property,
plant and equipment, net
7
Intangible assets(2)
360
Goodwill
162
Long-term derivative assets(1)
359
Total
assets acquired
1,912
Liabilities:
Current liabilities
276
Derivative liabilities, current(1)
270
Long-term derivative liabilities(1)
216
Total
liabilities assumed
762
Net assets acquired
$
1,150
____________
(1)
Consists of acquired customer and wholesale contracts which will be substantially amortized over 5
years.
(2)
Consists primarily of customer relationships that are being amortized over 14 years. See Note 3 for a further description of our intangible assets.
We recorded goodwill of $162 million, all of which is deductible for tax purposes, in connection with the acquisition of Calpine Solutions which represent the excess of the purchase price over the fair values of Calpine Solution’s assets and liabilities. For the goodwill acquired, we allocated $68 million to our West segment, $15 million to our
Texas segment and $79 million to our East segment. The purchase price allocation was finalized during the fourth quarter of 2017 which did not result in any material adjustments.
The revenue and earnings of Calpine Solutions since its acquisition on December 1, 2016 are not material to our Consolidated Statement of Operations for the year ended December 31, 2016.
The following table summarizes the unaudited pro forma operating revenues and net income attributable to Calpine for the periods presented as if Calpine Solutions was acquired on January 1, 2015. The unaudited pro forma information has been prepared by adding the preliminary, unaudited
historical results of Calpine Solutions, as adjusted for amortization of intangible assets and acquired contracts (using the preliminary values assigned to the net assets acquired from Calpine Solutions disclosed above) and interest expense from our 2017 First Lien Term Loan which funded a portion of the purchase price, to our results for the periods indicated below (in millions, except per share amounts).
2016
2015
(Unaudited)
Operating
revenues
$
8,324
$
8,308
Net income attributable to Calpine
$
105
$
132
Net
income per share attributable to Calpine - basic
$
0.30
$
0.36
Net income per share attributable to Calpine - diluted
$
0.29
$
0.36
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Acquisition of Granite Ridge Energy Center
On February 5, 2016, we, through our indirect, wholly-owned subsidiary Calpine Granite Holdings, LLC, completed the purchase of Granite Ridge Energy Center, a power plant with a nameplate capacity of 745 MW (summer peaking capacity of 695 MW), from Granite Ridge Holdings, LLC, for approximately $500 million, excluding working capital and other adjustments. The addition of this modern, efficient, natural gas-fired, combined-cycle power plant increased capacity in our East segment, specifically the constrained New England market. Beginning
operations in 2003, Granite Ridge Energy Center is located in Londonderry, New Hampshire and features two combustion turbines, two heat recovery steam generators and one steam turbine. We funded the acquisition with a combination of cash on hand and our 2023 First Lien Term Loan obtained in the fourth quarter of 2015, and the purchase price was primarily allocated to property, plant and equipment. The purchase price allocation was finalized during the first quarter of 2017 and did not result in any material adjustments or the recognition of goodwill. The pro forma incremental effect of Granite Ridge Energy Center on our results of operations for each of the years ended December 31, 2016 and 2015 is not material.
Acquisition of Champion
Energy
On October 1, 2015, we, through our indirect, wholly-owned subsidiary Calpine Energy Services Holdco, LLC, completed the purchase of Champion Energy Marketing, LLC from a subsidiary of Crane Champion Holdco, LLC, which owned a 75% interest, and EDF Trading North America, LLC, which owned a 25% interest, for approximately $240 million, excluding working capital adjustments. The addition of this well-established retail sales organization is consistent with our stated goal of getting closer to our end-use customers and provides us a valuable sales channel for directly reaching a much greater portion of the load we seek to serve. The purchase price was funded with cash on hand and any excess of the purchase price over the fair values of
Champion Energy’s assets and liabilities was recorded as goodwill; however, the goodwill we recorded as a result of this acquisition was immaterial. The purchase price allocation was finalized during the third quarter of 2016 which did not result in any material adjustments. The pro forma incremental effect of Champion Energy on our results of operations for the year ended December 31, 2015 is not material.
Sale of Osprey Energy Center
On January 3, 2017, we completed the sale of our Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million, excluding working capital and other adjustments. This transaction supports our effort to divest non-core assets outside our strategic
concentration. We recorded a gain on sale of assets, net of approximately $27 million during the year ended December 31, 2017 associated with the sale of the Osprey Energy Center.
Sale of Mankato Power Plant
On October 26, 2016, we, through our indirect, wholly-owned subsidiaries, New Steamboat Holdings, LLC and Mankato Holdings, LLC, completed the sale of our Mankato Power Plant, a 375 MW natural gas-fired, combined-cycle power plant and 345 MW expansion project under advanced development located in Minnesota,
to Southern Power Company, a subsidiary of Southern Company, for $396 million, excluding working capital and other adjustments. This transaction supports our effort to divest non-core assets outside our strategic concentration. We used the proceeds from the sale to partially fund the Calpine Solutions acquisition and for other corporate purposes. We recorded a gain on sale of assets, net of approximately $157 million during the year ended December 31, 2016, and our federal and state NOLs almost entirely offset the taxable gain from the sale.
South Point Energy Center
As a result of the denial by the Nevada Public Utility Commission of the sale of South Point Energy Center to Nevada Power Company
in February 2017, we terminated the corresponding asset sale agreement (originally executed on April 1, 2016) in the first quarter of 2017. We are currently assessing our options related to South Point Energy Center; however, we do not anticipate that the termination of the asset sale agreement will have a material effect on our financial condition, results of operations or cash flows. During the first quarter of 2017, we reclassified the assets of South Point Energy Center from current assets held for sale to held and used at fair value.
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5.
Property,
Plant and Equipment, Net
As of December 31, 2017 and 2016, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):
2017
2016
Depreciable
Lives
Buildings, machinery and equipment
$
16,506
$
16,468
3 – 46 Years
Geothermal properties
1,494
1,377
13
– 58 Years
Other
236
259
3 – 46 Years
18,236
18,104
Less:
Accumulated depreciation
6,383
5,865
11,853
12,239
Land
117
116
Construction
in progress
754
658
Property, plant and equipment, net
$
12,724
$
13,013
Total
depreciation expense, including amortization of leased assets, recorded for the years ended December 31, 2017, 2016 and 2015, was $638 million, $628 million and $595 million, respectively.
We have various debt instruments that are collateralized by our property, plant and equipment. See Note 7 for a discussion of such instruments.
Buildings, Machinery and Equipment
This component primarily includes power plants and related equipment. Included in buildings, machinery and equipment are assets under capital leases. See
Note 7 for further information regarding these assets under capital leases.
Geothermal Properties
This component primarily includes power plants and related equipment associated with our Geysers Assets.
Other
This component primarily includes software and emission reduction credits that are power plant specific and not available to be sold.
Capitalized Interest
The total amount of interest capitalized was $26 million, $21 million and $15 million for the years ended December 31, 2017,
2016 and 2015, respectively.
6.
Variable Interest Entities and Unconsolidated Investments
We consolidate all of our VIEs where we have determined that we are the primary beneficiary. There were no changes to our determination of whether we are the primary beneficiary of our VIEs for the year ended December 31, 2017. We have the following types of VIEs consolidated in our financial statements:
Subsidiaries
with Project Debt — All of our subsidiaries with project debt not guaranteed by Calpine have PPAs that provide financial support and are thus considered VIEs. We retain ownership and absorb the full risk of loss and potential for reward once the project debt is paid in full. Actions by the lender to assume control of collateral can occur only under limited circumstances such as upon the occurrence of an event of default, which we have determined to be unlikely. See Note 7 for further information regarding our project debt and Note 3 for information regarding our restricted cash balances.
Subsidiaries with PPAs — Certain of our majority owned subsidiaries
have PPAs that limit the risk and reward of our ownership and thus constitute a VIE.
VIE with a Purchase Option — OMEC has an agreement that provides a third party a fixed price option to purchase power plant assets exercisable in the year 2019. This purchase option limits the risk and reward of our ownership and, thus, constitutes a VIE.
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Consolidation of VIEs
We consolidate our VIEs where we determine that we have both the power to direct the activities of a VIE that most significantly affect the VIE’s economic performance and the obligation to absorb losses or receive benefits from the VIE. We have determined that we hold the obligation to
absorb losses and receive benefits in almost all of our VIEs where we hold the majority equity interest. Therefore, our determination of whether to consolidate is based upon which variable interest holder has the power to direct the most significant activities of the VIE (the primary beneficiary). Our analysis includes consideration of the following primary activities which we believe to have a significant effect on a power plant’s financial performance: operations and maintenance, plant dispatch, and fuel strategy as well as our ability to control or influence contracting and overall plant strategy. Our approach to determining which entity holds the powers and rights is based on powers held as of the balance sheet date. Contractual terms that may change the powers held in future periods, such as a purchase or sale option, are not considered in our analysis. Based on our analysis, we believe that we hold the power and rights to direct the most significant activities
for most of our majority-owned VIEs.
Under our consolidation policy and under U.S. GAAP we also:
•
perform an ongoing reassessment each reporting period of whether we are the primary beneficiary of our VIEs; and
•
evaluate if an entity is a VIE and whether we are the primary beneficiary whenever any changes in facts and circumstances occur such that the holders of the equity investment at risk, as a group, lose the power from voting rights or similar rights of those investments to direct the
activities of a VIE that most significantly affect the VIE’s economic performance or when there are other changes in the powers held by individual variable interest holders.
Noncontrolling Interest — We own a 75% interest in Russell City Energy Company, LLC, one of our VIEs, which is also 25% owned by a third party. We fully consolidate this entity in our Consolidated Financial Statements and account for the third party ownership interest as a noncontrolling interest.
VIE Disclosures
Our consolidated VIEs include natural gas-fired power plants with an aggregate capacity of 7,880 MW and 9,491 MW, at December 31,
2017 and 2016, respectively. For these VIEs, we may provide other operational and administrative support through various affiliate contractual arrangements among the VIEs, Calpine Corporation and its other wholly-owned subsidiaries whereby we support the VIE through the reimbursement of costs and/or the purchase and sale of energy. Other than amounts contractually required, we provided support to these VIEs in the form of cash and other contributions of nil, $115 million and $4 million for the years ended December 31, 2017, 2016
and 2015, respectively.
U.S. GAAP requires separate disclosure on the face of our Consolidated Balance Sheets of the significant assets of a consolidated VIE that can be used only to settle obligations of the consolidated VIE and the significant liabilities of a consolidated VIE for which creditors (or beneficial interest holders) do not have recourse to the general credit of the primary beneficiary. In determining which assets of our VIEs meet the separate disclosure criteria, we consider that this separate disclosure requirement is met where Calpine Corporation is substantially limited or prohibited from access to assets (primarily cash and cash equivalents, restricted cash and property, plant and equipment), and where our VIEs had project financing that prohibits the VIE from providing guarantees on the debt of others. In determining which liabilities of our VIEs meet the separate
disclosure criteria, we consider that this separate disclosure requirement is met where there are agreements that prohibit the debt holders of the VIEs from recourse to the general credit of Calpine Corporation and where the amounts were material to our financial statements.
Unconsolidated VIEs and Investments in Unconsolidated Subsidiaries
We have a 50% partnership interest in Greenfield LP and in Whitby. Greenfield LP and Whitby are VIEs; however, we do not have the power to direct the most significant activities of these entities and therefore do not consolidate them. Greenfield LP is a limited partnership between certain subsidiaries of ours and of Mitsui &
Co., Ltd., which operates the Greenfield Energy Centre, a 1,038 MW natural gas-fired, combined-cycle power plant located in Ontario, Canada. We and Mitsui & Co., Ltd. each hold a 50% interest in Greenfield LP. Whitby is a limited partnership between certain of our subsidiaries and Atlantic Packaging Ltd., which operates the Whitby facility, a 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada. We and Atlantic Packaging Ltd. each hold a 50% partnership interest in Whitby.
In December 2016, we acquired Calpine Receivables, a bankruptcy remote entity created for the special purpose of purchasing trade accounts receivable
from Calpine Solutions under the Accounts Receivable Sales Program. Calpine Receivables is a VIE as we have determined that we do not have the power to direct the activities of the VIE that most significantly affect the VIE’s economic performance nor the obligation to absorb losses or receive benefits from the VIE. Accordingly, we have determined
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that we are not the primary beneficiary of Calpine Receivables as we do not have the power to affect its financial performance as the unaffiliated financial institutions that purchase the receivables from Calpine Receivables control the selection criteria of the receivables sold and appoint the servicer of the receivables which controls management of default. Thus, we do not consolidate Calpine Receivables in
our Consolidated Financial Statements and use the equity method of accounting to record our net interest in Calpine Receivables.
We account for these entities under the equity method of accounting and include our net equity interest in investments in unconsolidated subsidiaries on our Consolidated Balance Sheets. At December 31, 2017 and 2016, our equity method investments included on our Consolidated Balance Sheets were comprised of the following (in millions):
Our
risk of loss related to our investments in Greenfield LP, Whitby and Calpine Receivables is limited to our investment balance. Holders of the debt of our unconsolidated investments do not have recourse to Calpine Corporation and its other subsidiaries; therefore, the debt of our unconsolidated investments is not reflected on our Consolidated Balance Sheets. At December 31, 2017 and 2016, Greenfield LP’s debt was approximately $256 million and $259 million, respectively, and based on our pro rata share of our investment in Greenfield LP, our share of such debt would be approximately $128
million and $130 million at December 31, 2017 and 2016, respectively.
Our equity interest in the net income from our investments in unconsolidated subsidiaries for the years ended December 31, 2017, 2016 and 2015, is recorded in (income) loss from unconsolidated subsidiaries. The following table sets
forth details of our (income) loss from unconsolidated subsidiaries and distributions for the years indicated (in millions):
Inland
Empire Energy Center Put and Call Options — We hold a call option to purchase the Inland Empire Energy Center (a 775 MW natural gas-fired power plant located in California) at predetermined prices from GE that may be exercised between years 2017 and 2024. GE holds a put option whereby they can require us to purchase the power plant, if certain plant performance criteria are met by 2025. We determined that we are not the primary beneficiary of the Inland Empire power plant, and we do not consolidate it due to the fact that GE directs the most significant activities of the power plant including operations and maintenance.
Our
debt agreements contain covenants which could permit lenders to accelerate the repayment of our debt by providing notice, the lapse of time, or both, if certain events of default remain uncured after any applicable grace period. We were in compliance with all of the covenants in our debt agreements at December 31, 2017.
Annual Debt Maturities
Contractual annual principal repayments or maturities of debt instruments as of December 31, 2017, are as follows (in millions):
2018
$
226
2019
899
2020
211
2021
219
2022
975
Thereafter
9,039
Subtotal
11,569
Less:
Debt issuance costs
138
Less: Discount
26
Total debt
$
11,405
Senior Unsecured Notes
Our Senior Unsecured Notes are summarized in the table below (in millions, except for interest rates):
Outstanding
at December 31,
Weighted Average Effective Interest Rates(1)
2017
2016
2017
2016
2023 Senior Unsecured Notes
$
1,239
$
1,237
5.6
%
5.5
%
2024
Senior Unsecured Notes
644
643
5.7
5.6
2025 Senior Unsecured Notes
1,534
1,532
6.0
5.9
Total
Senior Unsecured Notes
$
3,417
$
3,412
____________
(1)
Our
weighted average interest rate calculation includes the amortization of debt issuance costs.
In February 2015, we issued $650 million in aggregate principal amount of 5.5% senior unsecured notes due 2024 in a public offering. The 2024 Senior Unsecured Notes bear interest at 5.5% per annum with interest payable semi-annually on February 1 and August 1 of each year, beginning on August 1, 2015. The 2024 Senior Unsecured Notes were issued at par, mature on February 1, 2024 and contain substantially similar covenant, qualifications, exceptions and limitations as our 2023 Senior Unsecured
136
Notes
and 2025 Senior Unsecured Notes. We used the net proceeds received from the issuance of our 2024 Senior Unsecured Notes to replenish cash on hand used for the acquisition of Fore River Energy Center in the fourth quarter of 2014, to repurchase approximately $147 million of our 2023 First Lien Notes and for general corporate purposes. We recorded approximately $9 million in debt issuance costs related to the issuance of our 2024 Senior Unsecured Notes and approximately $19 million in debt extinguishment costs during the first quarter of 2015 related to the partial repurchase of our 2023 First Lien Notes.
On July 22, 2014, we issued $1.25 billion in aggregate principal amount of 5.375%
senior unsecured notes due 2023 and $1.55 billion in aggregate principal amount of 5.75% senior unsecured notes due 2025 in a public offering. The 2023 Senior Unsecured Notes bear interest at 5.375% per annum and the 2025 Senior Unsecured Notes bear interest at 5.75% per annum, in each case payable semi-annually on April 15 and October 15 of each year, beginning on April 15, 2015. The 2023 Senior Unsecured Notes mature on January 15, 2023 and the 2025 Senior Unsecured Notes mature on January 15, 2025. Our Senior Unsecured Notes were issued at par.
Our Senior Unsecured Notes are:
•
general
unsecured obligations of Calpine;
•
rank equally in right of payment with all of Calpine’s existing and future senior indebtedness;
•
effectively subordinated to Calpine’s secured indebtedness to the extent of the value of the collateral securing such indebtedness;
•
structurally subordinated
to any existing and future indebtedness and other liabilities of Calpine’s subsidiaries; and
•
senior in right of payment to any of Calpine’s subordinated indebtedness.
First Lien Term Loans
Our First Lien Term Loans are summarized in the table below (in millions, except for interest rates):
Outstanding
at December 31,
Weighted Average
Effective Interest Rates(1)
2017
2016
2017
2016
2017 First Lien Term Loan
$
—
$
537
—
%
5.0
%
2019
First Lien Term Loan
389
—
4.1
—
2023 First Lien Term Loans
1,064
1,071
4.6
4.5
2024
First Lien Term Loan
1,542
1,557
4.2
3.8
Total First Lien Term Loans
$
2,995
$
3,165
____________
(1)
Our
weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount.
On December 11, 2017, we repriced our 2023 First Lien Term Loans and 2024 First Lien Term Loan by lowering the margin over LIBOR by 0.25% to 2.50%.
On February 3, 2017, we entered into a $400 million first lien senior secured term loan which bears interest, at our option, at either (i) the Base Rate, equal to the highest of (a) the Federal Funds Effective Rate plus 0.50% per annum, (b) the Prime Rate or (c) the Eurodollar Rate for a one month interest period plus 1.0%
(in each case, as such terms are defined in the 2019 First Lien Term Loan credit agreement), plus an applicable margin of 0.75%, or (ii) LIBOR plus 1.75% per annum (with no LIBOR floor) and matures on December 31, 2019. An aggregate amount equal to 0.25% of the aggregate principal amount of the 2019 First Lien Term Loans is payable at the end of each quarter (beginning with the quarter ending June 2017) with the remaining balance payable on the maturity date. We paid an upfront fee of an amount equal to 1.0% of the aggregate principal amount of the 2019 First Lien Term Loan, which is structured as original issue discount and recorded approximately $8 million in
debt issuance costs during the first quarter of 2017 related to the issuance of our 2019 First Lien Term Loan. The 2019 First Lien Term Loan contains substantially similar covenants, qualifications, exceptions and limitations as other First Lien Term Loans and the First Lien Notes. We used the proceeds from the 2019 First Lien Term Loan, together with cash on hand, to redeem the remaining 2023 First Lien Notes.
On December 1, 2016, we entered into a $550 million first lien senior secured term loan to partially fund the acquisition of Calpine Solutions. We fully repaid the 2017 First Lien Term Loan and recorded $4 million in debt extinguishment costs related to the repayment during the year ended December 31, 2017.
137
On May 31, 2016, we entered into a $562 million first lien senior secured term loan which bears interest, at our option, at either (i) the Base Rate, equal to the highest of (a) the Federal Funds Effective Rate plus 0.50% per annum, (b) the Prime Rate or (c) the Eurodollar Rate for a one month interest period plus 1.0% (in each case, as such terms are defined in the credit agreement), plus an applicable margin of 2.00%, or (ii) LIBOR plus 2.75% per annum (with no LIBOR floor) and matures on May
31, 2023. An aggregate amount equal to 0.25% of the aggregate principal amount of the 2023 First Lien Term Loans is payable at the end of each quarter with the remaining balance payable on the maturity date. We paid an upfront fee of an amount equal to 1.0% of the aggregate principal amount of the 2023 First Lien Term Loans, which is structured as original issue discount and recorded approximately $11 million in debt issuance costs during the second quarter of 2016 related to the issuance of this portion of our 2023 First Lien Term Loans. The 2023 First Lien Term Loans contains substantially similar covenants, qualifications, exceptions and limitations as other First Lien Term Loans and the First Lien Notes. We used the proceeds from this portion of our 2023 First Lien Term Loans and a portion of our 2026 First Lien Notes, discussed
below, to repay portion of our First Lien Term Loans with maturity dates in 2019 and 2020 and recorded $15 million in debt extinguishment costs during the second quarter of 2016 associated with the repayment.
First Lien Notes
Our First Lien Notes are summarized in the table below (in millions, except for interest rates):
Outstanding
at December 31,
Weighted Average Effective Interest Rates(1)
2017
2016
2017
2016
2022 First Lien Notes
$
741
$
739
6.4
%
6.4
%
2023
First Lien Notes(2)
—
450
8.1
8.1
2024 First Lien Notes
485
485
6.1
6.1
2026
First Lien Notes
1,170
616
5.5
5.4
Total First Lien Notes
$
2,396
$
2,290
____________
(1)
Our
weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount.
(2)
On March 6, 2017, we used cash on hand along with the proceeds from our 2019 First Lien Term Loan to redeem the remaining $453 million of our 2023 First Lien Notes, plus accrued and unpaid interest. During the first quarter of 2017, we recorded approximately $21 million in debt extinguishment costs related to the redemption of our 2023 First Lien Notes.
On December 15, 2017, we issued
$560 million in aggregate principal amount of 5.25% senior secured notes due 2026 in a private placement. Additionally, on May 31, 2016, we issued $625 million in aggregate principal amount of 5.25% senior secured notes due 2026 in a private placement. Our 2026 First Lien Notes bear interest at 5.25% payable semi-annually on June 1 and December 1 of each year. Our 2026 First Lien Notes mature on June 1, 2026 and contain substantially similar covenants, qualifications, exceptions and limitations as our First Lien Notes. We recorded approximately $8 million in debt issuance costs during the fourth quarter
of 2017 related to the issuance of a portion of our 2026 First Lien Notes and approximately $9 million in debt issuance costs during the second quarter of 2016 related to the issuance of a portion of our 2026 First Lien Notes.
Our First Lien Notes are secured equally and ratably with indebtedness incurred under our First Lien Term Loans and Corporate Revolving Facility, subject to certain exceptions and permitted liens, on substantially all of our and certain of the guarantors’ existing and future assets. Additionally, our First Lien Notes rank equally in right of payment with all of our and the guarantors’ other existing and future senior indebtedness, and will be effectively subordinated in right of payment to all existing and future liabilities of our subsidiaries that do not guarantee
our First Lien Notes.
Subject to certain qualifications and exceptions, our First Lien Notes will, among other things, limit our ability and the ability of the guarantors to:
•
incur or guarantee additional first lien indebtedness;
•
enter into certain types of commodity hedge agreements that can be secured by first lien collateral;
•
enter
into sale and leaseback transactions;
•
create or incur liens; and
138
•
consolidate, merge or transfer all or substantially all of our assets and the assets of our restricted subsidiaries on a combined basis.
Project
Financing, Notes Payable and Other
The components of our project financing, notes payable and other are (in millions, except for interest rates):
Outstanding at
December 31,
Weighted Average
Effective Interest Rates(1)
2017
2016
2017
2016
Russell
City due 2023
$
401
$
462
6.4
%
6.5
%
Steamboat due 2025
414
444
4.7
5.4
OMEC
due 2019
294
303
7.2
7.2
Los Esteros due 2023
191
217
5.3
3.7
Pasadena(2)
89
91
8.9
8.9
Bethpage
Energy Center 3 due 2020-2025(3)
60
66
7.1
7.2
Other
49
14
—
—
Total
$
1,498
$
1,597
_____________
(1)
Our
weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount.
(2)
Represents a failed sale-leaseback transaction that is accounted for as financing transaction under U.S. GAAP.
(3)
Represents a weighted average of first and second lien loans for the weighted average effective interest rates.
Our project financings are collateralized solely by the capital stock or partnership interests, physical assets, contracts
and/or cash flows attributable to the entities that own the power plants. The lenders’ recourse under these project financings is limited to such collateral.
CCFC Term Loan and CCFC Term Loans
Our CCFC Term Loan and CCFC Term Loans are summarized in the table below (in millions, except for interest rates):
Outstanding at December 31,
Weighted Average
Effective Interest Rates(1)
2017
2016
2017
2016
CCFC
Term Loan
$
984
$
—
4.6
%
—
%
CCFC Term Loans
$
—
$
1,553
—
%
3.5
%
____________
(1)
Our
weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount.
On December 15, 2017, CCFC entered into a credit agreement providing for a first lien senior secured term loan facility for $1.0 billion. The CCFC Term Loan bears interest, at CCFC’s option, at either (i) the Base Rate, equal to the higher of (a) the Federal Funds Effective Rate plus 0.5% per annum, (b) the Prime Rate or (c) the Eurodollar Rate (as such terms are defined in the Credit Agreement) plus 1% per annum, plus an applicable margin of 1.5% per annum, or (ii) LIBOR plus 2.5% per annum. The CCFC Term Loan was offered
to investors at an issue price equal to 99.875% of face value.
An aggregate amount equal to 0.25% of the aggregate principal amount of the CCFC Term Loan will be payable at the end of each quarter commencing in March 2018, with the remaining balance payable on the maturity date (January 15, 2025). CCFC may elect from time to time to convert all or a portion of the CCFC Term Loan from LIBOR rate loans to Base Rate loans or vice versa. In addition, CCFC may at any time, and from time to time, prepay the CCFC Term Loan, in whole or in part, without premium or penalty (except as provided in the immediately succeeding paragraph), upon irrevocable notice to the Administrative Agent. Partial prepayments shall be in an aggregate minimum principal amount of $1 million,
provided that any prepayment shall be first applied to any portion of the CCFC Term Loan that is designated as Base Rate loans and then LIBOR rate loans.
139
CCFC may also reprice the CCFC Term Loan, subject to approval from the Lenders (as defined in the Credit Agreement). If a repricing transaction that results in a prepayment is consummated prior to June 15, 2018, CCFC will pay the Administrative Agent fees consisting of a prepayment premium of 1% of the principal amount that is being prepaid. If a repricing transaction that results in an amendment of the CCFC Term Loan is consummated prior to June 15, 2018, CCFC
will pay the Administrative Agent fees of 1% of the aggregate amount of the CCFC Term Loan outstanding immediately prior to such repricing transaction. CCFC may elect to extend the maturity of any CCFC Term Loan, in whole or in part, subject to approval from those lenders (as defined in the Credit Agreement) holding such CCFC Term Loan.
Subject to certain qualifications and exceptions, the Credit Agreement will, among other things, limit CCFC’s ability and the ability of the guarantors of the CCFC Term Loan to:
•
incur or guarantee additional first lien indebtedness;
•
enter
into sale and leaseback transactions;
•
create liens;
•
consummate certain asset sales;
•
make certain non-cash restricted payments; and
•
consolidate,
merge or transfer all or substantially all of CCFC’s assets and the assets of CCFC’s restricted subsidiaries on a combined basis.
We utilized the proceeds received from a portion of our 2026 First Lien Notes (discussed above) and the CCFC Term Loan, together with operating cash on hand, to fully repay the CCFC Term Loans and recorded approximately $13 million in debt issuance costs during the fourth quarter of 2017. We recorded approximately $12 million in debt extinguishment costs associated with the repayment of our CCFC Term Loans during the fourth quarter of 2017.
The CCFC Term Loan is secured by certain real and personal property of CCFC consisting primarily of six natural gas-fired
power plants. The CCFC Term Loan is not guaranteed by Calpine Corporation and is without recourse to Calpine Corporation or any of our non-CCFC subsidiaries or assets; however, CCFC generates the majority of its cash flows from an intercompany tolling agreement with Calpine Energy Services, L.P. and has various service agreements in place with other subsidiaries of Calpine Corporation.
Capital Lease Obligations
The following is a schedule by year of future minimum lease payments under capital leases and a failed sale-leaseback transaction related to our Pasadena Power Plant together with the present value of the net minimum lease payments as of December 31,
2017 (in millions):
Sale-Leaseback Transactions(1)
Capital Lease
Total
2018
$
21
$
19
$
40
2019
21
19
40
2020
21
19
40
2021
21
18
39
2022
16
17
33
Thereafter
26
93
119
Total
minimum lease payments
126
185
311
Less: Amount representing interest
37
70
107
Present
value of net minimum lease payments
$
89
$
115
$
204
____________
(1)
Amounts
are accounted for as financing transactions under U.S. GAAP and are included in our project financing, notes payable and other amounts above.
140
The primary types of property leased by us are power plants and related equipment. The leases generally provide for the lessee to pay taxes, maintenance, insurance, and certain other operating costs of the leased property. The remaining lease terms range up to 34 years (including lease renewal options). Some of the lease agreements contain customary restrictions on dividends up to Calpine Corporation, additional debt and further encumbrances similar to those typically found in project financing agreements. At December 31,
2017 and 2016, the asset balances for the leased assets totaled approximately $737 million and $864 million with accumulated amortization of $349 million and $404 million, respectively. Amortization of assets under capital leases is recorded in depreciation and amortization expense on our Consolidated Statements of Operations. See Note 16 for discussion of capital leases guaranteed by Calpine Corporation.
Corporate Revolving Facility and Other Letters of Credit Facilities
The table below represents amounts issued under our letter of credit facilities at December 31,
2017 and 2016 (in millions):
2017
2016
Corporate Revolving Facility
$
629
$
535
CDHI
244
250
Various
project financing facilities
196
206
Total
$
1,069
$
991
On
February 8, 2016, we amended our Corporate Revolving Facility, extending the maturity by two years to June 27, 2020, and increasing the capacity by an additional $178 million to $1,678 million through June 27, 2018, reverting back to $1,520 million through the maturity date. Further, we increased the letter of credit sublimit by $250 million to $1.0 billion and extended the maturity by two years to June 27, 2020.
On December
1, 2016, we amended our Corporate Revolving Facility, increasing the capacity by $112 million to $1,790 million for the full term through June 27, 2020 and increased the letter of credit capacity from $1.0 billion to $1.15 billion.
The Corporate Revolving Facility represents our primary revolving facility. Borrowings under the Corporate Revolving Facility bear interest, at our option, at either a base rate or LIBOR rate. Base rate borrowings shall be at the base rate, plus an applicable margin ranging from 1.00% to 1.25% as provided in the Corporate Revolving Facility credit agreement. Base rate is
defined as the higher of (i) the Federal Funds Effective Rate, as published by the Federal Reserve Bank of New York, plus 0.50% and (ii) the rate the administrative agent announces from time to time as its prime per annum rate. LIBOR rate borrowings shall be at the British Bankers’ Association Interest Settlement Rates for the interest period as selected by us as a one, two, three, six or, if agreed by all relevant lenders, nine or twelve month interest period, plus an applicable margin ranging from 2.00% to 2.25%. Interest payments are due on the last
business day of each calendar quarter for base rate loans and the earlier of (i) the last day of the interest period selected or (ii) each day that is three months (or a whole multiple thereof) after the first day for the interest period selected for LIBOR rate loans. Letter of credit fees for issuances of letters of credit include fronting fees equal to that percentage per annum as may be separately agreed upon between us and the issuing lenders and a participation fee for the lenders equal to the applicable interest margin for LIBOR rate borrowings. Drawings under letters of credit shall be repaid within two business days or be converted into borrowings as provided in the Corporate Revolving Facility credit agreement. We incur an unused commitment fee ranging from 0.25% to 0.50% on the unused amount of commitments under the Corporate
Revolving Facility.
The Corporate Revolving Facility does not contain any requirements for mandatory prepayments, except in the case of certain designated asset sales in excess of $3.0 billion in the aggregate. However, we may voluntarily repay, in whole or in part, the Corporate Revolving Facility, together with any accrued but unpaid interest, with prior notice and without premium or penalty. Amounts repaid may be reborrowed, and we may also voluntarily reduce the commitments under the Corporate Revolving Facility without premium or penalty.
The Corporate Revolving Facility is guaranteed and secured by certain of our current domestic subsidiaries and will also be additionally guaranteed by our future domestic subsidiaries
that are required to provide such a guarantee in accordance with the terms of the Corporate Revolving Facility. The Corporate Revolving Facility ranks equally in right of payment with all of our and the guarantors’ other existing and future senior indebtedness and will be effectively subordinated in right of payment to all existing and future liabilities of our subsidiaries that do not guarantee the Corporate Revolving Facility. The Corporate Revolving Facility also requires compliance with financial covenants that include a minimum cash interest coverage ratio and a maximum net leverage ratio.
On September 15, 2017, we amended our Corporate Revolving Facility to, among other things, provide that the Merger does not constitute a “Change of Control” thereunder, effective upon consummation
of the Merger. On October 20, 2017, we
141
further amended our Corporate Revolving Facility to extend the maturity of certain revolving commitments and reduce the capacity thereunder from $1.79 billion to $1.47 billion. Both amendments to the Corporate Revolving Facility are effective upon consummation of the Merger. See Note 2 for further information related to the Merger.
CDHI
We have a $300 million letter of credit facility related to CDHI. During the fourth quarter of 2017, we amended
our CDHI letter of credit facility to extend the maturity to October 2, 2021.
Fair Value of Debt
We record our debt instruments based on contractual terms, net of any applicable premium or discount. The following table details the fair values and carrying values of our debt instruments at December 31, 2017 and 2016 (in millions):
2017
2016
Fair Value
Carrying Value
Fair Value
Carrying
Value
Senior
Unsecured Notes
$
3,294
$
3,417
$
3,343
$
3,412
First
Lien Term Loans
3,043
2,995
3,244
3,165
First Lien Notes
2,437
2,396
2,349
2,290
Project
financing, notes payable and other(1)
1,439
1,409
1,543
1,506
CCFC Term Loan and CCFC Term Loans
1,000
984
1,567
1,553
Total
$
11,213
$
11,201
$
12,046
$
11,926
____________
(1)
Excludes
a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP.
We measure the fair value of our Senior Unsecured Notes, First Lien Term Loans, First Lien Notes, CCFC Term Loan and CCFC Term Loans using market information, including quoted market prices or dealer quotes for the identical liability when traded as an asset (categorized as level 2). We measure the fair value of our project financing, notes payable and other debt instruments using discounted cash flow analyses based on our current borrowing rates for similar types of borrowing arrangements (categorized as level 3). We do not have any debt instruments with fair value measurements categorized as level 1 within the fair value hierarchy.
8.
Assets
and Liabilities with Recurring Fair Value Measurements
Cash Equivalents — Highly liquid investments which meet the definition of cash equivalents, primarily investments in money market accounts and other interest-bearing accounts, are included in both our cash and cash equivalents and our restricted cash on our Consolidated Balance Sheets. Certain of our money market accounts invest in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities. We do not have any cash equivalents invested in institutional prime money market funds which require use of a floating net asset value and are subject to liquidity fees and redemption restrictions. Certain of our cash equivalents are classified within level 1 of the fair value hierarchy.
Derivatives — The primary
factors affecting the fair value of our derivative instruments at any point in time are the volume of open derivative positions (MMBtu, MWh and $ notional amounts); changing commodity market prices, primarily for power and natural gas; our credit standing and that of our counterparties and customers for energy commodity derivatives; and prevailing interest rates for our interest rate hedging instruments. Prices for power and natural gas and interest rates are volatile, which can result in material changes in the fair value measurements reported in our financial statements in the future.
We utilize market data, such as pricing services and broker quotes, and assumptions that we believe market participants would use in pricing our assets or liabilities including assumptions about the risks inherent to the inputs in the valuation technique. These inputs can be either readily observable, market corroborated or generally unobservable.
The market data obtained from broker pricing services is evaluated to determine the nature of the quotes obtained and, where accepted as a reliable quote, used to validate our assessment of fair value. We use other qualitative assessments to determine the level of activity in any given market. We primarily apply the market approach and income approach for recurring fair value measurements and utilize what we believe to be the best available information. We utilize valuation techniques that seek to maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the observability of those inputs.
142
The fair value of our derivatives includes consideration of our credit standing, the credit standing
of our counterparties and customers and the effect of credit enhancements, if any. We have also recorded credit reserves in the determination of fair value based on our expectation of how market participants would determine fair value. Such valuation adjustments are generally based on market evidence, if available, or our best estimate.
Our level 1 fair value derivative instruments primarily consist of power and natural gas swaps, futures and options traded on the NYMEX or Intercontinental Exchange.
Our level 2 fair value derivative instruments primarily consist of interest rate hedging instruments and OTC power and natural gas forwards for which market-based pricing inputs in the principal or most advantageous market are representative of executable prices for market participants. These inputs are observable at commonly quoted intervals for substantially the full term of the instruments.
In certain instances, our level 2 derivative instruments may utilize models to measure fair value. These models are industry-standard models, including the Black-Scholes option-pricing model, that incorporate various assumptions, including quoted interest rates, correlation, volatility, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Our level 3 fair value derivative instruments may consist of OTC power and natural gas forwards and options where pricing inputs are unobservable, as well as other complex and structured transactions primarily for the sale and purchase of power and natural gas to both wholesale counterparties and retail customers. Complex or structured transactions are tailored
to our customers’ needs and can introduce the need for internally-developed model inputs which might not be observable in or corroborated by the market. When such inputs have a significant effect on the measurement of fair value, the instrument is categorized in level 3. Our valuation models may incorporate historical correlation information and extrapolate available broker and other information to future periods.
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement at period end. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect our estimate of the fair value of our assets and liabilities and their placement within the fair value hierarchy levels. The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring
basis as of December 31, 2017 and 2016, by level within the fair value hierarchy:
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2017
Effect of netting and allocation of collateral(3)(4)
(1,570
)
(215
)
(34
)
(1,819
)
Total
liabilities
$
—
$
254
$
33
$
287
___________
(1)
As
of December 31, 2017 and 2016, we had cash equivalents of $21 million and $26 million included in cash and cash equivalents and $110 million and $127 million included in restricted cash, respectively.
(2)
Includes OTC swaps and options.
(3)
During
the third quarter of 2017, we elected to offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation; therefore, amounts recognized for the right to reclaim, or the obligation to return, cash collateral are presented net with the corresponding derivative instrument fair values. See Note 3 for a further description of the change in accounting principle associated with our election to offset fair value amounts associated with our derivative instruments. See Note 9 for further discussion of our derivative instruments subject to master netting arrangements.
(4)
Cash collateral posted with (received from) counterparties allocated to level
1, level 2 and level 3 derivative instruments totaled $44 million, $18 million and nil, respectively, at December 31, 2017. Cash collateral posted with (received from) counterparties allocated to level 1, level 2 and level 3 derivative instruments totaled $28 million, $27 million and $17 million, respectively, at December 31, 2016.
At December 31, 2017
and 2016, the derivative instruments classified as level 3 primarily included commodity contracts, which are classified as level 3 because the contract terms relate to a delivery location or tenor for which observable market rate information is not available. The fair value of the net derivative position classified as level 3 is predominantly driven by market commodity prices. The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at December 31, 2017 and 2016:
Quantitative
Information about Level 3 Fair Value Measurements
The
following table sets forth a reconciliation of changes in the fair value of our net derivative assets (liabilities) classified as level 3 in the fair value hierarchy for the years ended December 31, 2017, 2016 and 2015 (in millions):
2017
2016
2015
Balance,
beginning of period
$
416
$
(46
)
$
95
Realized and mark-to-market gains (losses):
Included
in net income:
Included in operating revenues(1)
32
(46
)
218
Included
in fuel and purchased energy expense(2)
50
7
(7
)
Change in collateral
(17
)
17
(10
)
Purchases,
issuances and settlements:
Purchases(3)
4
426
(70
)
Issuances
(1
)
—
—
Settlements
(179
)
(21
)
(29
)
Transfers
in and/or out of level 3(4):
Transfers into level 3(5)
(2
)
4
—
Transfers
out of level 3(6)
(106
)
75
(243
)
Balance, end of period
$
197
$
416
$
(46
)
Change
in unrealized gains (losses) relating to instruments still held at end of period
$
82
$
(39
)
$
211
___________
(1)
For
power contracts and other power-related products, included on our Consolidated Statements of Operations.
(2)
For natural gas and power contracts, swaps and options, included on our Consolidated Statements of Operations.
(3)
During December 2016, we had $421 million in purchases related to the
acquisition of Calpine Solutions, formerly Noble Solutions.
(4)
We transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no transfers into or out of level 1 during the years ended December 31, 2017, 2016 and 2015.
(5)
We had $(2)
million in losses, $4 million in gains and nil transfers out of level 2 into level 3 for the years ended December 31, 2017, 2016 and 2015, respectively.
(6)
We had $104 million in gains and $(75) million in losses and $4 million in gains transferred out of level 3 into level 2 during the years ended December 31,
2017, 2016 and 2015, respectively, due to changes in market liquidity in various power markets and $2 million and $239 million in gains transferred out of level 3 during the years ended December 31, 2017 and 2015, respectively, to other assets following the election of the normal purchase normal sales exemption and the discontinuance of derivative accounting treatment as of the date of this election for certain commodity contracts.
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9.
Derivative
Instruments
Types of Derivative Instruments and Volumetric Information
Commodity Instruments — We are exposed to changes in prices for the purchase and sale of power, natural gas, fuel oil, environmental products and other energy commodities. We use derivatives, which include physical commodity contracts and financial commodity instruments such as OTC and exchange traded swaps, futures, options, forward agreements and instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) or instruments that settle on power or natural gas price relationships between delivery points for the purchase and sale of power and natural gas to attempt to maximize the risk-adjusted returns by economically hedging a portion
of the commodity price risk associated with our assets. By entering into these transactions, we are able to economically hedge a portion of our Spark Spread at estimated generation and prevailing price levels.
We also engage in limited trading activities related to our commodity derivative portfolio as authorized by our Board of Directors and monitored by our Chief Risk Officer and Risk Management Committee of senior management. These transactions are executed primarily for the purpose of providing improved price and price volatility discovery, greater market access, and profiting from our market knowledge, all of which benefit our asset hedging activities. Our trading results were not material for the years ended December 31, 2017, 2016 and 2015.
Interest
Rate Hedging Instruments — A portion of our debt is indexed to base rates, primarily LIBOR. We have historically used interest rate hedging instruments to adjust the mix between fixed and variable rate debt to hedge our interest rate risk for potential adverse changes in interest rates. As of December 31, 2017, the maximum length of time over which we were hedging using interest rate hedging instruments designated as cash flow hedges was 8 years.
As of December 31, 2017 and 2016, the net forward notional buy (sell) position of our outstanding commodity derivative instruments
that did not qualify or were not designated under the normal purchase normal sale exemption and our interest rate hedging instruments were as follows (in millions):
Derivative Instruments
Notional Amounts
2017
2016
Power
(MWh)
(119
)
(86
)
Natural gas (MMBtu)
405
613
Environmental
credits (Tonnes)
12
16
Interest rate hedging instruments
$
4,600
(1)
$
3,721
___________
(1)
We
entered into interest rate hedging instruments during the first quarter of 2017 to hedge approximately $1.0 billion of variable rate debt for 2018 through 2020 and approximately $500 million of variable rate debt for 2021 through 2022.We also extended the tenor of certain interest rate hedging instruments, which effectively places a ceiling on LIBOR on $2.5 billion of variable rate corporate debt through 2020 and $1.25 billion of variable rate corporate debt in 2021.
Certain of our derivative instruments contain credit risk-related contingent provisions that require us to maintain collateral balances consistent with our credit ratings. If our credit rating were to be downgraded, it could require us to post additional collateral
or could potentially allow our counterparty to request immediate, full settlement on certain derivative instruments in liability positions. The aggregate fair value of our derivative liabilities with credit risk-related contingent provisions as of December 31, 2017, was $218 million for which we have posted collateral of $119 million by posting margin deposits or granting additional first priority liens on the assets currently subject to first priority liens under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. However, if our credit rating were downgraded by one notch from its current level, we estimate that additional collateral of $10 million related to our derivative liabilities would be required and
that no counterparty could request immediate, full settlement.
Accounting for Derivative Instruments
We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Statements of Operations until the period of delivery. Revenues and expenses derived from instruments that qualified for hedge accounting or represent an economic hedge are recorded in the same financial statement line item as the item being hedged. Hedge accounting requires us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting.
146
We present the cash flows from our derivatives in the same category as the item being hedged (or economically hedged) within operating activities on our Consolidated Statements of Cash Flows unless they contain an other-than-insignificant financing element in which case their cash flows are classified within financing activities.
Cash Flow Hedges — We currently apply hedge accounting to our interest rate hedging instruments. We report the effective portion of the mark-to-market gain or loss on our interest rate hedging instruments designated and qualifying as a cash flow hedging instrument as a component of OCI and reclassify such gains and losses into earnings in the same period during which the hedged forecasted transaction affects earnings. Gains and losses
due to ineffectiveness on interest rate hedging instruments are recognized currently in earnings as a component of interest expense. If it is determined that the forecasted transaction is no longer probable of occurring, then hedge accounting will be discontinued prospectively and future changes in fair value are recorded in earnings. If the hedging instrument is terminated or de-designated prior to the occurrence of the hedged forecasted transaction, the net accumulated gain or loss associated with the changes in fair value of the hedge instrument remains deferred in AOCI until such time as the forecasted transaction affects earnings or until it is determined that the forecasted transaction is probable of not occurring.
Derivatives Not Designated as Hedging Instruments — We enter into power, natural gas, interest rate, environmental product and fuel oil transactions that primarily act as economic hedges
to our asset and interest rate portfolio, but either do not qualify as hedges under the hedge accounting guidelines or qualify under the hedge accounting guidelines and the hedge accounting designation has not been elected. Changes in fair value of commodity derivatives not designated as hedging instruments are recognized currently in earnings and are separately stated on our Consolidated Statements of Operations in mark-to-market gain/loss as a component of operating revenues (for physical and financial power and Heat Rate and commodity option activity) and fuel and purchased energy expense (for physical and financial natural gas, power, environmental product and fuel oil activity). Changes in fair value of interest rate derivatives not designated as hedging instruments are recognized currently in earnings as interest expense.
Derivatives Included on Our Consolidated Balance Sheets
During
the third quarter of 2017, we elected to begin offsetting fair value amounts associated with our derivative instruments and related cash collateral and margin deposits on our Consolidated Balance Sheets that are executed with the same counterparty under master netting arrangements. Our netting arrangements include a right to set off or net together purchases and sales of similar products in the margining or settlement process. In some instances, we have also negotiated cross commodity netting rights which allow for the net presentation of activity with a given counterparty regardless of product purchased or sold. We also post cash collateral in support of our derivative instruments which may also be subject to a master netting arrangement with the same counterparty. See Note 3 for a further description of the change in accounting principle associated with our election to offset fair value amounts associated with our derivative instruments.
147
The following tables present the fair values of our derivative instruments and our net exposure after offsetting amounts subject to a master netting arrangement with the same counterparty to our derivative instruments recorded on our Consolidated Balance Sheets by location and hedge type at December 31, 2017 and 2016 (in millions):
At
December 31, 2017 and 2016, we had $155 million and $262 million of collateral under master netting arrangements that were not offset against our derivative instruments on the Consolidated Balance Sheets.
(2)
At December 31, 2017, current and long-term derivative assets are shown net of collateral of $(8) million and $(2)
million, respectively, and current and long-term derivative liabilities are shown net of collateral of $52 million and $20 million, respectively.
(3)
At December 31, 2016, current and long-term derivative assets are shown net of collateral of $(29) million and $(3) million, respectively, and current and long-term derivative liabilities are shown net of collateral of $19 million and $85
million, respectively.
Derivatives
designated as cash flow hedging instruments:
Interest rate hedging instruments
$
26
$
31
$
29
$
58
Total
derivatives designated as cash flow hedging instruments
$
26
$
31
$
29
$
58
Derivatives
not designated as hedging instruments:
Commodity instruments
$
366
$
285
$
492
$
229
Total
derivatives not designated as hedging instruments
$
366
$
285
$
492
$
229
Total
derivatives
$
392
$
316
$
521
$
287
149
Derivatives Included on Our Consolidated Statements of Operations
Changes in the fair values of our derivative instruments are reflected either in cash for option premiums paid or collected, in OCI, net of tax, for the effective portion of derivative instruments which qualify for and we have elected cash flow hedge accounting treatment, or on our Consolidated Statements of Operations as a component of mark-to-market activity within our earnings.
The following tables detail the components of our total activity for both the net realized gain (loss) and the net mark-to-market gain (loss) recognized from our derivative instruments in earnings and where these components were recorded on our Consolidated Statements of Operations for the years ended
December 31, 2017, 2016 and 2015 (in millions):
2017
2016
2015
Realized
gain (loss)(1)(2)
Commodity derivative instruments
$
7
$
235
$
450
Total
realized gain
$
7
$
235
$
450
Mark-to-market
gain (loss)(3)
Commodity derivative instruments
$
(171
)
$
(1
)
$
(113
)
Interest
rate hedging instruments
2
2
3
Total mark-to-market gain (loss)
$
(169
)
$
1
$
(110
)
Total
activity, net
$
(162
)
$
236
$
340
___________
(1)
Does
not include the realized value associated with derivative instruments that settle through physical delivery.
(2)
Includes amortization of acquisition date fair value of financial derivative activity related to the acquisition of Champion Energy, Calpine Solutions and North American Power.
(3)
In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.
2017
2016
2015
Realized
and mark-to-market gain (loss)(1)
Derivatives contracts included in operating revenues(2)(3)
$
(69
)
$
109
$
528
Derivatives
contracts included in fuel and purchased energy expense(2)(3)
(95
)
125
(191
)
Interest rate hedging instruments included in interest expense(4)
2
2
3
Total
activity, net
$
(162
)
$
236
$
340
___________
(1)
In
addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes adjustments to reflect changes in credit default risk exposure.
(2)
Does not include the realized value associated with derivative instruments that settle through physical delivery.
(3)
Includes amortization of acquisition date fair value of financial derivative activity related to the acquisition of Champion Energy, Calpine Solutions and North American Power.
(4)
In
addition to changes in market value on interest rate hedging instruments not designated as hedges, changes in mark-to-market gain (loss) also includes hedge ineffectiveness.
150
Derivatives Included in OCI and AOCI
The following table details the effect of our net derivative instruments that qualified for hedge accounting treatment and are included in OCI and AOCI for the years ended December 31, 2017, 2016 and 2015 (in millions):
Gains (Loss) Recognized
in
OCI (Effective Portion)
Gain (Loss) Reclassified from
AOCI into Income (Effective
Portion)(3)(4)
2017
2016
2015
2017
2016
2015
Affected
Line Item on the Consolidated Statements of Operations
Interest rate hedging instruments(1)(2)
$
21
$
41
$
23
$
(43
)
$
(43
)
$
(47
)
Interest
expense
Interest rate hedging instruments(1)(2)
$
5
$
—
$
—
$
(5
)
$
—
$
—
Depreciation
expense
Total
$
26
$
41
$
23
$
(48
)
$
(43
)
$
(47
)
____________
(1)
We
recorded a gain of $1 million on hedge ineffectiveness related to our interest rate hedging instruments designated as cash flow hedges during the year ended December 31, 2017. We did not record any material gain (loss) on hedge ineffectiveness related to our interest rate hedging instruments designated as cash flow hedges during the years ended December 31, 2016 and 2015.
(2)
We recorded income tax expense of $6
million, $1 million and nil for the years ended December 31, 2017, 2016 and 2015, respectively, in AOCI related to our cash flow hedging activities.
(3)
Cumulative cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $72 million, $90 million and $127 million at December 31,
2017, 2016 and 2015, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $6 million, $8 million and $11 million at December 31, 2017, 2016 and 2015, respectively.
(4)
Includes losses of nil,
$3 million and nil that were reclassified from AOCI to interest expense for the years ended December 31, 2017, 2016 and 2015, respectively, where the hedged transactions became probable of not occurring.
We estimate that pre-tax net losses of $20 million would be reclassified from AOCI into interest expense during the next 12 months as the hedged transactions settle; however, the actual amounts that will be reclassified will likely vary based on changes in interest rates. Therefore, we are unable to predict what the actual reclassification from AOCI into earnings (positive or negative)
will be for the next 12 months.
10.
Use of Collateral
We use margin deposits, prepayments and letters of credit as credit support with and from our counterparties for commodity procurement and risk management activities. In addition, we have granted additional first priority liens on the assets currently subject to first priority liens under various debt agreements as collateral under certain of our power and natural gas agreements and certain of our interest rate hedging instruments in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to the counterparties under such agreements.
The counterparties under such agreements share the benefits of the collateral subject to such first priority liens pro rata with the lenders under our various debt agreements.
151
The table below summarizes the balances outstanding under margin deposits, natural gas and power prepayments, and exposure under letters of credit and first priority liens for commodity procurement and risk management activities as of December 31, 2017 and 2016 (in millions):
2017
2016
Margin
deposits(1)
$
221
$
350
Natural gas and power prepayments
23
25
Total
margin deposits and natural gas and power prepayments with our counterparties(2)
$
244
$
375
Letters of credit issued
$
885
$
798
First
priority liens under power and natural gas agreements
102
206
First priority liens under interest rate hedging instruments
31
55
Total
letters of credit and first priority liens with our counterparties
$
1,018
$
1,059
Margin deposits posted with us by our counterparties(1)(3)
$
4
$
16
Letters
of credit posted with us by our counterparties
30
43
Total margin deposits and letters of credit posted with us by our counterparties
$
34
$
59
___________
(1)
During
the third quarter of 2017, we elected to offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation; therefore, amounts recognized for the right to reclaim, or the obligation to return, cash collateral are presented net with the corresponding derivative instrument fair values. See Note 3 for a further description of the change in accounting principle associated with our election to offset fair value amounts associated with our derivative instruments. See Note 9 for further discussion of our derivative instruments subject to master netting arrangements.
(2)
At December 31,
2017 and 2016, $64 million and $78 million, respectively, were included in current and long-term derivative assets and liabilities, $171 million and $288 million, respectively, were included in margin deposits and other prepaid expense and $9 million and $9 million, respectively, were included in other assets on our Consolidated Balance Sheets.
(3)
At
December 31, 2017 and 2016, $2 million and $6 million, respectively, were included in current and long-term derivative assets and liabilities and $2 million and $10 million, respectively, were included in other current liabilities on our Consolidated Balance Sheets.
Future collateral requirements for cash, first priority liens and letters of credit may increase or decrease based on the extent of our involvement in hedging and optimization contracts,
movements in commodity prices, and also based on our credit ratings and general perception of creditworthiness in our market.
11.
Income Taxes
Tax Cuts and Jobs Act (the “Act”)
On December 22, 2017, the Act was signed into law resulting in significant changes from previous tax law. Some of the more meaningful provisions which will affect us are:
•
a
reduction in the U.S. federal corporate tax rate from 35% to 21%;
•
limitation on the deduction of certain interest expense;
•
full expense deduction for certain business capital expenditures;
•
limitation
on the utilization of NOLs arising after December 31, 2017; and
•
a system of taxing foreign-sourced income from multinational corporations.
We have made a reasonable estimate for the measurement and accounting of the reduction in the U.S. federal corporate tax rate and transitional tax on foreign-sourced income from our international operations which have been reflected in the Consolidated Financial Statements as of and for the year ended December 31, 2017. The accounting for the reduction in the U.S. federal corporate tax rate decreased our net deferred tax asset by $559
million which was fully offset by a decrease in our valuation allowance for the year ended December 31, 2017. The accounting for the transitional tax on foreign-sourced income increased
152
our current tax provision by $9 million which was offset by the reduction in our current tax provision associated with our current year operating loss. The Act did not have an adverse material effect on our Consolidated Financial Statements for the year ended December 31, 2017.
Because
of the complexity of the new Global Intangible Low Taxed Income (“GILTI”) rules in the Act, we are continuing to evaluate this provision and its application under U.S. GAAP. We are not yet able to reasonably estimate the effect of this provision of the Act. Therefore, we have not made any adjustments related to potential GILTI tax in our Consolidated Financial Statements and have not made a policy decision regarding whether to record deferred taxes on GILTI.
In December 2017, the SEC issued Staff Accounting Bulletin No. 118 “Income Tax Accounting Implications of the Tax Cuts and Jobs Act” (“SAB 118”) which allows a company up to one year to finalize and record the tax effects of the Act. We are currently in the process of finalizing and quantifying the tax effects of the Act, but have recorded provisional amounts based on reasonable estimates for the measurement and accounting of certain effects of the
Act in our Consolidated Financial Statements for the year ended December 31, 2017. Under SAB 118, we will complete the required analyses and accounting during the year ended December 31, 2018.
Comprehensive Income — In February 2018, the FASB issued Accounting Standards Update 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.” The standard allows an entity to reclassify the income tax effects of the Act on items within AOCI to retained earnings and also requires additional disclosures. The standard is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We do not anticipate a material effect on our financial condition,
results of operations or cash flows as a result of adopting this standard.
Income Tax Expense (Benefit)
The jurisdictional components of income from continuing operations before income tax expense (benefit), attributable to Calpine, for the years ended December 31, 2017, 2016 and 2015, are as follows (in millions):
2017
2016
2015
U.S.
$
(358
)
$
116
$
133
International
27
24
26
Total
$
(331
)
$
140
$
159
The
components of income tax expense (benefit) from continuing operations for the years ended December 31, 2017, 2016 and 2015, consisted of the following (in millions):
2017
2016
2015
Current:
Federal
$
(10
)
$
(10
)
$
(1
)
State
18
14
10
Foreign
(14
)
1
2
Total
current
(6
)
5
11
Deferred:
Federal
5
10
(21
)
State
6
27
1
Foreign
3
6
(67
)
Total
deferred
14
43
(87
)
Total income tax expense (benefit)
$
8
$
48
$
(76
)
153
For the years ended December 31, 2017, 2016 and 2015, our income tax rates did not bear a customary relationship to statutory income tax rates, primarily as a result of the effect of our NOLs, valuation allowances and state income taxes. A reconciliation of the federal statutory rate of 35% to our effective rate from continuing operations for the years ended December 31, 2017, 2016 and 2015, is as follows:
2017
2016
2015
Federal
statutory tax rate
35.0
%
35.0
%
35.0
%
State tax expense, net of federal benefit
(6.0
)
19.4
5.1
Change
in tax rate of net deferred tax asset
(168.8
)
—
—
Valuation allowances offsetting tax rate change
168.8
—
—
Valuation
allowances against future tax benefits
(33.0
)
(25.0
)
(46.0
)
Valuation allowance related to foreign taxes
0.5
(0.1
)
(49.4
)
Distributions
from foreign affiliates and foreign taxes
(2.0
)
(0.6
)
3.1
Change in unrecognized tax benefits
5.1
(0.1
)
1.2
Disallowed
compensation
(0.6
)
0.9
3.1
Stock-based compensation
(0.9
)
2.2
0.6
Equity
earnings
(0.8
)
2.0
(0.5
)
Other differences
0.3
0.6
—
Effective
income tax rate
(2.4
)%
34.3
%
(47.8
)%
Deferred Tax Assets and Liabilities
The components of deferred income taxes as of December 31, 2017 and 2016, are
as follows (in millions):
2017
2016
Deferred tax assets:
NOL and
credit carryforwards
$
1,810
$
2,728
Taxes related to risk management activities and derivatives
20
38
Reorganization
items and impairments
146
222
Other differences
28
—
Deferred tax assets before valuation allowance
2,004
2,988
Valuation
allowance
(1,168
)
(1,581
)
Total deferred tax assets
836
1,407
Deferred tax liabilities:
Property,
plant and equipment
(805
)
(1,266
)
Other differences
—
(93
)
Total deferred tax liabilities
(805
)
(1,359
)
Net
deferred tax asset
31
48
Less: Non-current deferred tax liability
(28
)
(14
)
Deferred income tax asset, non-current
$
59
$
62
Intraperiod
Tax Allocation — In accordance with U.S. GAAP, intraperiod tax allocation provisions require allocation of a tax expense (benefit) to continuing operations due to current OCI gains (losses) with an offsetting amount recognized in OCI. The intraperiod tax allocation included in continuing operations is $6 million, nil and nil for the years ended December 31, 2017, 2016 and 2015.
NOL Carryforwards — As of December 31, 2017, our NOL carryforwards consisted primarily
of federal NOL carryforwards of approximately $6.6 billion, which expire between 2024 and 2037, and NOL carryforwards in 27 states and the District of Columbia totaling approximately $3.5 billion, which expire between 2018 and 2037. Substantially all of the federal and state NOLs are offset with a full valuation allowance. Certain of the state NOL carryforwards may be subject to limitations on their annual usage. If a subsequent ownership change, such as the ownership change associated with the impending Merger, were to occur as a result of future transactions in our stock, our ability to utilize the NOL carryforwards will be limited. Although
154
we have not completed our analysis, it is reasonably possible that our federal NOLs available to offset future taxable income could materially decrease. This reduction will be offset by an adjustment to the existing valuation allowance for an equal and offsetting amount. Additionally, our state NOLs available to offset future state income could similarly decrease which would also be offset by an equal and offsetting adjustment to the existing valuation allowance. Given the offsetting adjustments to the existing valuation allowance, any ownership change is not expected to have an adverse material effect on our Consolidated Financial Statements.
We also have approximately $659 million in foreign NOLs, which expire between 2026
and 2037, and the associated deferred tax asset of approximately $165 million is partially offset by a valuation allowance of $106 million. Under Canadian income tax law, our NOL carryfowards can be utilized to reduce future taxable income subject to certain limitations including new applicable limitations resulting from an ownership change which will result in an increase in the valuation allowance and a related charge to deferred tax expense. It is reasonably possible that an increase of approximately $59 million in the valuation allowance and a related charge to deferred tax expense would occur as a result of the impending Merger.
Income Tax Audits — We remain subject to periodic audits and reviews by taxing authorities;
however, we do not expect these audits will have a material effect on our tax provision. Any NOLs we claim in future years to reduce taxable income could be subject to IRS examination regardless of when the NOLs were generated. Any adjustment of state or federal returns could result in a reduction of deferred tax assets rather than a cash payment of income taxes in tax jurisdictions where we have NOLs. We are currently under U.S. federal income tax examination for the year ended December 31, 2015 and various state income tax audits for various periods. Our Canadian subsidiaries are currently under examination by the Canada Revenue Agency for the years ended December 31, 2013 through 2016.
Valuation Allowance — U.S.
GAAP requires that we consider all available evidence, both positive and negative, and tax planning strategies to determine whether, based on the weight of that evidence, a valuation allowance is needed to reduce the value of deferred tax assets. Future realization of the tax benefit of an existing deductible temporary difference or carryforward ultimately depends on the existence of sufficient taxable income of the appropriate character within the carryback or carryforward periods available under the tax law. Due to our history of losses, we were unable to assume future profits; however, we are able to consider available tax planning strategies.
As of December 31, 2017, we have provided a valuation allowance of approximately $1.2 billion on certain federal, state and foreign tax jurisdiction
deferred tax assets to reduce the amount of these assets to the extent necessary to result in an amount that is more likely than not to be realized. The net change in our valuation allowance was a decrease of $413 million for the year ended December 31, 2017 of which $559 million is related to the reduction in the U.S. federal corporate tax rate that was partially offset by $146 million primarily related to losses generated in the current period. We had a reduction in our valuation allowance of $56 million and $199 million for the years ended December 31, 2016
and 2015, respectively, primarily related to income generated in these periods.
Unrecognized Tax Benefits
At December 31, 2017, we had unrecognized tax benefits of $38 million. If recognized, $12 million of our unrecognized tax benefits could affect the annual effective tax rate and $26 million, related to deferred tax assets could be offset against the recorded valuation allowance resulting in no effect to our effective tax rate. We had accrued interest and penalties of $4 million and $12
million for income tax matters at December 31, 2017 and 2016, respectively. We recognize interest and penalties related to unrecognized tax benefits in income tax expense (benefit) on our Consolidated Statements of Operations and recorded $(8) million, nil and $1 million for the years ended December 31, 2017, 2016 and 2015, respectively. We believe that it is reasonably possible that a decrease within the range of nil
and $18 million in unrecognized tax benefits could occur within the next twelve months primarily related to foreign tax issues and the lapse of applicable statute of limitations.
A reconciliation of the beginning and ending amounts of our unrecognized tax benefits for the years ended December 31, 2017, 2016 and 2015, is as follows (in millions):
2017
2016
2015
Balance,
beginning of period
$
(59
)
$
(58
)
$
(56
)
Decreases related to prior year tax positions
11
1
3
Increases
related to current year tax positions
(2
)
(2
)
(5
)
Decreases related to change in tax rate of net deferred tax asset
12
—
—
Balance,
end of period
$
(38
)
$
(59
)
$
(58
)
155
12.
Earnings
(Loss) per Share
We include restricted stock units for which no future service is required as a condition to the delivery of the underlying common stock in our calculation of weighted average shares outstanding. As we incurred a net loss for the year ended December 31, 2017, diluted loss per share for this year is computed on the same basis as basic loss per share, as the inclusion of any other potential shares outstanding would be anti-dilutive. Reconciliations of the amounts used in the basic and diluted earnings (loss) per common share computations for the years ended December 31, 2017, 2016 and 2015, are as follows (shares
in thousands):
2017
2016
2015
Diluted weighted average shares calculation:
Weighted
average shares outstanding (basic)
355,245
354,006
362,033
Share-based awards
—
2,104
2,853
Weighted
average shares outstanding (diluted)
355,245
356,110
364,886
We excluded the following items from diluted earnings per common share for the years ended December 31, 2017, 2016 and 2015, because
they were anti-dilutive (shares in thousands):
2017
2016
2015
Share-based awards
5,881
1,659
5,340
13.
Stock-Based
Compensation
Calpine Equity Incentive Plans
The Calpine Equity Incentive Plans provide for the issuance of equity awards to all non-union employees as well as the non-employee members of our Board of Directors. The equity awards may include incentive or non-qualified stock options, restricted stock, restricted stock units, stock appreciation rights, performance compensation awards and other share-based awards. The equity awards granted under the Calpine Equity Incentive Plans include both graded and cliff vesting awards which vest over periods between one and five years, contain contractual terms between approximately five and ten years and are subject to forfeiture provisions
under certain circumstances, including termination of employment prior to vesting. At December 31, 2017, 300,000 shares and 21,865,106 shares remain available for future issuance under the 2017 Director Plan and the 2017 Equity Plan, respectively. There are no shares available for issuance under the 2008 Director Plan and the 2008 Equity Plan.
Equity Classified Share-Based Awards
We use the Black-Scholes option-pricing model or the Monte Carlo simulation model, as appropriate, to estimate the fair value of our employee stock options on the grant date, which takes into account the exercise price and expected term of the stock option, the current price of the underlying stock and its expected volatility,
expected dividends on the stock and the risk-free interest rate for the expected term of the stock option as of the grant date. For our restricted stock and restricted stock units, we use our closing stock price on the date of grant, or the last trading day preceding the grant date for restricted stock granted on non-trading days, as the fair value for measuring compensation expense. Stock-based compensation expense is recognized over the period in which the related employee services are rendered. The service period is generally presumed to begin on the grant date and end when the equity award is fully vested. We use the graded vesting attribution method to recognize fair value of the equity award over the service period. For example, the graded vesting attribution method views one three-year restricted stock grant with annual graded vesting as three separate sub-grants, each
representing 33 1/3% of the total number of shares of restricted stock granted. The first sub-grant vests over one year, the second sub-grant vests over two years and the third sub-grant vests over three years. A three-year restricted stock grant with cliff vesting is viewed as one grant vesting over three years.
Stock-based compensation expense recognized for our equity classified share-based awards was $36 million, $30 million and $31 million for the years ended
December 31, 2017, 2016 and 2015, respectively. We did not record any significant tax benefits related to stock-based compensation expense in any period as we are not benefiting from a significant portion of our deferred tax assets, including deductions related to stock-based compensation expense. In addition, we did not capitalize any stock-based compensation expense as part of the cost of an asset for the years ended December 31, 2017, 2016 and 2015. At December 31, 2017, there was unrecognized compensation
cost of $22 million related to restricted stock, $5 million related to restricted stock units and $4 million related to options which is expected to be recognized over a weighted average period of 1.2 years for restricted stock, 1.0 years for restricted stock units and 2.0 years for options. We issue new shares from our share reserves set aside for the Calpine Equity Incentive Plans when stock options are exercised and for other share-based awards.
156
A summary of all of our non-qualified
stock option activity for the Calpine Equity Incentive Plans for the year ended December 31, 2017, is as follows:
Upon
consummation of the Merger, all vested and unvested stock options will be canceled and the holders of the stock options will receive a cash payment equal to the intrinsic value based on a share price of $15.25 per share less any applicable withholding taxes.
The total intrinsic value of our employee stock options exercised was nil, $1 million and $6 million for the years ended December 31, 2017, 2016 and 2015, respectively. The total cash proceeds received from our employee stock options exercised was nil,
$1 million and $8 million for the years ended December 31, 2017, 2016 and 2015, respectively.
There were no stock option grants during the years ended December 31, 2016 and 2015. The fair value of options granted during the year ended December 31, 2017 was determined on the grant date using the Black-Scholes option-pricing model. Certain assumptions were used in
order to estimate fair value for options as noted in the following table:
2017
Expected term (in years)(1)
7.3 - 10.0
Risk-free interest rate(2)
2.25
%
Expected
volatility(3)
33 - 40
%
Dividend yield(4)
—
Weighted average grant-date fair value (per option)
$
5.38
___________
(1)
Expected
term calculated using historical exercise data.
(2)
Zero Coupon U.S. Treasury rate or equivalent based on expected term.
(3)
Volatility calculated using the implied volatility of our exchange traded stock options.
(4)
We have never paid cash dividends on our common stock and we do not anticipate
any cash dividend payments on our common stock in the near future.
157
A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the year ended December 31, 2017, is as follows:
Includes 63,075 shares of restricted stock and restricted stock units outstanding under the Director Plans and 5,948,740
shares of restricted stock and restricted stock units outstanding under the Equity Plans. Upon consummation of the Merger, all restricted stock and restricted stock units will become vested and canceled and the holders will receive a cash payment equal to a share price of $15.25 per share less any applicable withholding taxes.
The total fair value of our restricted stock and restricted stock units that vested during the years ended December 31, 2017, 2016 and 2015, was approximately $23 million, $17 million and $39 million, respectively.
Liability
Classified Share-Based Awards
During the first quarter of 2017, our Board of Directors approved the award of PSUs to certain senior management employees. These PSUs will be settled in cash with payouts based on the relative performance of Calpine’s total shareholder return over the three-year performance period of January 1, 2017 through December 31, 2019. The PSUs vest on the last day of the performance period and will be settled in cash; thus, these awards are liability classified and are measured at fair value using a Monte Carlo simulation model at each reporting date until settlement. Stock-based compensation expense recognized related to our liability classified share-based awards was $6 million, $1 million and $(5)
million for the years ended December 31, 2017, 2016 and 2015, respectively.
A summary of our PSU activity for the year ended December 31, 2017, is as follows:
Upon consummation of the Merger, all PSUs, including the PSUs awarded in 2015 for the measurement period of January 1, 2015
through December 31, 2017, will become vested and canceled in exchange for a cash payment with the payout value based on the greater of target value or actual performance over the truncated period using a share price of $15.25 per share less any applicable withholding taxes.
There were no payments made associated with our PSUs for the years ended December 31, 2017, 2016 and 2015.
158
14.
Defined
Contribution and Defined Benefit Plans
We maintain two defined contribution savings plans that are intended to be tax exempt under Sections 401(a) and 501(a) of the IRC. Our non-union plan generally covers employees who are not covered by a collective bargaining agreement, and our union plan covers employees who are covered by a collective bargaining agreement. We recorded expenses for these plans of approximately $14 million, $11 million and $12 million for the years ended December 31, 2017, 2016 and 2015, respectively. Employer matching contributions are 100%
of the first 5% of compensation a participant defers for the non-union plan. The employee deferral limit is 75% of eligible compensation under both plans.
We also maintain a defined benefit pension plan whereby retirement benefits are primarily a function of age attained, years of participation, years of service, vesting and level of compensation. Only approximately 3% of our employees are eligible to participate in a defined benefit pension plan. As of December 31, 2017 and 2016, there were approximately $21 million and $18 million
in plan assets and approximately $29 million and $26 million in pension liabilities, respectively. Our net pension liability recorded on our Consolidated Balance Sheets as of December 31, 2017 and 2016, was approximately $8 million and $8 million, respectively. For the years ended December 31, 2017, 2016 and 2015, we recognized net periodic benefit costs of approximately $1 million,
$2 million and $2 million, respectively. Our net periodic benefit cost is included in operating and maintenance expense on our Consolidated Statements of Operations. As of December 31, 2017 and 2016, the total amount recognized in AOCI for actuarial losses related to pension obligation was approximately $5 million and $5 million, respectively.
In making our estimates of our pension obligation and related costs, we utilize discount rates, rates of compensation increases and rates of return on our assets that we believe are reasonable. Due to the relatively
small size of our pension liability (which is not considered material), significant changes in these assumptions would not have a material effect on our pension liability. During 2017 and 2016, we made contributions of approximately $2 million and $3 million, respectively, and estimated contributions to the pension plan are expected to be approximately $1 million in 2017. Estimated future benefit payments to participants in each of the next five years are expected to be approximately $1 million in each year.
15.
Capital
Structure
Common Stock
Our authorized common stock consists of 1.4 billion shares of Calpine Corporation common stock. Common stock issued as of December 31, 2017 and 2016, was 361,677,891 shares and 359,627,113 shares, respectively, at a par value of $0.001 per share. Common stock outstanding as of December 31, 2017 and 2016,
was 360,516,091 shares and 359,061,764 shares, respectively. The table below summarizes our common stock activity for the years ended December 31, 2017, 2016 and 2015.
As of December 31, 2017 and 2016,
we had treasury stock of 1,161,800 shares and 565,349 shares, respectively, with a cost of $15 million and $7 million, respectively. Our treasury stock consists of shares repurchased as well as our common stock withheld to satisfy federal, state and local income tax withholding requirements for vested employee restricted stock awards and net share employee stock options exercises under the Equity Plan. All treasury stock is held at cost.
159
16.
Commitments
and Contingencies
Long-Term Service Agreements
As of December 31, 2017, the total estimated commitments for LTSAs associated with turbines were approximately $297 million. These commitments are payable over the remaining terms of the respective agreements, which range from 2 to 20 years. LTSA future commitment estimates are based on the stated payment terms in the contracts at the time of execution and are subject to an annual inflationary adjustment. Certain of these agreements have terms that allow us to cancel the contracts
for a fee. If we cancel such contracts, the estimated commitments remaining for LTSAs would be reduced.
Power Plant, Land and Other Operating Leases
We have entered into a long-term operating lease for one of our power plants, extending through February 1, 2020, which includes renewal options and contain customary restrictions on dividends up to Calpine Corporation, additional debt and further encumbrances similar to those typically found in project finance agreements. Payments on our operating lease, which may contain escalation clauses or step rent provisions, are recognized on a straight-line basis. Certain capital improvements associated with our leased power plant may be deemed to be leasehold
improvements and are amortized over the shorter of the term of the lease or the economic life of the capital improvement. We have also entered into various land and other operating leases for ground facilities and operations, which extend through 2073. Future minimum rent payments under these lease agreements, including renewal options and rent escalation clauses, are as follows (in millions):
Initial
Year
2018
2019
2020
2021
2022
Thereafter
Total
Land
and other operating leases
various
$
13
$
13
$
13
$
13
$
13
$
165
$
230
Power
plant operating lease
2000
22
30
—
—
—
—
52
Total
leases
$
35
$
43
$
13
$
13
$
13
$
165
$
282
During
the years ended December 31, 2017, 2016 and 2015, rent expense for power plant, land and other operating leases amounted to $41 million, $38 million and $43 million, respectively.
Production Royalties and Leases
We are obligated under numerous geothermal leases and right-of-way, easement and surface agreements. The geothermal leases generally provide for royalties based on production revenue with reductions for property taxes paid. The right-of-way, easement and surface agreements are based on flat rates or adjusted based on consumer price index changes and
are not material. Under the terms of most geothermal leases, the royalties accrue as a percentage of power revenues. Certain properties also have net profits and overriding royalty interests that are in addition to the land base lease royalties. Some lease agreements contain clauses providing for minimum lease payments to lessors if production temporarily ceases or if production falls below a specified level. Production royalties for geothermal power plants for the years ended December 31, 2017, 2016 and 2015, were $25 million, $22 million and $23 million, respectively.
Office Leases
We
lease our corporate and regional offices under noncancellable operating leases extending through 2026. Future minimum lease payments under these leases are as follows (in millions):
2018
$
13
2019
13
2020
13
2021
2
2022
1
Thereafter
3
Total
$
45
160
Lease payments are subject to adjustments for our pro rata portion of annual increases or decreases in building operating costs. During the years ended December 31, 2017, 2016 and 2015, rent expense for noncancelable operating leases was $9 million, $9 million and $11 million, respectively.
Commodity Purchases
We enter into commodity purchase contracts
of various terms with third parties to supply fuel to our natural gas-fired power plants and power to our retail customers. The majority of our purchases are made in the spot market or under index-priced contracts. These contracts are accounted for as executory contracts and therefore not recognized as liabilities on our Consolidated Balance Sheet. At December 31, 2017, we had future commitments for the purchase, transportation, or storage of commodities as detailed below (in millions):
2018
$
458
2019
253
2020
121
2021
85
2022
60
Thereafter
524
Total
$
1,501
Guarantees
and Indemnifications
As part of our normal business operations, we enter into various agreements providing, or otherwise arranging, financial or performance assurance to third parties on behalf of our subsidiaries in the ordinary course of such subsidiaries’ respective business. Such arrangements include guarantees, standby letters of credit and surety bonds for power and natural gas purchase and sale arrangements, retail contracts, contracts associated with the development, construction, operation and maintenance of our fleet of power plants and our Accounts Receivable
Sales Program. These arrangements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended commercial purposes.
At December 31, 2017, guarantees of subsidiary debt, standby letters of credit and surety bonds to third parties and the guarantee under our Account Receivable Sales Program and their respective expiration dates were as follows (in millions):
Guarantee
Commitments
2018
2019
2020
2021
2022
Thereafter
Total
Guarantee
of subsidiary debt(1)
$
31
$
30
$
30
$
29
$
24
$
66
$
210
Standby
letters of credit(2)(3)(4)
966
65
—
—
—
38
1,069
Surety
bonds(4)(5)(6)
14
6
—
—
—
26
46
Guarantee
under Accounts Receivable Sales Program(7)
196
—
—
—
—
—
196
Total
$
1,207
$
101
$
30
$
29
$
24
$
130
$
1,521
____________
(1)
Represents
Calpine Corporation guarantees of certain power plant capital leases and related interest. All guaranteed capital leases are recorded on our Consolidated Balance Sheets.
(2)
The standby letters of credit disclosed above represent those disclosed in Note 7.
(3)
Letters of credit are renewed annually and as such all amounts are reflected in the year of letter of credit expiration. The related commercial obligations extend for multiple years, therefore, renewal of the letter of credit will likely follow the term of the associated
commercial obligation.
(4)
These are contingent off balance sheet obligations.
(5)
The majority of surety bonds do not have expiration or cancellation dates.
(6)
As of December 31, 2017, no
cash collateral is outstanding related to these bonds.
(7)
Calpine has guaranteed the performance of Calpine Solutions under the Accounts Receivable Sales Program. The Accounts Receivable Sales Program expires on November 30, 2018.
161
We routinely arrange for the issuance of letters of credit and various forms of surety bonds to third parties in support of our subsidiaries’
contractual arrangements of the types described above and may guarantee the operating performance of some of our partially-owned subsidiaries up to our ownership percentage. The letters of credit issued under various credit facilities support risk management and other operational and construction activities. In the event a subsidiary were to fail to perform its obligations under a contract supported by such a letter of credit or surety bond, and the issuing bank or surety were to make payment to the third party, we would be responsible for reimbursing the issuing bank or surety within an agreed timeframe, typically a period of one to five days. To the extent liabilities are incurred as a result of activities covered by letters of credit or the surety bonds, such liabilities are included on
our Consolidated Balance Sheets.
Commercial Agreements — In connection with the purchase and sale of power, natural gas, environmental products and fuel oil to and from third parties with respect to the operation of our power plants and our retail subsidiaries, we may be required to guarantee a portion of the obligations of certain of our subsidiaries. We may also be required to guarantee performance obligations associated with our marketing, hedging, optimization and trading activities to manage our exposure to changes in prices for energy commodities. These guarantees may include future payment obligations and effectively guarantee our future performance under certain agreements.
Asset
Acquisition and Disposition Agreements — In connection with our purchase and sale agreements, we have frequently provided for indemnification to the counterparty for liabilities incurred as a result of a breach of a representation, warranty or covenant by the indemnifying party. These indemnification obligations generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or impossible to quantify at the time of the consummation of a particular transaction.
Other — Additionally, we and our subsidiaries from time to time assume other guarantee and indemnification obligations in conjunction with other transactions such as parts supply agreements, construction agreements, maintenance and service agreements and equipment lease agreements.
These guarantee and indemnification obligations may include indemnification from personal injury or other claims by our employees as well as future payment obligations and effectively guarantee our future performance under certain agreements.
Our potential exposure under guarantee and indemnification obligations can range from a specified amount to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. Our total maximum exposure under our guarantee and indemnification obligations is not estimable due to uncertainty as to whether claims will be made or how any potential claim will be resolved. As of December 31, 2017, there are no material outstanding claims related to our guarantee and indemnification obligations and we do not anticipate that
we will be required to make any material payments under our guarantee and indemnification obligations.
Litigation
We are party to various litigation matters, including regulatory and administrative proceedings arising out of the normal course of business. At the present time, we do not expect that the outcome of any of these proceedings, individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.
On a quarterly basis, 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 determine an unfavorable outcome is probable and is reasonably estimable, we accrue for potential litigation losses. 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; however, we do not expect that the reasonably possible outcome of these litigation matters would, individually or in the aggregate, have a material adverse effect on our financial condition, results of operations or cash flows. 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.
Environmental Matters
We
are subject to complex and stringent environmental laws and regulations related to the operation of our power plants. On occasion, we may incur environmental fees, penalties and fines associated with the operation of our power plants. At the present time, we do not have environmental violations or other matters that would have a material effect on our financial condition, results of operations or cash flows or that would significantly change our operations.
162
17.
Segment and Significant Customer Information
We
assess our 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. At December 31, 2017, our reportable segments were West (including geothermal), Texas and East (including Canada). The results of our retail subsidiaries are reflected in the segment which corresponds with the geographic area in which the retail sales occur. We continue to evaluate the optimal manner in which we assess our performance including our segments and future changes may result in changes to the composition of our geographic segments. Commodity Margin is a key operational measure of profit reviewed by our chief operating decision maker to assess
the performance of our segments. The tables below show our financial data for our segments for the periods indicated (in millions).
Debt modification and extinguishment costs and other (income) expense, net
54
Income
before income taxes
$
173
__________
(1)
Includes
$(8) million, $(2) million and $(2) million of lease levelization and $178 million, $122 million and $20 million of amortization expense for the years ended December 31, 2017, 2016 and 2015, respectively.
164
Significant Customers
For the
year ended December 31, 2017 and 2016, we had no significant customer that individually accounted for more than 10% of our annual consolidated revenues. For the year ended December 31, 2015, we had two significant customers, PJM Settlement, Inc. and PG&E, that individually accounted for more than 10% of our annual consolidated revenues. Our revenues from PJM Settlement, Inc. for the year ended December 31, 2015 were approximately $724 million, and were
attributed to our East segment. Our revenues from PG&E for the year ended December 31, 2015 was approximately $642 million, which was attributed to our West segment.
18.
Quarterly Consolidated Financial Data (unaudited)
Our quarterly operating results have fluctuated in the past and may continue to do so in the future as a result of a number of factors, including, but not limited to, our restructuring activities (including asset sales and dispositions), the completion of development
projects, the timing and amount of curtailment of operations under the terms of certain PPAs, the degree of risk management and marketing, hedging, optimization and trading activities, energy commodity market prices and variations in levels of production. Furthermore, the majority of the dollar value of capacity payments under certain of our PPAs are received during the months of May through October.
Quarter
Ended
December 31
September 30
June 30
March 31
(in millions, except per share amounts)
2017
Operating
revenues
$
1,801
$
2,586
$
2,084
$
2,281
Income
(loss) from operations
$
(100
)
$
393
$
13
$
72
Net
income (loss) attributable to Calpine
$
(292
)
$
225
$
(216
)
$
(56
)
Net
income (loss) per common share attributable to Calpine — Basic
$
(0.82
)
$
0.63
$
(0.61
)
$
(0.16
)
Net
income (loss) per common share attributable to Calpine — Diluted
$
(0.82
)
$
0.63
$
(0.61
)
$
(0.16
)
2016
Operating
revenues
$
1,582
$
2,355
$
1,164
$
1,615
Income
from operations(1)
$
234
$
462
$
140
$
3
Net
income (loss) attributable to Calpine
$
24
$
295
$
(29
)
$
(198
)
Net
income (loss) per common share attributable to Calpine — Basic
$
0.07
$
0.83
$
(0.08
)
$
(0.56
)
Net
income (loss) per common share attributable to Calpine — Diluted
$
0.07
$
0.83
$
(0.08
)
$
(0.56
)
____________
(1)
We
recorded a gain on sale of assets, net of $(157) million in connection with the sale of the Mankato Power Plant which is included in income from operations on our Consolidated Statement of Operations for the year ended December 31, 2016.
