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[X]
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended December 31, 2018
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[ ]
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the transition period from to
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Large accelerated filer [ ]
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Accelerated filer [ ]
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Non-accelerated filer [X]
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Smaller reporting company [ ]
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(Do not check if a smaller reporting company)
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Emerging growth company [ ]
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Page
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Item 1.
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Item 1A.
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Item 1B.
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Item 2.
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Item 3.
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Item 4.
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Item 5.
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Item 6.
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Item 7.
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Item 7A.
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Item 8.
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Item 9.
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Item 9A.
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Item 9B.
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Item 10.
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Item 11.
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Item 12.
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Item 13.
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Item 14.
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Item 15.
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Item 16.
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ABBREVIATION
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DEFINITION
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2008 Director Plan
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The Amended and Restated Calpine Corporation 2008 Director Incentive Plan
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2008 Equity Plan
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The Amended and Restated Calpine Corporation 2008 Equity Incentive Plan
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2017 Director Plan
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The Calpine Corporation 2017 Equity Compensation Plan for Non-Employee Directors
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2017 Equity Plan
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The Calpine Corporation 2017 Equity Incentive Plan
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2017 First Lien Term Loan
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The $550 million first lien senior secured term loan, dated December 1, 2016, among Calpine Corporation, as borrower, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent and MUFG Union Bank, N.A., as collateral agent, repaid in a series of transactions on March 16, 2017, August 31, 2017, September 29, 2017, October 31, 2017 and November 30, 2017
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2019 First Lien Term Loan
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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
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2022 First Lien Notes
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The $750 million aggregate principal amount of 6.0% senior secured notes due 2022, issued October 31, 2013
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2023 First Lien Notes
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The $1.2 billion aggregate principal amount of 7.875% senior secured notes due 2023, issued January 14, 2011, repaid in a series of transactions on November 7, 2012, December 2, 2013, December 4, 2014, February 3, 2015, December 7, 2015, December 19, 2016 and March 6, 2017
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2023 First Lien Term Loans
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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
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2023 Senior Unsecured Notes
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The $1.25 billion aggregate principal amount of 5.375% senior unsecured notes due 2023, issued July 22, 2014
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2024 First Lien Notes
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The $490 million aggregate principal amount of 5.875% senior secured notes due 2024, issued October 31, 2013
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2024 First Lien Term Loan
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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
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2024 Senior Unsecured Notes
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The $650 million aggregate principal amount of 5.5% senior unsecured notes due 2024, issued February 3, 2015
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2025 Senior Unsecured Notes
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The $1.55 billion aggregate principal amount of 5.75% senior unsecured notes due 2025, issued July 22, 2014
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2026 First Lien Notes
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Collectively, the $625 million aggregate principal amount of 5.25% senior secured notes due 2026, issued May 31, 2016, and the $560 million aggregate principal amount of 5.25% senior secured notes due 2026, issued on December 15, 2017
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ABBREVIATION
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DEFINITION
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AB 32
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California Assembly Bill 32
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Accounts Receivable Sales Program
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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
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AOCI
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Accumulated Other Comprehensive Income
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Average availability
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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
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Average capacity factor, excluding peakers
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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
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Board of Directors
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Calpine Corporation Board of Directors
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Btu
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British thermal unit(s), a measure of heat content
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CAA
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Federal Clean Air Act, U.S. Code Title 42, Chapter 85
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CAISO
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California Independent System Operator which is an entity that manages the power grid and operates the competitive power market in California
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CARB
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California Air Resources Board
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Calpine Equity Incentive Plans
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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
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Calpine Receivables
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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
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Calpine Solutions
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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
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Cap-and-Trade
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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
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CCFC
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Calpine Construction Finance Company, L.P., an indirect, wholly-owned subsidiary of Calpine
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CCFC Term Loan
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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
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CCFC Term Loans
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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
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ABBREVIATION
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DEFINITION
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CDHI
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Calpine Development Holdings, Inc., an indirect, wholly-owned subsidiary of Calpine
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CFTC
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Commodities Futures Trading Commission
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Champion Energy
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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
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Chapter 11
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Chapter 11 of the U.S. Bankruptcy Code
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Class B Interests
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Partnership interests in CPN Management having the rights and obligations with respect to Class B Interests as set forth in the Second Amended and Restated Limited Partnership Agreement of CPN Management dated August 29, 2018
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CO
2
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Carbon dioxide
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Cogeneration
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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
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Commodity expense
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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
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Commodity Margin
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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. Commodity Margin is a measure of segment profit or loss under FASB Accounting Standards Codification 280 used by our chief operating decision maker to make decisions about allocating resources to the relevant segments and assessing their performance
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Commodity revenue
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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
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Company
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Calpine Corporation, a Delaware corporation, and its subsidiaries
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Corporate Revolving Facility
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The approximately $1.69 billion aggregate amount revolving credit facility credit agreement, dated as of December 10, 2010, as amended on June 27, 2013, July 30, 2014, February 8, 2016, December 1, 2016, September 15, 2017, October 20, 2017, March 8, 2018 and May 18, 2018 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
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CPN Management
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CPN Management, LP, which owns 100% of the common stock of Calpine Corporation
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CSAPR
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Cross-State Air Pollution Rule
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Director Plans
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Collectively, the 2008 Director Plan and the 2017 Director Plan
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EIA
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Energy Information Administration of the U.S. Department of Energy
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EPA
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U.S. Environmental Protection Agency
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Equity Plans
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Collectively, the 2008 Equity Plan and the 2017 Equity Plan
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ABBREVIATION
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DEFINITION
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ERCOT
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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
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Exchange Act
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U.S. Securities Exchange Act of 1934, as amended
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FASB
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Financial Accounting Standards Board
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FDIC
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U.S. Federal Deposit Insurance Corporation
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FERC
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U.S. Federal Energy Regulatory Commission
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First Lien Notes
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Collectively, the 2022 First Lien Notes, the 2024 First Lien Notes and the 2026 First Lien Notes
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First Lien Term Loans
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Collectively, the 2019 First Lien Term Loan, the 2023 First Lien Term Loans and the 2024 First Lien Term Loan
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FRCC
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Florida Reliability Coordinating Council
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GE
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General Electric International, Inc.
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Geysers Assets
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Our geothermal power plant assets, including our steam extraction and gathering assets, located in northern California consisting of 13 operating power plants
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GHG(s)
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Greenhouse gas(es), primarily carbon dioxide (CO
2
), and including methane (CH
4
), nitrous oxide (N
2
O), sulfur hexafluoride (SF
6
), hydrofluorocarbons (HFCs) and perfluorocarbons (PFCs)
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Greenfield LP
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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
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Heat Rate(s)
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A measure of the amount of fuel required to produce a unit of power
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IRC
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Internal Revenue Code
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IRS
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U.S. Internal Revenue Service
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ISO(s)
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Independent System Operator(s) which is an entity that coordinates, controls and monitors the operation of an electric power system
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ISO-NE
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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
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KWh
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Kilowatt hour(s), a measure of power produced, purchased or sold
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LIBOR
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London Inter-Bank Offered Rate
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LTSA(s)
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Long-Term Service Agreement(s)
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Lyondell
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LyondellBasell Industries N.V.
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Market Heat Rate(s)
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The regional power price divided by the corresponding regional natural gas price
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Merger
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Merger of Volt Merger Sub, Inc. with and into Calpine pursuant to the terms of the Merger Agreement, which was consummated on March 8, 2018
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ABBREVIATION
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DEFINITION
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Merger Agreement
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Agreement and Plan of Merger, dated August 17, 2017, by and among Calpine Corporation, Volt Parent, LP and Volt Merger Sub, Inc.
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MMBtu
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Million Btu
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MRO
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Midwest Reliability Organization
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MW
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Megawatt(s), a measure of plant capacity
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MWh
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Megawatt hour(s), a measure of power produced, purchased or sold
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NAAQS
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National Ambient Air Quality Standards
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NERC
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North American Electric Reliability Council
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Noble Solutions
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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
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NOL(s)
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Net operating loss(es)
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North American Power
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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.
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NOx
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Nitrogen oxides
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NPCC
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Northeast Power Coordinating Council
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NYISO
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New York ISO which operates competitive wholesale markets to manage the flow of electricity across New York
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NYMEX
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New York Mercantile Exchange
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NYSE
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New York Stock Exchange
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OCI
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Other Comprehensive Income
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OMEC
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Otay Mesa Energy Center, LLC, an indirect, wholly-owned subsidiary that owns the Otay Mesa Energy Center, a 608 MW power plant located in San Diego County, California
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OTC
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Over-the-Counter
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PG&E
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Pacific Gas & Electric Company
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PJM
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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
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PPA(s)
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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
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PSD
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Prevention of Significant Deterioration
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ABBREVIATION
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DEFINITION
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PUCT
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Public Utility Commission of Texas
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PUHCA 2005
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U.S. Public Utility Holding Company Act of 2005
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PURPA
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U.S. Public Utility Regulatory Policies Act of 1978
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QF(s)
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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
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REC(s)
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Renewable energy credit(s)
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Report
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This Annual Report on Form 10-K for the year ended December 31, 2018, filed with the SEC on March 28, 2019
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Reserve margin(s)
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The measure of how much the total generating capacity installed in a region exceeds the peak demand for power in that region
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RFC
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Reliability First Corporation
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RGGI
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Regional Greenhouse Gas Initiative
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Risk Management Policy
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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
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RMR Contract(s)
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Reliability Must Run contract(s)
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RPS
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Renewable Portfolio Standard
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RTO(s)
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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
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SDG&E
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San Diego Gas & Electric Company
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SEC
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U.S. Securities and Exchange Commission
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Securities Act
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U.S. Securities Act of 1933, as amended
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Senior Unsecured Notes
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Collectively, the 2023 Senior Unsecured Notes, the 2024 Senior Unsecured Notes and the 2025 Senior Unsecured Notes
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SERC
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Southeastern Electric Reliability Council
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Severance Plan
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Calpine Corporation Amended and Restated Change in Control and Severance Benefits Plan
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Short Term Credit Facility
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The $300 million aggregate amount credit agreement, dated as of April 11, 2018, among Calpine Corporation, Morgan Stanley Senior Funding, Inc., as administrative agent, and the lenders party thereto, which was terminated on August 17, 2018
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SO
2
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Sulfur dioxide
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Spark Spread(s)
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The difference between the sales price of power per MWh and the cost of natural gas to produce it
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ABBREVIATION
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DEFINITION
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Steam Adjusted Heat Rate
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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
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Stockholders Agreement
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Stockholders Agreement, dated March 8, 2018, by and between Calpine Corporation and CPN Management
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TRE
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Texas Reliability Entity, Inc.
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U.S. GAAP
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Generally accepted accounting principles in the U.S.
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VAR
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Value-at-risk
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VIE(s)
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Variable interest entity(ies)
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WECC
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Western Electricity Coordinating Council
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Whitby
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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
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•
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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;
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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;
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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;
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Risks associated with the operation, construction and development of power plants, including unscheduled outages or delays and plant efficiencies;
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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;
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Extensive competition in our wholesale and retail businesses, including from renewable sources of power, interference by states in competitive power markets through subsidies or similar support for new or existing power plants, lower prices and other incentives offered by retail competitors, and other risks associated with marketing and selling power in the evolving energy markets;
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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);
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The expiration or early termination of our PPAs and the related results on revenues;
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Future capacity revenue may not occur at expected levels;
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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;
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Disruptions in or limitations on the transportation of natural gas or fuel oil and the transmission of power;
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Our ability to manage our counterparty and customer exposure and credit risk, including our commodity positions or if a significant customer were to seek bankruptcy protection under Chapter 11;
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Our ability to attract, motivate and retain key employees;
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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
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Other risks identified in this Report.
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Item 1.
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Business
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First, we are a provider of power to utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities and other governmental entities, power marketers as well as retail commercial, industrial, 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.
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•
|
Second, we provide capacity for sale to utilities, independent electric system operators and retail power providers. In various markets, retail power providers (or independent electric system operators on their behalf) are required to demonstrate adequate resources to meet their power sales commitments. To meet this obligation, they procure a market product known as capacity from power plant owners or resellers. 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.
|
Geographic Diversity
|
Dispatch Technology
|
|
|
|
•
|
27% related to leases with the federal government via the Office of Natural Resources Revenue,
|
•
|
30% related to leases with the California State Lands Commission and
|
•
|
43% related to leases with private landowners/leaseholders.
|
SEGMENT / Power Plant
|
|
NERC
Region
|
|
U.S. State or
Canadian
Province
|
|
Technology
|
|
Calpine
Interest
Percentage
|
|
Calpine Net
Interest
Baseload
(MW)
(1)(3)
|
|
Calpine Net
Interest
With Peaking
(MW)
(2)(3)
|
|
2018
Total MWh
Generated
(4)
|
||||
WEST
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Geothermal
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
McCabe #5 & #6
|
|
WECC
|
|
CA
|
|
Renewable
|
|
100
|
%
|
|
84
|
|
|
84
|
|
|
707,861
|
|
Ridge Line #7 & #8
|
|
WECC
|
|
CA
|
|
Renewable
|
|
100
|
%
|
|
76
|
|
|
76
|
|
|
612,803
|
|
Calistoga
|
|
WECC
|
|
CA
|
|
Renewable
|
|
100
|
%
|
|
69
|
|
|
69
|
|
|
500,757
|
|
Eagle Rock
|
|
WECC
|
|
CA
|
|
Renewable
|
|
100
|
%
|
|
68
|
|
|
68
|
|
|
604,643
|
|
Big Geysers
|
|
WECC
|
|
CA
|
|
Renewable
|
|
100
|
%
|
|
61
|
|
|
61
|
|
|
436,498
|
|
Lake View
|
|
WECC
|
|
CA
|
|
Renewable
|
|
100
|
%
|
|
54
|
|
|
54
|
|
|
487,073
|
|
Quicksilver
|
|
WECC
|
|
CA
|
|
Renewable
|
|
100
|
%
|
|
53
|
|
|
53
|
|
|
353,868
|
|
Sonoma
|
|
WECC
|
|
CA
|
|
Renewable
|
|
100
|
%
|
|
53
|
|
|
53
|
|
|
439,167
|
|
Cobb Creek
|
|
WECC
|
|
CA
|
|
Renewable
|
|
100
|
%
|
|
51
|
|
|
51
|
|
|
326,123
|
|
Socrates
|
|
WECC
|
|
CA
|
|
Renewable
|
|
100
|
%
|
|
50
|
|
|
50
|
|
|
361,704
|
|
Sulphur Springs
|
|
WECC
|
|
CA
|
|
Renewable
|
|
100
|
%
|
|
47
|
|
|
47
|
|
|
450,998
|
|
Grant
|
|
WECC
|
|
CA
|
|
Renewable
|
|
100
|
%
|
|
41
|
|
|
41
|
|
|
332,791
|
|
Aidlin
|
|
WECC
|
|
CA
|
|
Renewable
|
|
100
|
%
|
|
18
|
|
|
18
|
|
|
114,165
|
|
Natural Gas-Fired
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Delta Energy Center
|
|
WECC
|
|
CA
|
|
Combined Cycle
|
|
100
|
%
|
|
835
|
|
|
857
|
|
|
3,088,154
|
|
Pastoria Energy Center
|
|
WECC
|
|
CA
|
|
Combined Cycle
|
|
100
|
%
|
|
770
|
|
|
749
|
|
|
4,325,914
|
|
Hermiston Power Project
|
|
WECC
|
|
OR
|
|
Combined Cycle
|
|
100
|
%
|
|
566
|
|
|
635
|
|
|
3,644,368
|
|
Otay Mesa Energy Center
|
|
WECC
|
|
CA
|
|
Combined Cycle
|
|
100
|
%
|
|
513
|
|
|
608
|
|
|
491,473
|
|
Metcalf Energy Center
|
|
WECC
|
|
CA
|
|
Combined Cycle
|
|
100
|
%
|
|
564
|
|
|
605
|
|
|
2,079,914
|
|
Sutter Energy Center
|
|
WECC
|
|
CA
|
|
Combined Cycle
|
|
100
|
%
|
|
542
|
|
|
578
|
|
|
589,339
|
|
Los Medanos Energy Center
|
|
WECC
|
|
CA
|
|
Cogen
|
|
100
|
%
|
|
518
|
|
|
572
|
|
|
3,275,237
|
|
South Point Energy Center
(5)
|
|
WECC
|
|
AZ
|
|
Combined Cycle
|
|
100
|
%
|
|
520
|
|
|
530
|
|
|
260,151
|
|
Russell City Energy Center
|
|
WECC
|
|
CA
|
|
Combined Cycle
|
|
75
|
%
|
|
429
|
|
|
464
|
|
|
750,650
|
|
Los Esteros Critical Energy Facility
|
|
WECC
|
|
CA
|
|
Combined Cycle
|
|
100
|
%
|
|
243
|
|
|
309
|
|
|
355,224
|
|
Gilroy Energy Center
|
|
WECC
|
|
CA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
141
|
|
|
25,657
|
|
Gilroy Cogeneration Plant
|
|
WECC
|
|
CA
|
|
Cogen
|
|
100
|
%
|
|
109
|
|
|
130
|
|
|
102,683
|
|
King City Cogeneration Plant
|
|
WECC
|
|
CA
|
|
Cogen
|
|
100
|
%
|
|
120
|
|
|
120
|
|
|
372,736
|
|
Wolfskill Energy Center
|
|
WECC
|
|
CA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
48
|
|
|
9,388
|
|
Yuba City Energy Center
|
|
WECC
|
|
CA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
47
|
|
|
32,148
|
|
Feather River Energy Center
|
|
WECC
|
|
CA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
47
|
|
|
33,113
|
|
Creed Energy Center
|
|
WECC
|
|
CA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
47
|
|
|
13,908
|
|
Lambie Energy Center
|
|
WECC
|
|
CA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
47
|
|
|
13,299
|
|
Goose Haven Energy Center
|
|
WECC
|
|
CA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
47
|
|
|
12,447
|
|
Riverview Energy Center
|
|
WECC
|
|
CA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
47
|
|
|
18,004
|
|
King City Peaking Energy Center
|
|
WECC
|
|
CA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
44
|
|
|
8,584
|
|
Agnews Power Plant
|
|
WECC
|
|
CA
|
|
Combined Cycle
|
|
100
|
%
|
|
28
|
|
|
28
|
|
|
16,080
|
|
Subtotal
|
|
|
|
|
|
|
|
|
|
6,482
|
|
|
7,425
|
|
|
25,246,922
|
|
SEGMENT / Power Plant
|
|
NERC
Region
|
|
U.S. State or
Canadian
Province
|
|
Technology
|
|
Calpine
Interest
Percentage
|
|
Calpine Net
Interest
Baseload
(MW)
(1)(3)
|
|
Calpine Net
Interest
With Peaking
(MW)
(2)(3)
|
|
2018
Total MWh
Generated
(4)
|
||||
TEXAS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Deer Park Energy Center
|
|
TRE
|
|
TX
|
|
Cogen
|
|
100
|
%
|
|
1,103
|
|
|
1,204
|
|
|
6,904,500
|
|
Guadalupe Energy Center
|
|
TRE
|
|
TX
|
|
Combined Cycle
|
|
100
|
%
|
|
1,009
|
|
|
1,000
|
|
|
5,527,007
|
|
Baytown Energy Center
|
|
TRE
|
|
TX
|
|
Cogen
|
|
100
|
%
|
|
810
|
|
|
896
|
|
|
4,329,171
|
|
Channel Energy Center
|
|
TRE
|
|
TX
|
|
Cogen
|
|
100
|
%
|
|
723
|
|
|
808
|
|
|
4,225,208
|
|
Pasadena Power Plant
(6)
|
|
TRE
|
|
TX
|
|
Cogen/Combined Cycle
|
|
100
|
%
|
|
763
|
|
|
781
|
|
|
3,953,102
|
|
Bosque Energy Center
|
|
TRE
|
|
TX
|
|
Combined Cycle
|
|
100
|
%
|
|
740
|
|
|
762
|
|
|
4,179,896
|
|
Freestone Energy Center
|
|
TRE
|
|
TX
|
|
Combined Cycle
|
|
75
|
%
|
|
779
|
|
|
746
|
|
|
4,796,142
|
|
Magic Valley Generating Station
|
|
TRE
|
|
TX
|
|
Combined Cycle
|
|
100
|
%
|
|
682
|
|
|
712
|
|
|
3,290,323
|
|
Jack A. Fusco Energy Center
(7)
|
|
TRE
|
|
TX
|
|
Combined Cycle
|
|
100
|
%
|
|
523
|
|
|
609
|
|
|
2,853,844
|
|
Corpus Christi Energy Center
|
|
TRE
|
|
TX
|
|
Cogen
|
|
100
|
%
|
|
426
|
|
|
500
|
|
|
2,093,699
|
|
Texas City Power Plant
|
|
TRE
|
|
TX
|
|
Cogen
|
|
100
|
%
|
|
400
|
|
|
453
|
|
|
963,151
|
|
Hidalgo Energy Center
|
|
TRE
|
|
TX
|
|
Combined Cycle
|
|
78.5
|
%
|
|
397
|
|
|
379
|
|
|
1,545,307
|
|
Freeport Energy Center
(8)
|
|
TRE
|
|
TX
|
|
Cogen
|
|
100
|
%
|
|
210
|
|
|
236
|
|
|
1,062,358
|
|
Subtotal
|
|
|
|
|
|
|
|
|
|
8,565
|
|
|
9,086
|
|
|
45,723,708
|
|
|
EAST
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Bethlehem Energy Center
|
|
RFC
|
|
PA
|
|
Combined Cycle
|
|
100
|
%
|
|
1,062
|
|
|
1,130
|
|
|
4,164,300
|
|
Hay Road Energy Center
|
|
RFC
|
|
DE
|
|
Combined Cycle
|
|
100
|
%
|
|
1,039
|
|
|
1,130
|
|
|
2,750,315
|
|
York 2 Energy Center
|
|
RFC
|
|
PA
|
|
Combined Cycle
|
|
100
|
%
|
|
668
|
|
|
828
|
|
|
—
|
|
Morgan Energy Center
|
|
SERC
|
|
AL
|
|
Cogen
|
|
100
|
%
|
|
720
|
|
|
807
|
|
|
4,532,864
|
|
Fore River Energy Center
|
|
NPCC
|
|
MA
|
|
Combined Cycle
|
|
100
|
%
|
|
750
|
|
|
731
|
|
|
3,258,006
|
|
Edge Moor Energy Center
|
|
RFC
|
|
DE
|
|
Steam Cycle
|
|
100
|
%
|
|
—
|
|
|
725
|
|
|
316,509
|
|
Granite Ridge Energy Center
|
|
NPCC
|
|
NH
|
|
Combined Cycle
|
|
100
|
%
|
|
745
|
|
|
695
|
|
|
2,177,486
|
|
York Energy Center
|
|
RFC
|
|
PA
|
|
Combined Cycle
|
|
100
|
%
|
|
519
|
|
|
565
|
|
|
1,838,910
|
|
Westbrook Energy Center
|
|
NPCC
|
|
ME
|
|
Combined Cycle
|
|
100
|
%
|
|
552
|
|
|
552
|
|
|
1,497,989
|
|
Greenfield Energy Centre
(9)
|
|
NPCC
|
|
ON
|
|
Combined Cycle
|
|
50
|
%
|
|
422
|
|
|
519
|
|
|
1,033,805
|
|
RockGen Energy Center
|
|
MRO
|
|
WI
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
503
|
|
|
455,771
|
|
Zion Energy Center
|
|
RFC
|
|
IL
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
503
|
|
|
541,758
|
|
Garrison Energy Center
|
|
RFC
|
|
DE
|
|
Combined Cycle
|
|
100
|
%
|
|
273
|
|
|
309
|
|
|
1,339,892
|
|
Pine Bluff Energy Center
|
|
SERC
|
|
AR
|
|
Cogen
|
|
100
|
%
|
|
184
|
|
|
215
|
|
|
1,304,930
|
|
Cumberland Energy Center
|
|
RFC
|
|
NJ
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
191
|
|
|
198,483
|
|
Kennedy International Airport Power Plant
|
|
NPCC
|
|
NY
|
|
Cogen
|
|
100
|
%
|
|
110
|
|
|
121
|
|
|
601,879
|
|
Sherman Avenue Energy Center
|
|
RFC
|
|
NJ
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
92
|
|
|
59,791
|
|
Bethpage Energy Center 3
|
|
NPCC
|
|
NY
|
|
Combined Cycle
|
|
100
|
%
|
|
60
|
|
|
80
|
|
|
121,778
|
|
Carll
’
s Corner Energy Center
|
|
RFC
|
|
NJ
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
73
|
|
|
11,679
|
|
Mickleton Energy Center
|
|
RFC
|
|
NJ
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
67
|
|
|
5,021
|
|
Bethpage Power Plant
|
|
NPCC
|
|
NY
|
|
Combined Cycle
|
|
100
|
%
|
|
55
|
|
|
56
|
|
|
261,959
|
|
Christiana Energy Center
|
|
RFC
|
|
DE
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
53
|
|
|
1,497
|
|
Bethpage Peaker
|
|
NPCC
|
|
NY
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
48
|
|
|
70,378
|
|
Stony Brook Power Plant
|
|
NPCC
|
|
NY
|
|
Cogen
|
|
100
|
%
|
|
45
|
|
|
47
|
|
|
298,483
|
|
Tasley Energy Center
|
|
RFC
|
|
VA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
33
|
|
|
768
|
|
Whitby Cogeneration
(10)
|
|
NPCC
|
|
ON
|
|
Cogen
|
|
50
|
%
|
|
25
|
|
|
25
|
|
|
207,273
|
|
Delaware City Energy Center
|
|
RFC
|
|
DE
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
23
|
|
|
83
|
|
West Energy Center
|
|
RFC
|
|
DE
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
20
|
|
|
699
|
|
SEGMENT / Power Plant
|
|
NERC
Region
|
|
U.S. State or
Canadian
Province
|
|
Technology
|
|
Calpine
Interest
Percentage
|
|
Calpine Net
Interest
Baseload
(MW)
(1)(3)
|
|
Calpine Net
Interest
With Peaking
(MW)
(2)(3)
|
|
2018
Total MWh
Generated
(4)
|
||||
Bayview Energy Center
|
|
RFC
|
|
VA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
12
|
|
|
2,950
|
|
Crisfield Energy Center
|
|
RFC
|
|
MD
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
10
|
|
|
4,488
|
|
Vineland Solar Energy Center
|
|
RFC
|
|
NJ
|
|
Renewable
|
|
100
|
%
|
|
—
|
|
|
4
|
|
|
5,110
|
|
Subtotal
|
|
|
|
|
|
|
|
|
|
7,229
|
|
|
10,167
|
|
|
27,064,854
|
|
|
Total operating power plants
|
|
79
|
|
|
|
|
|
|
|
22,276
|
|
|
26,678
|
|
|
98,035,484
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Power plant sold during 2018
|
|
|
|
|
|
|
|
|
|
|
||||||||
Auburndale Peaking Energy Center
|
|
FRCC
|
|
FL
|
|
Simple Cycle
|
|
100
|
%
|
|
n/a
|
|
|
n/a
|
|
|
—
|
|
Subtotal
|
|
|
|
|
|
|
|
|
|
|
|
|
|
—
|
|
|||
Total operating and sold power plants
|
|
|
|
|
|
|
|
|
|
|
|
|
|
98,035,484
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
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
|
|
|
27,163
|
|
|
|
(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)
|
South Point Energy Center is available for economic dispatch.
|
(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 renewable energy credit sales agreement.
|
Item 1A.
|
Risk Factors
|
•
|
increases and decreases in generation capacity in our markets;
|
•
|
changes in power transmission or fuel transportation capacity constraints or inefficiencies;
|
•
|
volatile weather conditions, particularly unusually hot or mild summers or unusually cold or warm winters in our market areas;
|
•
|
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.
|
•
|
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 the PJM and ISO-NE capacity auctions and the NYISO markets; and
|
•
|
regulations and market rules related to our RECs.
|
•
|
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.
|
•
|
necessary power generation equipment;
|
•
|
governmental permits and approvals including environmental permits and approvals;
|
•
|
fuel supply and transportation agreements;
|
•
|
sufficient equity capital and debt financing;
|
•
|
power transmission agreements;
|
•
|
water supply and wastewater discharge agreements or permits; and
|
•
|
site agreements and construction contracts.
|
•
|
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.
|
•
|
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.
|
•
|
limiting our ability to borrow additional amounts for working capital, capital expenditures, debt service requirements, potential growth or other purposes;
|
•
|
limiting our ability to use operating cash flows in other areas of our business because we must dedicate a substantial portion of these funds to service our debt;
|
•
|
increasing our vulnerability to general adverse economic and industry conditions;
|
•
|
limiting our ability to capitalize on business opportunities and to react to competitive pressures and adverse changes in governmental regulation;
|
•
|
limiting our ability or increasing the costs to refinance indebtedness; and
|
•
|
limiting our ability to enter into marketing, hedging and optimization activities by reducing the number of counterparties with whom we can transact as well as the volume and type of those transactions.
|
•
|
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.
|
•
|
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.
|
Item 1B.
|
Unresolved Staff Comments
|
Item 2.
|
Properties
|
Item 3.
|
Legal Proceedings
|
Item 4.
|
Mine Safety Disclosures
|
Item 5.
|
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
|
|
Years Ended December 31,
|
||||||||||||||||||
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
|
(in millions)
|
||||||||||||||||||
Statement of Operations data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating revenues
|
$
|
9,512
|
|
|
$
|
8,752
|
|
|
$
|
6,716
|
|
|
$
|
6,472
|
|
|
$
|
8,030
|
|
Net income (loss) attributable to Calpine
|
$
|
10
|
|
|
$
|
(339
|
)
|
|
$
|
92
|
|
|
$
|
235
|
|
|
$
|
946
|
|
Balance Sheet data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Total assets
|
$
|
16,062
|
|
|
$
|
16,453
|
|
|
$
|
17,493
|
|
|
$
|
16,849
|
|
|
$
|
16,089
|
|
Short-term debt and capital lease obligations
|
$
|
637
|
|
|
$
|
225
|
|
|
$
|
748
|
|
|
$
|
221
|
|
|
$
|
199
|
|
Long-term debt and capital lease obligations
|
$
|
10,148
|
|
|
$
|
11,180
|
|
|
$
|
11,431
|
|
|
$
|
11,716
|
|
|
$
|
10,933
|
|
Item 7.
|
Management’s Discussion and Analysis of Financial Condition and Results of Operation
s
|
|
2018
|
|
2017
|
|
Change
|
|
% Change
|
|||||||
Operating revenues:
|
|
|
|
|
|
|
|
|||||||
Commodity revenue
|
$
|
9,865
|
|
|
$
|
8,836
|
|
|
$
|
1,029
|
|
|
12
|
|
Mark-to-market loss
|
(373
|
)
|
|
(101
|
)
|
|
(272
|
)
|
|
#
|
|
|||
Other revenue
|
20
|
|
|
17
|
|
|
3
|
|
|
18
|
|
|||
Operating revenues
|
9,512
|
|
|
8,752
|
|
|
760
|
|
|
9
|
|
|||
Operating expenses:
|
|
|
|
|
|
|
|
|||||||
Fuel and purchased energy expense:
|
|
|
|
|
|
|
|
|||||||
Commodity expense
|
6,914
|
|
|
6,268
|
|
|
(646
|
)
|
|
(10
|
)
|
|||
Mark-to-market (gain) loss
|
(165
|
)
|
|
70
|
|
|
235
|
|
|
#
|
|
|||
Fuel and purchased energy expense
|
6,749
|
|
|
6,338
|
|
|
(411
|
)
|
|
(6
|
)
|
|||
Operating and maintenance expense
|
1,020
|
|
|
1,080
|
|
|
60
|
|
|
6
|
|
|||
Depreciation and amortization expense
|
739
|
|
|
724
|
|
|
(15
|
)
|
|
(2
|
)
|
|||
General and other administrative expense
|
158
|
|
|
155
|
|
|
(3
|
)
|
|
(2
|
)
|
|||
Other operating expenses
|
98
|
|
|
85
|
|
|
(13
|
)
|
|
(15
|
)
|
|||
Total operating expenses
|
8,764
|
|
|
8,382
|
|
|
(382
|
)
|
|
(5
|
)
|
|||
Impairment losses
|
10
|
|
|
41
|
|
|
31
|
|
|
76
|
|
|||
(Gain) on sale of assets, net
|
—
|
|
|
(27
|
)
|
|
(27
|
)
|
|
#
|
|
|||
(Income) from unconsolidated subsidiaries
|
(24
|
)
|
|
(22
|
)
|
|
2
|
|
|
9
|
|
|||
Income from operations
|
762
|
|
|
378
|
|
|
384
|
|
|
#
|
|
|||
Interest expense
|
617
|
|
|
621
|
|
|
4
|
|
|
1
|
|
|||
(Gain) loss on extinguishment of debt
|
(28
|
)
|
|
38
|
|
|
66
|
|
|
#
|
|
|||
Other (income) expense, net
|
81
|
|
|
32
|
|
|
(49
|
)
|
|
#
|
|
|||
Income (loss) before income taxes
|
92
|
|
|
(313
|
)
|
|
405
|
|
|
#
|
|
|||
Income tax expense
|
64
|
|
|
8
|
|
|
(56
|
)
|
|
#
|
|
|||
Net income (loss)
|
28
|
|
|
(321
|
)
|
|
349
|
|
|
#
|
|
|||
Net income attributable to the noncontrolling interest
|
(18
|
)
|
|
(18
|
)
|
|
—
|
|
|
—
|
|
|||
Net income (loss) attributable to Calpine
|
$
|
10
|
|
|
$
|
(339
|
)
|
|
$
|
349
|
|
|
#
|
|
|
2018
|
|
2017
|
|
Change
|
|
% Change
|
||||
Operating Performance Metrics:
|
|
|
|
|
|
|
|
||||
MWh generated (in thousands)
(1)(2)
|
95,732
|
|
|
93,114
|
|
|
2,618
|
|
|
3
|
|
Average availability
(2)
|
87.6
|
%
|
|
86.8
|
%
|
|
0.8
|
%
|
|
1
|
|
Average total MW in operation
(1)
|
25,120
|
|
|
25,193
|
|
|
(73
|
)
|
|
—
|
|
Average capacity factor, excluding peakers
|
46.9
|
%
|
|
46.6
|
%
|
|
0.3
|
%
|
|
1
|
|
Steam Adjusted Heat Rate
(2)
|
7,353
|
|
|
7,305
|
|
|
(48
|
)
|
|
(1
|
)
|
#
|
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 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.
|
(in millions)
|
|
|
||
$
|
174
|
|
|
Higher regulatory capacity revenue in our East segment
|
120
|
|
|
Higher energy margins for our wholesale business associated with higher market Spark Spreads across most regions, the positive effect of new PPAs in the West and a gain associated with the cancellation of a PPA recorded during the first quarter of 2018. The increase was partially offset by lower contributions from hedges and lower energy margins associated with our Retail segment primarily in Texas and the Northeast
|
|
31
|
|
|
Higher revenue associated with the sale of environmental credits in our Texas segment during the first quarter of 2018 with no similar activity in 2017
|
|
58
|
|
|
Year-over-year change in contract amortization, lease levelization relating to tolling contracts and other
(1)
|
|
$
|
383
|
|
|
|
(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.
|
|
2017
|
|
2016
|
|
Change
|
|
% Change
|
|||||||
Operating revenues:
|
|
|
|
|
|
|
|
|||||||
Commodity revenue
|
$
|
8,836
|
|
|
$
|
6,943
|
|
|
$
|
1,893
|
|
|
27
|
|
Mark-to-market loss
|
(101
|
)
|
|
(245
|
)
|
|
144
|
|
|
59
|
|
|||
Other revenue
|
17
|
|
|
18
|
|
|
(1
|
)
|
|
(6
|
)
|
|||
Operating revenues
|
8,752
|
|
|
6,716
|
|
|
2,036
|
|
|
30
|
|
|||
Operating expenses:
|
|
|
|
|
|
|
|
|||||||
Fuel and purchased energy expense:
|
|
|
|
|
|
|
|
|||||||
Commodity expense
|
6,268
|
|
|
4,431
|
|
|
(1,837
|
)
|
|
(41
|
)
|
|||
Mark-to-market (gain) loss
|
70
|
|
|
(244
|
)
|
|
(314
|
)
|
|
#
|
|
|||
Fuel and purchased energy expense
|
6,338
|
|
|
4,187
|
|
|
(2,151
|
)
|
|
(51
|
)
|
|||
Operating and maintenance expense
|
1,080
|
|
|
977
|
|
|
(103
|
)
|
|
(11
|
)
|
|||
Depreciation and amortization expense
|
724
|
|
|
662
|
|
|
(62
|
)
|
|
(9
|
)
|
|||
General and other administrative expense
|
155
|
|
|
140
|
|
|
(15
|
)
|
|
(11
|
)
|
|||
Other operating expenses
|
85
|
|
|
79
|
|
|
(6
|
)
|
|
(8
|
)
|
|||
Total operating expenses
|
8,382
|
|
|
6,045
|
|
|
(2,337
|
)
|
|
(39
|
)
|
|||
Impairment losses
|
41
|
|
|
13
|
|
|
(28
|
)
|
|
#
|
|
|||
(Gain) on sale of assets, net
|
(27
|
)
|
|
(157
|
)
|
|
(130
|
)
|
|
(83
|
)
|
|||
(Income) from unconsolidated subsidiaries
|
(22
|
)
|
|
(24
|
)
|
|
(2
|
)
|
|
(8
|
)
|
|||
Income from operations
|
378
|
|
|
839
|
|
|
(461
|
)
|
|
(55
|
)
|
|||
Interest expense
|
621
|
|
|
631
|
|
|
10
|
|
|
2
|
|
|||
Loss on extinguishment of debt
|
38
|
|
|
25
|
|
|
(13
|
)
|
|
(52
|
)
|
|||
Other (income) expense, net
|
32
|
|
|
24
|
|
|
(8
|
)
|
|
(33
|
)
|
|||
Income (loss) before income taxes
|
(313
|
)
|
|
159
|
|
|
(472
|
)
|
|
#
|
|
|||
Income tax expense
|
8
|
|
|
48
|
|
|
40
|
|
|
83
|
|
|||
Net income (loss)
|
(321
|
)
|
|
111
|
|
|
(432
|
)
|
|
#
|
|
|||
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 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.
|
(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.
|
West:
|
2018
|
|
2017
|
|
Change
|
|
% Change
|
|||||||
Commodity Margin (in millions)
|
$
|
1,060
|
|
|
$
|
970
|
|
|
$
|
90
|
|
|
9
|
|
Commodity Margin per MWh generated
|
$
|
41.99
|
|
|
$
|
44.20
|
|
|
$
|
(2.21
|
)
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|||||||
MWh generated (in thousands)
|
25,247
|
|
|
21,946
|
|
|
3,301
|
|
|
15
|
|
|||
Average availability
|
88.5
|
%
|
|
83.2
|
%
|
|
5.3
|
%
|
|
6
|
|
|||
Average total MW in operation
|
7,425
|
|
|
7,425
|
|
|
—
|
|
|
—
|
|
|||
Average capacity factor, excluding peakers
|
41.4
|
%
|
|
35.5
|
%
|
|
5.9
|
%
|
|
17
|
|
|||
Steam Adjusted Heat Rate
|
7,347
|
|
|
7,321
|
|
|
(26
|
)
|
|
—
|
|
Texas:
|
2018
|
|
2017
|
|
Change
|
|
% Change
|
|||||||
Commodity Margin (in millions)
|
$
|
646
|
|
|
$
|
552
|
|
|
$
|
94
|
|
|
17
|
|
Commodity Margin per MWh generated
|
$
|
14.46
|
|
|
$
|
12.80
|
|
|
$
|
1.66
|
|
|
13
|
|
|
|
|
|
|
|
|
|
|||||||
MWh generated (in thousands)
|
44,661
|
|
|
43,117
|
|
|
1,544
|
|
|
4
|
|
|||
Average availability
|
88.8
|
%
|
|
89.3
|
%
|
|
(0.5
|
)%
|
|
(1
|
)
|
|||
Average total MW in operation
|
8,850
|
|
|
8,853
|
|
|
(3
|
)
|
|
—
|
|
|||
Average capacity factor, excluding peakers
|
57.6
|
%
|
|
55.6
|
%
|
|
2.0
|
%
|
|
4
|
|
|||
Steam Adjusted Heat Rate
|
7,152
|
|
|
7,137
|
|
|
(15
|
)
|
|
—
|
|
East:
|
2018
|
|
2017
|
|
Change
|
|
% Change
|
|||||||
Commodity Margin (in millions)
|
$
|
970
|
|
|
$
|
790
|
|
|
$
|
180
|
|
|
23
|
|
Commodity Margin per MWh generated
|
$
|
37.56
|
|
|
$
|
28.16
|
|
|
$
|
9.40
|
|
|
33
|
|
|
|
|
|
|
|
|
|
|||||||
MWh generated (in thousands)
|
25,824
|
|
|
28,051
|
|
|
(2,227
|
)
|
|
(8
|
)
|
|||
Average availability
|
85.5
|
%
|
|
86.7
|
%
|
|
(1.2
|
)%
|
|
(1
|
)
|
|||
Average total MW in operation
|
8,845
|
|
|
8,915
|
|
|
(70
|
)
|
|
(1
|
)
|
|||
Average capacity factor, excluding peakers
|
42.5
|
%
|
|
46.2
|
%
|
|
(3.7
|
)%
|
|
(8
|
)
|
|||
Steam Adjusted Heat Rate
|
7,708
|
|
|
7,568
|
|
|
(140
|
)
|
|
(2
|
)
|
Retail:
|
2018
|
|
2017
|
|
Change
|
|
% Change
|
|||||||
Commodity Margin (in millions)
|
$
|
357
|
|
|
$
|
396
|
|
|
$
|
(39
|
)
|
|
(10
|
)
|
West:
|
2017
|
|
2016
|
|
Change
|
|
% Change
|
|||||||
Commodity Margin (in millions)
|
$
|
970
|
|
|
$
|
984
|
|
|
$
|
(14
|
)
|
|
(1
|
)
|
Commodity Margin per MWh generated
|
$
|
44.20
|
|
|
$
|
37.48
|
|
|
$
|
6.72
|
|
|
18
|
|
|
|
|
|
|
|
|
|
|||||||
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
|
)
|
Texas:
|
2017
|
|
2016
|
|
Change
|
|
% Change
|
|||||||
Commodity Margin (in millions)
|
$
|
552
|
|
|
$
|
543
|
|
|
$
|
9
|
|
|
2
|
|
Commodity Margin per MWh generated
|
$
|
12.80
|
|
|
$
|
11.64
|
|
|
$
|
1.16
|
|
|
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
|
|
|
—
|
|
East:
|
2017
|
|
2016
|
|
Change
|
|
% Change
|
|||||||
Commodity Margin (in millions)
|
$
|
790
|
|
|
$
|
905
|
|
|
$
|
(115
|
)
|
|
(13
|
)
|
Commodity Margin per MWh generated
|
$
|
28.16
|
|
|
$
|
26.34
|
|
|
$
|
1.82
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|||||||
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
|
|
Retail:
|
2017
|
|
2016
|
|
Change
|
|
% Change
|
|||||||
Commodity Margin (in millions)
|
$
|
396
|
|
|
$
|
172
|
|
|
$
|
224
|
|
|
130
|
|
|
2018
|
|
2017
|
||||
Cash and cash equivalents, corporate
(1)
|
$
|
141
|
|
|
$
|
228
|
|
Cash and cash equivalents, non-corporate
(2)
|
64
|
|
|
56
|
|
||
Total cash and cash equivalents
|
205
|
|
|
284
|
|
||
Restricted cash
(2)
|
201
|
|
|
159
|
|
||
Corporate Revolving Facility availability
(3)
|
966
|
|
|
1,161
|
|
||
CDHI letter of credit facility availability
(4)
|
49
|
|
|
56
|
|
||
Other facilities availability
(5)
|
7
|
|
|
—
|
|
||
Total current liquidity availability
|
$
|
1,428
|
|
|
$
|
1,660
|
|
(1)
|
Our ability to use corporate cash and cash equivalents is unrestricted. Includes $52 million and $4 million of margin deposits posted with us by our counterparties at
December 31, 2018
and 2017, respectively. See Note 11 of the Notes to Consolidated Financial Statements for further information related to our collateral.
|
(2)
|
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.
|
(3)
|
Our ability to use availability under our Corporate Revolving Facility is unrestricted. For the year ended December 31, 2018, we utilized an incremental approximately $95 million in capacity primarily through letter of credit issuances. Additionally, on March 8, 2018, the capacity of our Corporate Revolving Facility decreased by $320 million to $1.47 billion, only to be subsequently increased on May 18, 2018, by approximately $220 million to approximately $1.69 billion.
|
(4)
|
Our $300 million CDHI letter of credit facility is restricted to support certain obligations under PPAs and power transmission and natural gas transportation agreements as well as fund the construction of our Washington Parish Energy Center. Pursuant to the terms and conditions of the CDHI credit agreement, the capacity under the CDHI letter of credit facility will be reduced to $125 million on June 30, 2019. The decrease in capacity will not have a material effect on our liquidity as alternative sources of liquidity are available.
|
(5)
|
We have two unsecured letter of credit facilities with third party financial institutions totaling
$200 million
. One of the facilities, with commitments totaling
$150 million
, matures partially in June 2020 and fully by December 2020. The other facility, with commitments totaling
$50 million
, matures in June 2020.
|
•
|
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.
|
|
2018
|
|
2017
|
||||
Corporate Revolving Facility
(1)
|
$
|
693
|
|
|
$
|
629
|
|
CDHI
|
251
|
|
|
244
|
|
||
Various project financing facilities
|
228
|
|
|
196
|
|
||
Other corporate facilities
(2)
|
193
|
|
|
—
|
|
||
Total
|
$
|
1,365
|
|
|
$
|
1,069
|
|
(1)
|
The Corporate Revolving Facility represents our primary revolving facility.
|
(2)
|
We have two unsecured letter of credit facilities with third party financial institutions totaling
$200 million
. One of the facilities, with commitments totaling
$150 million
, matures partially in June 2020 and fully by December 2020. The other facility, with commitments totaling
$50 million
, matures in June 2020.
|
|
2019
|
||
Major maintenance expense
|
$
|
120
|
|
Maintenance capital expenditures
|
385
|
|
|
Growth related capital expenditures
|
205
|
|
|
Total major maintenance expense and capital spending
|
710
|
|
|
Less: Amounts expected to be funded with financing
|
(110
|
)
|
|
Net major maintenance expense and capital spending
|
$
|
600
|
|
|
2018
|
|
2017
|
|
2016
|
||||||
Beginning cash, cash equivalents and restricted cash
|
$
|
443
|
|
|
$
|
606
|
|
|
$
|
1,134
|
|
Net cash provided by (used in):
|
|
|
|
|
|
||||||
Operating activities
|
1,101
|
|
|
949
|
|
|
1,035
|
|
|||
Investing activities
|
(392
|
)
|
|
(211
|
)
|
|
(1,959
|
)
|
|||
Financing activities
|
(746
|
)
|
|
(901
|
)
|
|
396
|
|
|||
Net decrease in cash, cash equivalents and restricted cash
|
(37
|
)
|
|
(163
|
)
|
|
(528
|
)
|
|||
Ending cash, cash equivalents and restricted cash
|
$
|
406
|
|
|
$
|
443
|
|
|
$
|
606
|
|
•
|
Income from operations
—
Income from operations, adjusted for non-cash items, increased by $361 million for the year ended December 31, 2018, compared to the same period in 2017. Non-cash items consist primarily of depreciation and amortization, income from unconsolidated investments in subsidiaries, gain on sale of assets and mark-to-market activity. The increase in income from operations was primarily driven by a $315 million increase in Commodity revenue, net of Commodity expense, excluding non-cash amortization and a $61 million decrease in operating and maintenance expense. See “Results of Operations for the year ended December 31, 2018 and 2017” above for further discussion of these changes.
|
•
|
Working capital employed
—
Working capital employed increased by $179 million for the year ended December 31, 2018 compared to the same period in 2017 after adjusting for changes in debt extinguishment costs and mark-to-market related balances which did not impact cash provided by operating activities. This change was primarily due to an increase in net collateral margining requirements on our commodity hedging activities during the period ended December 31, 2018 as well as an increase in the purchase of environmental products inventory necessary to manage business requirements.
|
•
|
Capital expenditures —
Capital expenditures for the year ended December 31, 2018, were $415 million, an increase of $110 million, compared to expenditures of $305 million for the year ended December 31, 2017. The increase was primarily due to additional capitalization of seasonal maintenance outage costs during 2018 when compared to 2017.
|
•
|
Proceeds from the sale 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, 2018 we sold the Auburndale Peaking Energy Center for net proceeds of $11 million.
|
•
|
Acquisition of Retail Electric Provider —
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. We did not acquire any retail electric providers during the year ended December 31, 2018.
|
•
|
Return of investment in unconsolidated subsidiary —
We received a return of investment of $18 million from our unconsolidated subsidiary, Greenfield LP, during the year ended December 31, 2018. This amount reflects incremental distributions in excess of equity in earnings recognized from our investment in the subsidiary. There was no similar activity during the year ended 2017.
|
•
|
Refinancing and Debt Paydown Activity —
During the year ended December 31, 2017, we utilized cash on hand to repay our outstanding 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. There was no similar activity during the year ended December 31, 2018.
|
•
|
Repurchases of Senior Unsecured Notes —
During the year ended December 31, 2018, we repurchased $390 million in aggregate principal of our Senior Unsecured Notes for $355 million. There was no similar activity during the year ended December 31, 2017.
|
•
|
Project financing, notes payable and other
—
During the year ended December 31, 2018, we refinanced and downsized the project debt associated with OMEC, utilizing the proceeds of $220 million, together with cash on hand, to repay the original project debt of $285 million. There was no similar activity during the year ended December 31, 2017.
|
•
|
Stock Repurchases —
During the year ended December 31, 2018, we repurchased $79 million of our equity classified share-based awards on the effective date of the Merger. There was no similar activity during the same period in 2017.
|
•
|
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 letter of credit 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.
|
•
|
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.
|
•
|
Refinancing and Debt Paydown Activity —
During the year ended December 31, 2017, we utilized cash on hand to repay our outstanding 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.
|
|
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
|
|
Total
|
|
Less than 1
Year
|
|
1-3 Years
|
|
3-5 Years
|
|
More than 5
Years
|
||||||||||
Operating lease obligations
(1)
|
$
|
316
|
|
|
$
|
50
|
|
|
$
|
39
|
|
|
$
|
35
|
|
|
$
|
192
|
|
Purchase obligations:
|
|
|
|
|
|
|
|
|
|
||||||||||
Commodity purchase obligations
(2)
|
$
|
1,116
|
|
|
$
|
415
|
|
|
$
|
306
|
|
|
$
|
194
|
|
|
$
|
201
|
|
LTSA
(3)
|
243
|
|
|
40
|
|
|
52
|
|
|
62
|
|
|
89
|
|
|||||
Water agreements
(4)
|
404
|
|
|
26
|
|
|
54
|
|
|
50
|
|
|
274
|
|
|||||
Other purchase obligations
(5)
|
303
|
|
|
149
|
|
|
79
|
|
|
22
|
|
|
53
|
|
|||||
Total purchase obligations
|
$
|
2,066
|
|
|
$
|
630
|
|
|
$
|
491
|
|
|
$
|
328
|
|
|
$
|
617
|
|
Debt
|
$
|
10,918
|
|
|
$
|
642
|
|
|
$
|
505
|
|
|
$
|
3,554
|
|
|
$
|
6,217
|
|
Other contractual obligations:
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest payments on debt
(6)
|
$
|
2,929
|
|
|
$
|
583
|
|
|
$
|
1,092
|
|
|
$
|
876
|
|
|
$
|
378
|
|
Liability for uncertain tax positions
|
30
|
|
|
1
|
|
|
9
|
|
|
2
|
|
|
18
|
|
|||||
Interest rate hedging instruments
(6)
|
12
|
|
|
5
|
|
|
5
|
|
|
2
|
|
|
—
|
|
|||||
Total other contractual obligations
|
$
|
2,971
|
|
|
$
|
589
|
|
|
$
|
1,106
|
|
|
$
|
880
|
|
|
$
|
396
|
|
Total contractual obligations
|
$
|
16,271
|
|
|
$
|
1,911
|
|
|
$
|
2,141
|
|
|
$
|
4,797
|
|
|
$
|
7,422
|
|
(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 contractually obligated amounts 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 estimated payments in accordance with the stated payment terms in the contracts at the time of execution. The minimum contractually obligated amount at December 31, 2018 associated with our LTSAs is $18 million.
|
(4)
|
The amounts presented here are based on contractually obligated amounts over the life of the contracts.
|
(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 spot and forward interest rates at
December 31, 2018
.
|
|
Commodity Instruments
|
|
Interest Rate
Hedging Instruments |
|
Total
|
||||||
Fair value of contracts outstanding at January 1, 2018
|
$
|
81
|
|
|
$
|
(5
|
)
|
|
$
|
76
|
|
Items recognized or otherwise settled during the period
(1)(2)
|
59
|
|
|
11
|
|
|
70
|
|
|||
Fair value attributable to new contracts
(3)
|
(47
|
)
|
|
—
|
|
|
(47
|
)
|
|||
Changes in fair value attributable to price movements
|
(264
|
)
|
|
24
|
|
|
(240
|
)
|
|||
Fair value of contracts outstanding at December 31, 2018
(4)
|
$
|
(171
|
)
|
|
$
|
30
|
|
|
$
|
(141
|
)
|
(1)
|
Commodity contract settlements consist of the realization of previously recognized losses on contracts not designated as hedging instruments of $91 million (represents a portion of Commodity revenue and Commodity expense as reported on our Consolidated Statements of Operations) and $32 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 $8 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) and $1 million relating to an interest rate hedging instrument that was terminated as a result of the refinancing of project debt in the fourth quarter of 2018.
|
(3)
|
Fair value attributable to new contracts includes $3 million and nil of fair value related to commodity contracts and interest rate hedging instruments, respectively, which are not reflected in OCI or earnings.
|
(4)
|
We netted all amounts allowed under the derivative accounting guidance on the Consolidated Balance Sheet, which includes derivative transactions under enforceable master netting arrangements and related cash collateral. Net commodity and interest rate derivative assets and liabilities reported in Notes 9 and 10 of the Notes to Consolidated Financial Statements and are shown net of collateral paid to and received from counterparties under legally enforceable master netting arrangements.
|
Fair Value Source
|
|
2019
|
|
2020-2021
|
|
2022-2023
|
|
After 2023
|
|
Total
|
||||||||||
Prices actively quoted
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Prices provided by other external sources
|
|
(122
|
)
|
|
(43
|
)
|
|
2
|
|
|
—
|
|
|
(163
|
)
|
|||||
Prices based on models and other valuation methods
|
|
(57
|
)
|
|
27
|
|
|
5
|
|
|
17
|
|
|
(8
|
)
|
|||||
Total fair value
|
|
$
|
(179
|
)
|
|
$
|
(16
|
)
|
|
$
|
7
|
|
|
$
|
17
|
|
|
$
|
(171
|
)
|
•
|
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
|
•
|
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.
|
Credit Quality
(Based on Standard & Poor’s Ratings
as of December 31, 2018)
|
|
2019
|
|
2020-2021
|
|
2022-2023
|
|
After 2023
|
|
Total
|
||||||||||
Investment grade
|
|
$
|
(135
|
)
|
|
$
|
(41
|
)
|
|
$
|
(5
|
)
|
|
$
|
1
|
|
|
$
|
(180
|
)
|
Non-investment grade
|
|
(11
|
)
|
|
(11
|
)
|
|
(2
|
)
|
|
—
|
|
|
(24
|
)
|
|||||
No external ratings
(1)
|
|
(33
|
)
|
|
36
|
|
|
14
|
|
|
16
|
|
|
33
|
|
|||||
Total fair value
|
|
$
|
(179
|
)
|
|
$
|
(16
|
)
|
|
$
|
7
|
|
|
$
|
17
|
|
|
$
|
(171
|
)
|
(1)
|
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.
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
Thereafter
|
|
Total
|
|
Fair Value
December 31,
2018
|
||||||||||||||||
Debt by Maturity Date:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Fixed Rate
|
$
|
24
|
|
|
$
|
8
|
|
|
$
|
7
|
|
|
$
|
758
|
|
|
$
|
1,244
|
|
|
$
|
3,514
|
|
|
$
|
5,555
|
|
|
$
|
5,182
|
|
Average Interest Rate
|
4.1
|
%
|
|
6.5
|
%
|
|
6.1
|
%
|
|
6.0
|
%
|
|
5.4
|
%
|
|
5.6
|
%
|
|
|
|
|
||||||||||
Variable Rate
|
$
|
593
|
|
|
$
|
210
|
|
|
$
|
223
|
|
|
$
|
235
|
|
|
$
|
1,238
|
|
|
$
|
2,639
|
|
|
$
|
5,138
|
|
|
$
|
4,974
|
|
Average Interest Rate
(1)
|
4.5
|
%
|
|
4.4
|
%
|
|
4.4
|
%
|
|
4.4
|
%
|
|
5.0
|
%
|
|
5.2
|
%
|
|
|
|
|
(1)
|
Projection based upon forward LIBOR rates inferred from spot rates at
December 31, 2018
.
|
•
|
a contract that qualifies as a lease;
|
•
|
a derivative;
|
•
|
a contract that meets the definition of a derivative but is eligible for the normal purchase normal sale exemption; or
|
•
|
a contract that is a physical or executory contract.
|
•
|
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
|
•
|
sales of natural gas and other service revenues.
|
•
|
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 as contractual changes where 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.
|
•
|
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.
|
Item 7A.
|
Quantitative and Qualitative Disclosures about Market Risk
|
Item 8.
|
Financial Statements and Supplementary Data
|
Item 9.
|
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
|
Item 9A.
|
Controls and Procedures
|
•
|
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.
|
Item 9B.
|
Other Information
|
Item 10.
|
Directors, Executive Officers and Corporate Governance
|
Name
|
|
Age
|
|
Principal Occupation
|
Avik Dey
|
|
41
|
|
Managing Director, Canada Pension Plan Investment Board
|
Andrew Gilbert
|
|
32
|
|
Principal, Energy Capital Partners
|
John B. (Thad) Hill III
|
|
51
|
|
President and Chief Executive Officer, Calpine Corporation
|
Douglas W. Kimmelman
|
|
58
|
|
Senior Partner and Founder, Energy Capital Partners
|
W. Thaddeus Miller
|
|
68
|
|
Executive Vice Chairman, Chief Legal Officer and Secretary, Calpine Corporation
|
Tyler G. Reeder
|
|
45
|
|
Managing Partner, Energy Capital Partners
|
Andrew D. Singer
|
|
56
|
|
Partner and General Counsel, Energy Capital Partners
|
Donald A. Wagner
|
|
55
|
|
Managing Director, Access Industries
|
Name
|
|
Age
|
|
Position
|
|
John B. (Thad) Hill III
(1)
|
|
51
|
|
|
President and Chief Executive Officer
|
Zamir Rauf
|
|
59
|
|
|
Executive Vice President and Chief Financial Officer
|
W. Thaddeus Miller
(1)
|
|
68
|
|
|
Executive Vice Chairman, Chief Legal Officer and Secretary
|
Charles M. Gates
|
|
67
|
|
|
Executive Vice President, Power Operations
|
(1)
|
See “Directors” above for biographical information.
|
Item 11.
|
Executive Compensation
|
John B. (Thad) Hill III
|
President and Chief Executive Officer
|
Zamir Rauf
|
Executive Vice President and Chief Financial Officer
|
W. Thaddeus Miller
|
Executive Vice Chairman, Chief Legal Officer and Secretary
|
Charles M. Gates
|
Executive Vice President, Power Operations
|
W.G. (Trey) Griggs III
|
Former Executive Vice President and President, Calpine Retail
|
•
|
Alignment with Owners’ Interests.
Our long-term incentive awards align our named executive officers’ interests with the interests of our owners by rewarding increases in the value of our business, incentivizing retention and optimizing long-term financial performance.
|
•
|
Pay for Performance.
A significant portion of compensation for our named executive officers is linked to the achievement of corporate operating and financial objectives that we believe drive long-term 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 potential value of long-term incentives could be
|
•
|
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 Class B Interests (as described in “Details of Each Element of Compensation — Long-Term Incentives” below) over approximately five years.
|
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 our owners.
|
Long-Term Incentives
|
Align executive officers’ interests with the interests of owners by rewarding increases in the value of our business.
|
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.
|
•
|
our budget for annual merit increases;
|
•
|
the appropriateness of each executive officer’s compensation, both individually and relative to the other executive officers; and
|
•
|
the individual performance of each executive officer.
|
|
2018
|
|
|||||
|
Base Salary
|
|
Percentage increase from previous year
|
|
|||
John B. (Thad) Hill III
|
$
|
1,230,000
|
|
|
2.5
|
%
|
|
Zamir Rauf
|
$
|
656,103
|
|
|
2.5
|
%
|
|
W. Thaddeus Miller
|
$
|
893,003
|
|
|
2.5
|
%
|
|
Charles M. Gates
|
$
|
483,288
|
|
|
2.5
|
%
|
|
Performance Level Performance Score
|
|
Threshold
|
|
Target
|
|
Maximum
|
|
Results
|
|
Score
|
|
Weight
|
|
Weighted Score
|
|
||||||||||||||
Commodity Margin
|
|
$
|
2,843
|
|
|
$
|
2,943
|
|
|
$
|
3,143
|
|
|
$
|
3,091
|
|
|
|
174.0
|
|
%
|
|
35.0
|
|
%
|
|
60.9
|
|
%
|
Expenses
|
|
$
|
1,062
|
|
|
$
|
981
|
|
|
$
|
730
|
|
|
$
|
1,014
|
|
|
|
83.7
|
|
%
|
|
35.0
|
|
%
|
|
29.3
|
|
%
|
CAPEX/Maintenance
|
|
$
|
439
|
|
|
$
|
411
|
|
|
$
|
353
|
|
|
$
|
428
|
|
|
|
76.0
|
|
%
|
|
10.0
|
|
%
|
|
7.6
|
|
%
|
TRIR
|
|
|
1.4
|
|
|
|
0.80
|
|
|
|
0.40
|
|
|
|
0.66
|
|
|
|
118.0
|
|
%
|
|
10.0
|
|
%
|
|
11.8
|
|
%
|
Average EFOF
|
|
|
5.56
|
|
%
|
|
3.6
|
|
%
|
|
1.71
|
|
%
|
|
4.54
|
|
%
|
|
80.0
|
|
%
|
|
5.0
|
|
%
|
|
4.0
|
|
%
|
Regulatory Compliance (Pass/Fail)
|
|
No material non-compliance events
|
|
|
PASS
|
|
|
100.0
|
|
%
|
|
5.0
|
|
%
|
|
5.0
|
|
%
|
|||||||||||
Overall Performance Score
|
|
100
|
|
%
|
|
118.6
|
|
%
|
|||||||||||||||||||||
Board Discretionary Increase (Decrease) Factor
|
|
|
|
|
1.0
|
|
|
||||||||||||||||||||||
Final Performance Score
|
|
|
|
|
118.6
|
|
%
|
•
|
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.
|
•
|
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
|
•
|
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 of Directors’ consideration of the quantitative outcomes of the Performance Measures and any additional factors taken into consideration which would result in the Board of Directors, in its discretion, adjusting the calculated outcomes.
|
Name
|
|
Incentive Eligible Earnings
|
|
Target Incentive %
|
|
Maximum Incentive %
|
|
Incremental Incentive Rate
(3)
|
|
Incentive Calculation Overall
Performance
Score
(4)
|
|
Incentive %
(5)
|
|
Incentive Amount
|
||||||||
John B. (Thad) Hill III
(1)
|
|
$
|
1,224,231
|
|
|
110
|
%
|
|
220
|
%
|
|
2.0
|
|
118.6
|
%
|
|
150.9
|
%
|
|
$
|
1,847,609
|
|
Zamir Rauf
(1)
|
|
$
|
653,026
|
|
|
90
|
%
|
|
200
|
%
|
|
2.22
|
|
118.6
|
%
|
|
127.2
|
%
|
|
$
|
830,649
|
|
W. Thaddeus Miller
(1)
|
|
$
|
888,814
|
|
|
90
|
%
|
|
200
|
%
|
|
2.22
|
|
118.6
|
%
|
|
127.2
|
%
|
|
$
|
1,130,572
|
|
Charles M. Gates
(2)
|
|
$
|
469,868
|
|
|
90
|
%
|
|
200
|
%
|
|
2.22
|
|
118.6
|
%
|
|
127.2
|
%
|
|
$
|
597,672
|
|
(1)
|
The maximum incentive as a percentage of base salary is set forth in the employment agreement for these named executive officers.
|
(2)
|
Mr. 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 2018 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.
|
Name
|
|
Time Vested Class B Interests
|
|
Grant Date
|
John B. (Thad) Hill III
|
|
1.3900%
|
|
March 8, 2018
|
Zamir Rauf
|
|
0.3900%
|
|
March 8, 2018
|
Zamir Rauf
|
|
0.0100%
|
|
August 29, 2018
|
W. Thaddeus Miller
|
|
0.5300%
|
|
March 8, 2018
|
Charles M. Gates
|
|
0.1700%
|
|
March 8, 2018
|
Charles M. Gates
|
|
0.0200%
|
|
August 29, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-Equity
|
|
|
|
|
|||||||
|
|
|
|
|
|
|
|
Option
|
|
Stock
|
|
Incentive Plan
|
|
All Other
|
|
|
|||||||
|
|
|
|
Salary
|
|
Bonus
|
|
Awards
|
|
Awards
|
|
Compensation
|
|
Compensation
|
|
Total
|
|||||||
Name and Principal Position
|
|
Year
|
|
($)
|
|
($)
(1)
|
|
($)
(2)
|
|
($)
(2)
|
|
($)
(3)
|
|
($)
(4)(5)
|
|
($)
|
|||||||
John B. (Thad) Hill III
|
|
2018
|
|
1,233,279
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,847,609
|
|
|
10,272,030
|
|
|
13,352,918
|
|
President and Chief
|
|
2017
|
|
1,182,486
|
|
|
—
|
|
|
1,663,591
|
|
|
2,631,318
|
|
|
1,284,741
|
|
|
13,500
|
|
|
6,775,636
|
|
Executive Officer
|
|
2016
|
|
1,129,410
|
|
|
—
|
|
|
—
|
|
|
3,727,625
|
|
|
1,261,393
|
|
|
13,250
|
|
|
6,131,678
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Zamir Rauf
|
|
2018
|
|
658,490
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
830,649
|
|
|
4,266,125
|
|
|
5,755,264
|
|
Executive Vice President and
|
|
2017
|
|
643,513
|
|
|
—
|
|
|
581,045
|
|
|
894,072
|
|
|
568,801
|
|
|
13,500
|
|
|
2,700,931
|
|
Chief Financial Officer
|
|
2016
|
|
630,173
|
|
|
—
|
|
|
—
|
|
|
1,376,402
|
|
|
574,306
|
|
|
13,250
|
|
|
2,594,131
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
W. Thaddeus Miller
|
|
2018
|
|
913,321
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,130,572
|
|
|
3,858,850
|
|
|
5,902,743
|
|
Executive Vice Chairman,
|
|
2017
|
|
888,119
|
|
|
—
|
|
|
790,838
|
|
|
1,216,895
|
|
|
774,179
|
|
|
13,500
|
|
|
3,683,531
|
|
Chief Legal Officer and
|
|
2016
|
|
870,228
|
|
|
—
|
|
|
—
|
|
|
1,873,382
|
|
|
781,671
|
|
|
48,250
|
|
|
3,573,531
|
|
Secretary
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Charles M. Gates
|
|
2018
|
|
496,188
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
597,672
|
|
|
1,974,503
|
|
|
3,068,363
|
|
Executive Vice President,
|
|
2017
|
|
482,768
|
|
|
—
|
|
|
427,995
|
|
|
658,580
|
|
|
409,385
|
|
|
13,500
|
|
|
1,992,228
|
|
Power Operations
|
|
2016
|
|
356,713
|
|
|
200,000
|
|
|
—
|
|
|
902,067
|
|
|
425,029
|
|
|
13,250
|
|
|
1,897,059
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
W.G. (Trey) Griggs III
(6)
|
|
2018
|
|
127,664
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5,681,913
|
|
|
5,809,577
|
|
Former Executive Vice
|
|
2017
|
|
524,830
|
|
|
—
|
|
|
476,846
|
|
|
733,747
|
|
|
467,270
|
|
|
13,500
|
|
|
2,216,193
|
|
President and President,
|
|
2016
|
|
513,976
|
|
|
—
|
|
|
—
|
|
|
1,129,565
|
|
|
455,325
|
|
|
13,250
|
|
|
2,112,116
|
|
Calpine Retail
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Represents a one-time cash sign-on bonus in 2016 for Mr. Gates in conjunction with the commencement of his employment on April 1, 2016.
|
(2)
|
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. For discussion of the assumptions used in these valuations, see Note 13 of the Notes to Consolidated Financial Statements.
|
(3)
|
Bonus paid pursuant to the CIP and/or the named executive officer’s employment agreement or letter agreement, as applicable.
|
(4)
|
For 2018, the amounts set forth under “All Other Compensation” for Messrs. Hill, Rauf, Miller and Gates represents $13,750 in employer contributions to the Company’s 401(k) Plan and $2,500 in non-discretionary employer contribution. For Messrs. Hill, Rauf, Miller, Gates and Griggs, the amount also includes $10,236,012, $4,240,310, $3,829,422, $1,958,253 and $2,690,744, respectively, in cash payments made by the Company associated with outstanding unvested share-based awards in connection with the Merger. For Messrs. Hill, Rauf and Miller, the amount includes $19,768, $9,565 and $13,178, respectively, in legal fees in connection with the amendment to their employment agreements. For Mr. Griggs, the amount includes $6,869 in employer contributions to the Company’s 401(k) Plan and $2,984,300 in severance payments in connection with his employment termination in March 2018.
|
(5)
|
The Class B Interests do not have a grant date fair value as these awards are accounted for as profit sharing arrangements under FASB Accounting Standards Codification Topic 710. For a further description of the Class B Interests, see “Compensation Discussion and Analysis — Elements of Compensation — Details of Each Element of Compensation — Long-Term Incentives.” The market value for the Class B Interests is not determinable as there is no public market for the Class B Interests. As such, the fair value of the Class B Interests is not included herein. We did not record any expense in our Consolidated Statement of Operations for the year ended December 31, 2018 associated with the Class B Interests.
|
(6)
|
Mr. Griggs departed the Company on March 8, 2018.
|
|
|
Estimated Future Payouts Under Non-Equity Incentive Plan Awards
(1)
|
|||||
Name
|
Grant Date
|
Threshold
($)
|
Target
($)
|
Maximum
($)
|
|||
John B. (Thad) Hill III
|
—
|
807,992
|
|
1,346,654
|
|
2,693,308
|
|
|
|
|
|
|
|||
Zamir Rauf
|
—
|
352,634
|
|
587,723
|
|
1,306,052
|
|
|
|
|
|
|
|||
W. Thaddeus Miller
|
—
|
479,960
|
|
799,933
|
|
1,777,628
|
|
|
|
|
|
|
|||
Charles M. Gates
|
—
|
253,729
|
|
422,881
|
|
939,736
|
|
(1)
|
Amounts represent estimated possible payments under the CIP. Actual amounts paid under the CIP for 2018 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.”
|
|
|
Stock Awards
|
||||
Name
|
|
Number of Shares Acquired on Vesting
(#)
|
|
Value Realized
on Vesting
($)
|
||
John B. (Thad) Hill III
|
|
111,006
|
|
|
1,683,580
|
|
Zamir Rauf
|
|
40,989
|
|
|
621,662
|
|
W. Thaddeus Miller
|
|
—
|
|
|
—
|
|
Charles M. Gates
|
|
10,755
|
|
|
162,078
|
|
W.G. (Trey) Griggs
|
|
25,872
|
|
|
391,974
|
|
•
|
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 the Consolidated Omnibus Budget Reconciliation Act of 1985, as amended, “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.
|
•
|
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
|
•
|
a prorated bonus for the year in which such termination occurs;
|
•
|
a lump sum cash severance payment equal to 3.0 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 or for 2018, whichever is larger;
|
•
|
a monthly payment for a period of 36 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; and
|
•
|
reimbursement for payment for outplacement services for a period of up to 24 months following such termination.
|
•
|
a prorated bonus for the year in which such termination occurs calculated based on the Company’s actual performance;
|
•
|
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; and
|
•
|
reimbursement for payment for outplacement services for a period of up to 24 months following such termination.
|
•
|
a full annual bonus for the year in which such termination occurs calculated based on actual Company performance; and
|
•
|
a monthly payment for a period of 18 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.
|
•
|
a prorated bonus for the year in which such termination occurs calculated based on actual Company performance and the number of days in the year of termination that Mr. Hill was employed by the Company;
|
•
|
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; and
|
•
|
consent rights regarding certain redemption, repurchase, and / or call rights that may be applicable to vested Class B Interests.
|
•
|
in the event of a change in control of the Company, the Class B Interests will become fully vested; and
|
•
|
if Mr. Hill’s employment terminates by reason of disability or death, the Class B Interests will become fully vested.
|
•
|
a prorated bonus for the year in which such termination would have occurred calculated based on actual Company performance;
|
•
|
a lump sum cash severance payment equal to 3.0 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 or for 2018, if higher;
|
•
|
a monthly payment for a period of 36 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; and
|
•
|
outplacement services for a period of up to 18 months following such termination.
|
•
|
a prorated bonus for the year in which such termination occurs calculated based on actual Company performance;
|
•
|
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;
|
•
|
a monthly payment for a period of 18 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; and
|
•
|
reimbursement for payment for outplacement services for a period of up to 18 months following such termination.
|
•
|
a full annual bonus for the year in which such termination occurs calculated based on actual Company performance; and
|
•
|
for the remainder of the employment term, a monthly payment 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.
|
•
|
a prorated bonus for the year in which such termination occurs calculated based on actual Company performance;
|
•
|
a monthly payment for a period of 18 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; and
|
•
|
consent rights regarding certain redemption, repurchase, and / or call rights that may be applicable to vested Class B Interests.
|
•
|
in the event of a change in control of the Company, the Class B Interests will become fully vested; and
|
•
|
if Mr. Miller’s employment terminates by reason of disability or death, the Class B Interests will become fully vested.
|
•
|
a prorated bonus for the year in which such termination would have occurred;
|
•
|
a lump sum cash severance payment equal to 3.0 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 or for 2018, whichever is larger;
|
•
|
a monthly payment for a period of 36 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; and
|
•
|
outplacement services for a period of up to 18 months following such termination.
|
•
|
a prorated bonus for the year in which such termination occurs;
|
•
|
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;
|
•
|
a monthly payment for a period of 18 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; and
|
•
|
reimbursement for payment for outplacement services for a period of up to 18 months following such termination.
|
•
|
a full annual bonus for the year in which such termination occurs calculated based on actual Company performance; and
|
•
|
for the remainder of the employment term, a monthly payment 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.
|
•
|
a prorated bonus for the year in which such termination occurs calculated based on actual Company performance;
|
•
|
a monthly payment for a period of 18 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; and
|
•
|
consent rights regarding certain redemption, repurchase, and / or call rights that may be applicable to vested Class B Interests.
|
•
|
in the event of a change in control of the Company, the Class B Interests will become fully vested; and
|
•
|
if Mr. Rauf’s employment terminates by reason of disability or death, the Class B Interests will become fully vested.
|
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
|
|
Death or Disability
|
||||||||||
John B. (Thad) Hill III
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash Compensation
(1)
|
|
$
|
—
|
|
|
$
|
9,596,609
|
|
|
$
|
9,596,609
|
|
|
$
|
9,596,609
|
|
|
$
|
1,847,609
|
|
Health and Welfare Benefits
(2)
|
|
—
|
|
|
97,200
|
|
|
97,200
|
|
|
97,200
|
|
|
48,600
|
|
|||||
Outplacement
(2)
|
|
—
|
|
|
55,000
|
|
|
55,000
|
|
|
55,000
|
|
|
—
|
|
|||||
Unvested Class B Interests
(3)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
TOTAL
|
|
$
|
—
|
|
|
$
|
9,748,809
|
|
|
$
|
9,748,809
|
|
|
$
|
9,748,809
|
|
|
$
|
1,896,209
|
|
Zamir Rauf
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash Compensation
(1)
|
|
$
|
830,649
|
|
|
$
|
4,570,436
|
|
|
$
|
4,570,436
|
|
|
$
|
4,570,436
|
|
|
$
|
830,649
|
|
Health and Welfare Benefits
(2)
|
|
—
|
|
|
97,200
|
|
|
97,200
|
|
|
97,200
|
|
|
137,700
|
|
|||||
Outplacement
(2)
|
|
—
|
|
|
50,000
|
|
|
50,000
|
|
|
50,000
|
|
|
—
|
|
|||||
Unvested Class B Interests
(3)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
TOTAL
|
|
$
|
830,649
|
|
|
$
|
4,717,636
|
|
|
$
|
4,717,636
|
|
|
$
|
4,717,636
|
|
|
$
|
968,349
|
|
W. Thaddeus Miller
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash Compensation
(1)
|
|
$
|
1,130,572
|
|
|
$
|
6,220,689
|
|
|
$
|
6,220,689
|
|
|
$
|
6,220,689
|
|
|
$
|
1,130,572
|
|
Health and Welfare Benefits
(2)
|
|
—
|
|
|
67,752
|
|
|
67,752
|
|
|
67,752
|
|
|
95,982
|
|
|||||
Outplacement
(2)
|
|
—
|
|
|
50,000
|
|
|
50,000
|
|
|
50,000
|
|
|
—
|
|
|||||
Unvested Class B Interests
(3)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
TOTAL
|
|
$
|
1,130,572
|
|
|
$
|
6,338,441
|
|
|
$
|
6,338,441
|
|
|
$
|
6,338,441
|
|
|
$
|
1,226,554
|
|
Charles M. Gates
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash Compensation
(1)
|
|
$
|
—
|
|
|
$
|
1,377,371
|
|
|
$
|
1,377,371
|
|
|
$
|
2,745,559
|
|
|
$
|
—
|
|
Health and Welfare Benefits
(2)
|
|
—
|
|
|
33,876
|
|
|
33,876
|
|
|
67,752
|
|
|
—
|
|
|||||
Outplacement
(2)
|
|
—
|
|
|
50,000
|
|
|
50,000
|
|
|
50,000
|
|
|
—
|
|
|||||
Unvested Class B Interests
(3)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Tax Gross-Up
(4)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
995,484
|
|
|
—
|
|
|||||
TOTAL
|
|
$
|
—
|
|
|
$
|
1,461,247
|
|
|
$
|
1,461,247
|
|
|
$
|
3,858,795
|
|
|
$
|
—
|
|
(1)
|
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 2018 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 $2,700 per month (for family coverage) which applied to Messrs. Hill and Rauf and $1,882 per month (for employee and spouse coverage) which applied to Messrs. Miller and Gates. Outplacement services were valued at $50,000 and $55,000 for 18 and 24 months, respectively, of coverage.
|
(3)
|
Class B Interests only entitle the holder to future distributions from CPN Management. Distributions from CPN Management are made at the discretion of the general partner.
|
(4)
|
The gross-up payment is an additional amount that we are obligated to pay to Mr. Gates pursuant to the Gates Letter Agreement in order to make the executive whole for any federal excise tax imposed on the executive as a result of the executive’s receipt of any excess parachute payments that are contingent upon a change of control, as well as the payment of all federal and state income and excise taxes imposed on the gross-up payment.
|
•
|
base salary,
|
•
|
compensation under the annual incentive program or equivalent (calculated assuming payouts at the target level for employees hired in 2018 who were not eligible for an incentive payment in 2018),
|
•
|
cash-out of unvested share-based awards in connection with the closing of the Merger, and
|
•
|
employer contributions to the Company’s 401(k) Plan.
|
Name
|
Fees Earned or
Paid in Cash ($)
|
|
All Other Compensation ($)
(1)
|
|
Total ($)
|
|
Mary L. Brlas
|
16,750
|
|
136,289
|
|
|
153,039
|
Frank Cassidy
|
37,967
|
|
502,015
|
|
|
539,982
|
Jack A. Fusco
|
14,144
|
|
1,856,253
|
|
|
1,870,397
|
Michael W. Hofmann
|
19,356
|
|
437,889
|
|
|
457,245
|
David C. Merritt
|
20,472
|
|
534,985
|
|
|
555,457
|
W. Benjamin Moreland
|
16,750
|
|
128,253
|
|
|
145,003
|
Robert A. Mosbacher, Jr.
|
21,217
|
|
128,253
|
|
|
149,470
|
Denise M. O’Leary
|
21,217
|
|
128,253
|
|
|
149,470
|
Avik Dey
|
—
|
|
—
|
|
|
—
|
Andrew Gilbert
|
—
|
|
—
|
|
|
—
|
Douglas W. Kimmelman
|
—
|
|
—
|
|
|
—
|
Tyler G. Reeder
|
—
|
|
—
|
|
|
—
|
Andrew D. Singer
|
—
|
|
—
|
|
|
—
|
Donald A. Wagner
|
—
|
|
—
|
|
|
—
|
(1)
|
The amounts set forth under “All Other Compensation” represent cash payments made by the Company associated with outstanding unvested and vested but not released share-based awards in connection with the Merger.
|
|
|
Annual Retainer ($)
|
|
Meeting Fees ($)
|
|
Committee Chair Retainer ($)
|
Outside Board Members
|
|
56,000
|
|
20,000
|
|
—
|
Chairman of the Board
|
|
100,000
(1)
|
|
—
|
|
—
|
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)
|
The independent Chairman of the Board received this amount in addition to the annual retainer paid to independent outside board members.
|
Item 12.
|
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
|
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 Owners
|
|
|
|
|
|
|
|
||||
CPN Management
(1)
|
105.2
|
|
|
—
|
|
|
105.2
|
|
|
100.0
|
%
|
Named Executive Officers and Directors
|
|
|
|
|
|
|
|
||||
John B. (Thad) Hill III
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Zamir Rauf
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
W. Thaddeus Miller
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Charles M. Gates
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Avik Dey
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Andrew Gilbert
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Douglas W. Kimmelman
(2)
|
105.2
|
|
|
—
|
|
|
105.2
|
|
|
100
|
%
|
Tyler G. Reeder
(2)
|
105.2
|
|
|
—
|
|
|
105.2
|
|
|
100
|
%
|
Andrew D. Singer
(2)
|
105.2
|
|
|
—
|
|
|
105.2
|
|
|
100
|
%
|
Donald A. Wagner
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
All executive officers and directors as a group
(10 persons)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
(1)
|
The principal business address of CPN Management, LP is 51 John F. Kennedy Parkway, Suite 200, Short Hills, NJ 07078.
|
(2)
|
ECP ControlCo, LLC is the sole managing member of Energy Capital Partners GP III, LLC, which is the sole managing member of Volt Parent GP, LLC which is the general partner of each of Volt Parent, LP and CPN Management. Douglas Kimmelman, 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 GP III, LLC, Volt Parent GP, LLC, and Messrs. Kimmelman, Singer, Labbat, Reeder and D’Argenio may be deemed to have or share beneficial ownership of the common stock held directly by CPN Management. 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, NJ 07078.
|
Item 13.
|
Certain Relationships and Related Transactions, and Director Independence
|
•
|
ECP ControlCo, LLC
|
•
|
CPPIB Calpine Canada, Inc.
|
•
|
Access Industries, Inc.
|
Item 14.
|
Principal Accounting Fees and Services
|
|
2018
|
|
2017
|
||||
|
(in millions)
|
||||||
Audit Fees
(1)(2)
|
$
|
5.4
|
|
|
$
|
6.6
|
|
(1)
|
Our Audit fees consisted of approximately $4.4 million and $5.5 million for the audits and quarterly reviews of our consolidated financial statements, registration statements and offerings for Calpine Corporation for 2018 and 2017, respectively, and fees of approximately $1.0 million and $1.1 million for 2018 and 2017, 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, 2018 and 2017.
|
Item 15.
|
Exhibits, Financial Statement Schedule
|
|
Page
|
(a)-1.
Financial Statements and Other Information
|
|
Calpine Corporation and Subsidiaries
|
|
(a)-2.
Financial Statement Schedule
|
|
Calpine Corporation and Subsidiaries
|
|
(b)
Exhibits
|
|
Exhibit
Number
|
|
Description
|
|
Debtors’ Sixth Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the United States Bankruptcy Code (incorporated by reference to Exhibit 2.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on December 27, 2007, File No. 001-12079).
|
|
|
|
|
|
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).
|
|
|
|
|
|
Agreement and Plan of Merger, dated as of August 17, 2017, by and among Calpine Corporation, Volt Parent, LP and Volt Merger Sub, Inc. (incorporated by reference to Exhibit 2.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on August 22, 2017).
|
|
|
|
|
|
Fourth Amended and Restated Certificate of Incorporation of Calpine Corporation (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on From 8-K filed with the SEC on April 13, 2018).
|
|
|
|
|
|
Third Amended and Restated By-Laws of Calpine Corporation (incorporated by reference to Exhibit 3.3 to the Company’s Current Report on From 8-K filed with the SEC on April 13, 2018).
|
|
|
|
|
|
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 July 8, 2014, between the Company and Wilmington Trust, National Association, as trustee (the “Trustee”) (incorporated by reference to Exhibit 4.1 to the Company’s Form S-3ASR filed with the SEC on July 8, 2014).
|
|
|
|
|
|
First Supplemental Indenture, dated as of July 22, 2014, between the Company and the Trustee, governing the 2023 Notes (incorporated by reference to Exhibit 4.4 to the Company’s Current Report on Form 8-K filed with the SEC on July 22, 2014).
|
|
|
|
|
|
Second Supplemental Indenture, dated as of July 22, 2014, between the Company and the Trustee, governing the 2025 Notes (incorporated by reference to Exhibit 4.5 to the Company’s Current Report on Form 8-K filed with the SEC on July 22, 2014).
|
|
|
|
|
|
Form of 2023 Note (incorporated by reference to Exhibit 4.6 to the Company’s Current Report on Form 8-K filed with the SEC on July 22, 2014).
|
|
|
|
|
|
Form of 2025 Note (incorporated by reference to Exhibit 4.7 to the Company’s Current Report on Form 8-K filed with the SEC on July 22, 2014).
|
|
|
|
|
|
Third Supplemental Indenture, dated as of February 3, 2015, between the Company and the Trustee, governing the 2024 Notes (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed with the SEC on February 3, 2015).
|
|
|
|
|
|
Form of 2024 Note (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K filed with the SEC on February 3, 2015).
|
|
|
|
|
|
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).
|
|
|
|
|
|
Stockholders Agreement, dated March 8, 2018, by and between Calpine Corporation and CPN Management, LP (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on From 8-K filed with the SEC on March 8, 2018).
|
|
|
|
|
10.1
|
|
Financing Agreements.
|
|
|
Exhibit
Number
|
|
Description
|
|
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).
|
|
|
|
|
|
Amended and Restated Guarantee and Collateral Agreement, dated as of December 10, 2010, made by the Company and certain of the Company's subsidiaries party thereto in favor of Goldman Sachs Credit Partners, L.P., as collateral agent (incorporated by reference to Exhibit 10.1 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).
|
|
|
|
|
|
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 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).
|
|
|
|
|
|
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).
|
|
|
|
|
Exhibit
Number
|
|
Description
|
|
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).
|
|
|
|
|
|
Amendment No. 8 to the Credit Agreement, dated as of May 18, 2018, 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 the Company’s Current Report on From 8-K filed with the SEC on May 21, 2018).
|
|
|
|
|
10.2
|
|
Management Contracts or Compensatory Plans, Contracts or Arrangements.
|
|
|
|
|
Letter Agreement, dated September 1, 2008, between the Company and John B. (Thad) HIll (incorporated by reference to Exhibit 10.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on September 4, 2008).†
|
|
|
|
|
|
Amended and Restated Executive Employment Agreement between the Company and John B. (Thad) Hill, dated August 29, 2018 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on From 8-K filed with the SEC on September 4, 2018).†
|
|
|
|
|
|
Executive Employment Agreement between the Company and Zamir Rauf, dated August 29, 2018 (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on From 8-K filed with the SEC on September 4, 2018).†
|
|
|
|
|
|
Restrictive Covenant Agreement between the Company and Zamir Rauf, dated August 29, 2018 (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on From 8-K filed with the SEC on September 4, 2018).†
|
|
|
|
|
|
Amended and Restated Executive Employment Agreement between the Company and W. Thaddeus Miller, dated August 29, 2018 (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on From 8-K filed with the SEC on September 4, 2018).†
|
|
|
|
|
|
Letter Agreement, dated August 29, 2018, between the Company and Charles M. Gates.*†
|
|
|
|
|
|
Calpine Corporation 2010 Calpine Incentive Plan (incorporated by reference to Exhibit 10.6 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, filed with the SEC on July 30, 2010, File No. 001-12079).†
|
|
|
|
|
|
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).†
|
|
|
|
|
|
Amended and Restated Limited Partnership Agreement of CPN Management, LP a Delaware Limited Partnership,dated March 8, 2018 (incorporated by reference to Exhibit 10.1 to the Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2018, filed with the SEC on May 10, 2018).†
|
|
|
|
|
Exhibit
Number
|
|
Description
|
|
Form of Award Agreement of Class B Interest in CPN Management, L.P .*†
|
|
|
|
|
|
Second Amended and Restated Limited Partnership Agreement of CPN Management, LP a Delaware Limited Partnership, dated August 29, 2018 (incorporated by reference to Exhibit 10.1 to the Calpine’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2018, filed with the SEC on November 8, 2018).†
|
|
|
|
|
|
Subsidiaries of the Company.*
|
|
|
|
|
|
Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*
|
|
|
|
|
|
Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*
|
|
|
|
|
|
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.‡
|
|
|
|
|
101.INS
|
|
XBRL Instance Document.*
|
|
|
|
101.SCH
|
|
XBRL Taxonomy Extension Schema.*
|
|
|
|
101.CAL
|
|
XBRL Taxonomy Extension Calculation Linkbase.*
|
|
|
|
101.DEF
|
|
XBRL Taxonomy Extension Definition Linkbase.*
|
|
|
|
101.LAB
|
|
XBRL Taxonomy Extension Label Linkbase.*
|
|
|
|
101.PRE
|
|
XBRL Taxonomy Extension Presentation Linkbase.*
|
*
|
Filed herewith.
|
‡
|
Furnished herewith.
|
†
|
Management contract or compensatory plan, contract or arrangement.
|
CALPINE CORPORATION
|
||
|
|
|
By:
|
|
/s/ ZAMIR RAUF
|
|
|
Zamir Rauf
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
|
Signature
|
|
Title
|
|
Date
|
|
|
|
||
/s/ JOHN B. (Thad) HILL
|
|
President, Chief Executive Officer and Director (principal executive officer)
|
|
March 28, 2019
|
John B. (Thad) Hill
|
|
|
|
|
|
|
|
||
/s/ ZAMIR RAUF
|
|
Executive Vice President and Chief Financial Officer (principal financial officer)
|
|
March 28, 2019
|
Zamir Rauf
|
|
|
|
|
|
|
|
||
/s/ JEFF KOSHKIN
|
|
Chief Accounting Officer (principal accounting officer)
|
|
March 28, 2019
|
Jeff Koshkin
|
|
|
|
|
|
|
|
|
|
/s/ AVIK DEY
|
|
Director
|
|
March 28, 2019
|
Avik Dey
|
|
|
|
|
|
|
|
|
|
/s/ ANDREW GILBERT
|
|
Director
|
|
March 28, 2019
|
Andrew Gilbert
|
|
|
|
|
|
|
|
|
|
/s/ DOUGLAS W. KIMMELMAN
|
|
Director
|
|
March 28, 2019
|
Douglas W. Kimmelman
|
|
|
|
|
|
|
|
||
/s/ W. THADDEUS MILLER
|
|
Executive Vice Chairman, Chief Legal Officer, Secretary and Director
|
|
March 28, 2019
|
W. Thaddeus Miller
|
|
|
|
|
|
|
|
||
/s/ TYLER G. REEDER
|
|
Director
|
|
March 28, 2019
|
Tyler G. Reeder
|
|
|
|
|
|
|
|
||
/s/ ANDREW D. SINGER
|
|
Director
|
|
March 28, 2019
|
Andrew D. Singer
|
|
|
|
|
|
|
|
||
/s/ DONALD A. WAGNER
|
|
Director
|
|
March 28, 2019
|
Donald A. Wagner
|
|
|
|
|
|
|
|
|
|
|
Page
|
|
2018
|
|
2017
|
|
2016
|
||||||
Operating revenues:
|
|
|
|
|
|
||||||
Commodity revenue
|
$
|
9,865
|
|
|
$
|
8,836
|
|
|
$
|
6,943
|
|
Mark-to-market loss
|
(373
|
)
|
|
(101
|
)
|
|
(245
|
)
|
|||
Other revenue
|
20
|
|
|
17
|
|
|
18
|
|
|||
Operating revenues
|
9,512
|
|
|
8,752
|
|
|
6,716
|
|
|||
Operating expenses:
|
|
|
|
|
|
||||||
Fuel and purchased energy expense:
|
|
|
|
|
|
||||||
Commodity expense
|
6,914
|
|
|
6,268
|
|
|
4,431
|
|
|||
Mark-to-market (gain) loss
|
(165
|
)
|
|
70
|
|
|
(244
|
)
|
|||
Fuel and purchased energy expense
|
6,749
|
|
|
6,338
|
|
|
4,187
|
|
|||
Operating and maintenance expense
|
1,020
|
|
|
1,080
|
|
|
977
|
|
|||
Depreciation and amortization expense
|
739
|
|
|
724
|
|
|
662
|
|
|||
General and other administrative expense
|
158
|
|
|
155
|
|
|
140
|
|
|||
Other operating expenses
|
98
|
|
|
85
|
|
|
79
|
|
|||
Total operating expenses
|
8,764
|
|
|
8,382
|
|
|
6,045
|
|
|||
Impairment losses
|
10
|
|
|
41
|
|
|
13
|
|
|||
(Gain) on sale of assets, net
|
—
|
|
|
(27
|
)
|
|
(157
|
)
|
|||
(Income) from unconsolidated subsidiaries
|
(24
|
)
|
|
(22
|
)
|
|
(24
|
)
|
|||
Income from operations
|
762
|
|
|
378
|
|
|
839
|
|
|||
Interest expense
|
617
|
|
|
621
|
|
|
631
|
|
|||
(Gain) loss on extinguishment of debt
|
(28
|
)
|
|
38
|
|
|
25
|
|
|||
Other (income) expense, net
|
81
|
|
|
32
|
|
|
24
|
|
|||
Income (loss) before income taxes
|
92
|
|
|
(313
|
)
|
|
159
|
|
|||
Income tax expense
|
64
|
|
|
8
|
|
|
48
|
|
|||
Net income (loss)
|
28
|
|
|
(321
|
)
|
|
111
|
|
|||
Net income attributable to the noncontrolling interest
|
(18
|
)
|
|
(18
|
)
|
|
(19
|
)
|
|||
Net income (loss) attributable to Calpine
|
$
|
10
|
|
|
$
|
(339
|
)
|
|
$
|
92
|
|
|
|
2018
|
|
2017
|
|
2016
|
||||||
Net income (loss)
|
|
$
|
28
|
|
|
$
|
(321
|
)
|
|
$
|
111
|
|
Cash flow hedging activities:
|
|
|
|
|
|
|
||||||
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income (loss)
|
|
40
|
|
|
(22
|
)
|
|
(2
|
)
|
|||
Reclassification adjustment for loss on cash flow hedges realized in net income (loss)
|
|
6
|
|
|
48
|
|
|
43
|
|
|||
Unrealized actuarial gain arising during period
|
|
1
|
|
|
—
|
|
|
—
|
|
|||
Foreign currency translation gain (loss)
|
|
(10
|
)
|
|
13
|
|
|
5
|
|
|||
Income tax expense
|
|
(5
|
)
|
|
(6
|
)
|
|
(1
|
)
|
|||
Other comprehensive income
|
|
32
|
|
|
33
|
|
|
45
|
|
|||
Comprehensive income (loss)
|
|
60
|
|
|
(288
|
)
|
|
156
|
|
|||
Comprehensive (income) attributable to the noncontrolling interest
|
|
(21
|
)
|
|
(20
|
)
|
|
(22
|
)
|
|||
Comprehensive income (loss) attributable to Calpine
|
|
$
|
39
|
|
|
$
|
(308
|
)
|
|
$
|
134
|
|
|
2018
|
|
2017
|
||||
ASSETS
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents ($43 and $39 attributable to VIEs)
|
$
|
205
|
|
|
$
|
284
|
|
Accounts receivable, net of allowance of $9 and $9
|
1,022
|
|
|
970
|
|
||
Inventories
|
525
|
|
|
498
|
|
||
Margin deposits and other prepaid expense
|
315
|
|
|
203
|
|
||
Restricted cash, current ($90 and $74 attributable to VIEs)
|
167
|
|
|
134
|
|
||
Derivative assets, current
|
142
|
|
|
174
|
|
||
Other current assets
|
43
|
|
|
43
|
|
||
Total current assets
|
2,419
|
|
|
2,306
|
|
||
Property, plant and equipment, net ($3,919 and $4,048 attributable to VIEs)
|
12,442
|
|
|
12,724
|
|
||
Restricted cash, net of current portion ($33 and $24 attributable to VIEs)
|
34
|
|
|
25
|
|
||
Investments in unconsolidated subsidiaries
|
76
|
|
|
106
|
|
||
Long-term derivative assets
|
160
|
|
|
218
|
|
||
Goodwill
|
242
|
|
|
242
|
|
||
Intangible assets, net
|
412
|
|
|
512
|
|
||
Other assets ($30 and $22 attributable to VIEs)
|
277
|
|
|
320
|
|
||
Total assets
|
$
|
16,062
|
|
|
$
|
16,453
|
|
LIABILITIES & STOCKHOLDERS’ EQUITY
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts payable
|
$
|
958
|
|
|
$
|
777
|
|
Accrued interest payable
|
96
|
|
|
104
|
|
||
Debt, current portion ($201 and $175 attributable to VIEs)
|
637
|
|
|
225
|
|
||
Derivative liabilities, current
|
303
|
|
|
197
|
|
||
Other current liabilities
|
489
|
|
|
571
|
|
||
Total current liabilities
|
2,483
|
|
|
1,874
|
|
||
Debt, net of current portion ($1,978 and $2,238 attributable to VIEs)
|
10,148
|
|
|
11,180
|
|
||
Long-term derivative liabilities
|
140
|
|
|
119
|
|
||
Other long-term liabilities
|
235
|
|
|
213
|
|
||
Total liabilities
|
13,006
|
|
|
13,386
|
|
||
|
|
|
|
||||
Commitments and contingencies (see Note 16)
|
|
|
|
||||
Stockholders’ equity:
|
|
|
|
||||
Common stock, $0.001 par value per share; authorized 5,000 and 1,400,000,000 shares, respectively, 105.2 and 361,677,891 shares issued, respectively, and 105.2 and 360,516,091 shares outstanding, respectively
|
—
|
|
|
—
|
|
||
Treasury stock, at cost, nil and 1,161,800 shares, respectively
|
—
|
|
|
(15
|
)
|
||
Additional paid-in capital
|
9,582
|
|
|
9,661
|
|
||
Accumulated deficit
|
(6,542
|
)
|
|
(6,552
|
)
|
||
Accumulated other comprehensive loss
|
(77
|
)
|
|
(106
|
)
|
||
Total Calpine stockholders’ equity
|
2,963
|
|
|
2,988
|
|
||
Noncontrolling interest
|
93
|
|
|
79
|
|
||
Total stockholders’ equity
|
3,056
|
|
|
3,067
|
|
||
Total liabilities and stockholders’ equity
|
$
|
16,062
|
|
|
$
|
16,453
|
|
|
Common
Stock
|
|
Treasury
Stock
|
|
Additional
Paid-In
Capital
|
|
Accumulated
Deficit
|
|
Accumulated
Other
Comprehensive
Loss
|
|
Noncontrolling
Interest
|
|
Total
Stockholders’
Equity
|
||||||||||||||
Balance, December 31, 2015
|
$
|
—
|
|
|
$
|
(1
|
)
|
|
$
|
9,594
|
|
|
$
|
(6,305
|
)
|
|
$
|
(179
|
)
|
|
$
|
58
|
|
|
$
|
3,167
|
|
Treasury stock transactions
|
—
|
|
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
|||||||
Stock-based compensation expense
|
—
|
|
|
—
|
|
|
30
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
30
|
|
|||||||
Option exercises
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|||||||
Distribution to the noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(9
|
)
|
|
(9
|
)
|
|||||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
92
|
|
|
—
|
|
|
19
|
|
|
111
|
|
|||||||
Other comprehensive income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
42
|
|
|
3
|
|
|
45
|
|
|||||||
Balance, December 31, 2016
|
$
|
—
|
|
|
$
|
(7
|
)
|
|
$
|
9,625
|
|
|
$
|
(6,213
|
)
|
|
$
|
(137
|
)
|
|
$
|
71
|
|
|
$
|
3,339
|
|
Treasury stock transactions
|
—
|
|
|
(8
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(8
|
)
|
|||||||
Stock-based compensation expense
|
—
|
|
|
—
|
|
|
36
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
36
|
|
|||||||
Distribution to the noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(12
|
)
|
|
(12
|
)
|
|||||||
Net income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
(339
|
)
|
|
—
|
|
|
18
|
|
|
(321
|
)
|
|||||||
Other comprehensive income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
31
|
|
|
2
|
|
|
33
|
|
|||||||
Balance, December 31, 2017
|
$
|
—
|
|
|
$
|
(15
|
)
|
|
$
|
9,661
|
|
|
$
|
(6,552
|
)
|
|
$
|
(106
|
)
|
|
$
|
79
|
|
|
$
|
3,067
|
|
Treasury stock transactions
|
—
|
|
|
(7
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(7
|
)
|
|||||||
Stock-based compensation expense
|
—
|
|
|
—
|
|
|
41
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
41
|
|
|||||||
Effects of the Merger
|
—
|
|
|
22
|
|
|
(100
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(78
|
)
|
|||||||
Dividends
|
—
|
|
|
—
|
|
|
(20
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(20
|
)
|
|||||||
Contribution from the noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
2
|
|
|||||||
Distribution to the noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(9
|
)
|
|
(9
|
)
|
|||||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|
—
|
|
|
18
|
|
|
28
|
|
|||||||
Other comprehensive income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
29
|
|
|
3
|
|
|
32
|
|
|||||||
Balance, December 31, 2018
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
9,582
|
|
|
$
|
(6,542
|
)
|
|
$
|
(77
|
)
|
|
$
|
93
|
|
|
$
|
3,056
|
|
|
2018
|
|
2017
|
|
2016
|
||||||
Cash flows from operating activities:
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
28
|
|
|
$
|
(321
|
)
|
|
$
|
111
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
||||||
Depreciation and amortization
(1)
|
848
|
|
|
921
|
|
|
910
|
|
|||
(Gain) loss on extinguishment of debt
|
(32
|
)
|
|
38
|
|
|
25
|
|
|||
Deferred income taxes
|
47
|
|
|
14
|
|
|
43
|
|
|||
Impairment losses
|
10
|
|
|
41
|
|
|
13
|
|
|||
(Gain) on sale of assets, net
|
—
|
|
|
(27
|
)
|
|
(157
|
)
|
|||
Mark-to-market activity, net
|
205
|
|
|
169
|
|
|
(1
|
)
|
|||
(Income) from unconsolidated subsidiaries
|
(24
|
)
|
|
(22
|
)
|
|
(24
|
)
|
|||
Return on investments from unconsolidated subsidiaries
|
35
|
|
|
28
|
|
|
21
|
|
|||
Stock-based compensation expense
|
57
|
|
|
42
|
|
|
31
|
|
|||
Other
|
29
|
|
|
(5
|
)
|
|
8
|
|
|||
Change in operating assets and liabilities, net of effects of acquisitions:
|
|
|
|
|
|
||||||
Accounts receivable
|
(101
|
)
|
|
(108
|
)
|
|
(128
|
)
|
|||
Accounts payable
|
164
|
|
|
70
|
|
|
34
|
|
|||
Margin deposits and other prepaid expense
|
(134
|
)
|
|
115
|
|
|
416
|
|
|||
Other assets and liabilities, net
|
(82
|
)
|
|
(15
|
)
|
|
19
|
|
|||
Derivative instruments, net
|
51
|
|
|
9
|
|
|
(286
|
)
|
|||
Net cash provided by operating activities
|
1,101
|
|
|
949
|
|
|
1,035
|
|
|||
Cash flows from investing activities:
|
|
|
|
|
|
||||||
Purchases of property, plant and equipment
|
(415
|
)
|
|
(305
|
)
|
|
(489
|
)
|
|||
Proceeds from sale of power plants and other
(2)
|
11
|
|
|
162
|
|
|
179
|
|
|||
Purchase of Granite Ridge Energy Center
|
—
|
|
|
—
|
|
|
(526
|
)
|
|||
Purchases of North American Power and Calpine Solutions, net of cash acquired
(3)
|
—
|
|
|
(111
|
)
|
|
(1,150
|
)
|
|||
Return of investment from unconsolidated subsidiaries
|
18
|
|
|
—
|
|
|
—
|
|
|||
Other
|
(6
|
)
|
|
43
|
|
|
27
|
|
|||
Net cash used in investing activities
|
(392
|
)
|
|
(211
|
)
|
|
(1,959
|
)
|
|||
Cash flows from financing activities:
|
|
|
|
|
|
||||||
Borrowings under CCFC Term Loan and First Lien Term Loans
|
—
|
|
|
1,395
|
|
|
1,101
|
|
|||
Repayments of CCFC Term Loans and First Lien Term Loans
|
(41
|
)
|
|
(2,150
|
)
|
|
(1,231
|
)
|
|||
Borrowings under First Lien Notes
|
—
|
|
|
560
|
|
|
625
|
|
|||
Repurchases of Senior Unsecured and First Lien Notes
|
(355
|
)
|
|
(453
|
)
|
|
(120
|
)
|
|||
Borrowings under Corporate Revolving Facility
|
355
|
|
|
25
|
|
|
—
|
|
|||
Repayments of Corporate Revolving Facility
|
(325
|
)
|
|
(25
|
)
|
|
—
|
|
|||
Borrowings from project financing, notes payable and other
|
220
|
|
|
—
|
|
|
458
|
|
|||
Repayments of project financing, notes payable and other
|
(470
|
)
|
|
(174
|
)
|
|
(364
|
)
|
|||
Distribution to noncontrolling interest holder
|
(9
|
)
|
|
(12
|
)
|
|
(9
|
)
|
|||
Financing costs
|
(18
|
)
|
|
(60
|
)
|
|
(63
|
)
|
|||
Stock repurchases
|
(79
|
)
|
|
—
|
|
|
—
|
|
|||
Proceeds from exercises of stock options
|
—
|
|
|
—
|
|
|
1
|
|
|||
Shares repurchased for tax withholding on stock-based awards
|
(7
|
)
|
|
(7
|
)
|
|
(6
|
)
|
|||
Dividends paid
(4)
|
(20
|
)
|
|
—
|
|
|
—
|
|
|||
Other
|
3
|
|
|
—
|
|
|
4
|
|
|||
Net cash (used in) provided by financing activities
|
(746
|
)
|
|
(901
|
)
|
|
396
|
|
|||
Net decrease in cash, cash equivalents and restricted cash
|
(37
|
)
|
|
(163
|
)
|
|
(528
|
)
|
|||
Cash, cash equivalents and restricted cash, beginning of period
|
443
|
|
|
606
|
|
|
1,134
|
|
|||
Cash, cash equivalents and restricted cash, end of period
(5)
|
$
|
406
|
|
|
$
|
443
|
|
|
$
|
606
|
|
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS — (Continued)
(in millions)
|
|||||||||||
|
|
|
|
|
|
||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Cash paid during the period for:
|
|
|
|
|
|
||||||
Interest, net of amounts capitalized
|
$
|
587
|
|
|
$
|
575
|
|
|
$
|
584
|
|
Income taxes
|
$
|
23
|
|
|
$
|
12
|
|
|
$
|
12
|
|
|
|
|
|
|
|
||||||
Supplemental disclosure of non-cash investing and financing activities:
|
|
|
|
|
|
||||||
Purchase of King City Cogeneration Plant Lease
(6)
|
$
|
—
|
|
|
$
|
15
|
|
|
$
|
—
|
|
Change in capital expenditures included in accounts payable
|
$
|
19
|
|
|
$
|
20
|
|
|
$
|
(37
|
)
|
Reduction of debt due to sale of Mankato Power Plant
(2)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
243
|
|
(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)
|
Subsequent to the consummation of the Merger on March 8, 2018, we paid certain Merger-related costs incurred by CPN Management, our direct parent.
|
(5)
|
Our cash and cash equivalents, restricted cash, current and restricted cash, net of current portion are stated as separate line items on our Consolidated Balance Sheets.
|
(6)
|
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.
|
1.
|
Organization and Operations
|
2.
|
Merger
|
3.
|
Summary of Significant Accounting Policies
|
As of December 31, 2018
|
|
Ownership Interest
|
|
Property, Plant & Equipment
|
|
Accumulated Depreciation
|
|
Construction in Progress
|
|||||||
(in millions, except percentages)
|
|||||||||||||||
Freestone Energy Center
|
|
75.0
|
%
|
|
$
|
379
|
|
|
$
|
(167
|
)
|
|
$
|
1
|
|
Hidalgo Energy Center
|
|
78.5
|
%
|
|
$
|
251
|
|
|
$
|
(114
|
)
|
|
$
|
4
|
|
•
|
financial institutions and trading companies;
|
•
|
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.
|
|
2018
|
|
2017
|
||||||||||||||||||||
|
Current
|
|
Non-Current
|
|
Total
|
|
Current
|
|
Non-Current
|
|
Total
|
||||||||||||
Debt service
|
$
|
13
|
|
|
$
|
8
|
|
|
$
|
21
|
|
|
$
|
11
|
|
|
$
|
8
|
|
|
$
|
19
|
|
Construction/major maintenance
|
23
|
|
|
24
|
|
|
47
|
|
|
28
|
|
|
16
|
|
|
44
|
|
||||||
Security/project/insurance
|
120
|
|
|
—
|
|
|
120
|
|
|
92
|
|
|
—
|
|
|
92
|
|
||||||
Other
|
11
|
|
|
2
|
|
|
13
|
|
|
3
|
|
|
1
|
|
|
4
|
|
||||||
Total
|
$
|
167
|
|
|
$
|
34
|
|
|
$
|
201
|
|
|
$
|
134
|
|
|
$
|
25
|
|
|
$
|
159
|
|
|
2018
|
|
2017
|
|
Lives
|
||||
Acquired contracts
|
$
|
458
|
|
|
$
|
458
|
|
|
0 – 9 Years
|
Customer relationships
|
445
|
|
|
445
|
|
|
7 – 14 Years
|
||
Trademark and trade name
|
40
|
|
|
40
|
|
|
15 Years
|
||
Other
|
88
|
|
|
88
|
|
|
17 – 23 Years
|
||
|
1,031
|
|
|
1,031
|
|
|
|
||
Less: Accumulated amortization
|
619
|
|
|
519
|
|
|
|
||
Intangible assets, net
|
$
|
412
|
|
|
$
|
512
|
|
|
|
2019
|
$
|
71
|
|
2020
|
$
|
44
|
|
2021
|
$
|
40
|
|
2022
|
$
|
35
|
|
2023
|
$
|
28
|
|
•
|
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;
|
•
|
mark-to-market revenues from derivative instruments as a result of our marketing, hedging, optimization and trading activities; and
|
•
|
sales of natural gas and other service revenues.
|
2019
|
$
|
342
|
|
2020
|
261
|
|
|
2021
|
257
|
|
|
2022
|
224
|
|
|
2023
|
141
|
|
|
Thereafter
|
239
|
|
|
Total
|
$
|
1,464
|
|
4.
|
Revenue from Contracts with Customers
|
|
Wholesale
|
|
|
|
|
|
|
||||||||||||||||
|
West
|
|
Texas
|
|
East
|
|
Retail
|
|
Elimination
|
|
Total
|
||||||||||||
Third Party:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Energy & other products
|
$
|
1,070
|
|
|
$
|
1,500
|
|
|
$
|
621
|
|
|
$
|
1,857
|
|
|
$
|
—
|
|
|
$
|
5,048
|
|
Capacity
|
152
|
|
|
94
|
|
|
657
|
|
|
—
|
|
|
—
|
|
|
903
|
|
||||||
Revenues relating to physical or executory contracts – third party
|
$
|
1,222
|
|
|
$
|
1,594
|
|
|
$
|
1,278
|
|
|
$
|
1,857
|
|
|
$
|
—
|
|
|
$
|
5,951
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Affiliate
(1)
:
|
$
|
30
|
|
|
$
|
34
|
|
|
$
|
89
|
|
|
$
|
4
|
|
|
$
|
(157
|
)
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Revenues relating to leases and derivative instruments
(2)
|
|
|
|
|
|
|
|
|
|
|
$
|
3,561
|
|
||||||||||
Total operating revenues
|
|
|
|
|
|
|
|
|
|
|
$
|
9,512
|
|
(1)
|
Affiliate energy, other and capacity revenues reflect revenues on transactions between wholesale and retail affiliates excluding affiliate activity related to leases and derivative instruments. All such activity supports retail supply needs from the wholesale business and/or allows for collateral margin netting efficiencies at Calpine.
|
(2)
|
Revenues relating to contracts accounted for as leases and derivatives include energy and capacity revenues relating to PPAs that we are required to account for as operating leases and physical and financial commodity derivative contracts, primarily relating to power, natural gas and environmental products. Revenue related to derivative instruments includes revenue recorded in Commodity revenue and mark-to-market gain (loss) within our operating revenues on our Consolidated Statements of Operations.
|
5.
|
Acquisitions and Divestitures
|
(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.
|
|
2016
|
||
|
(Unaudited)
|
||
Operating revenues
|
$
|
8,324
|
|
Net income attributable to Calpine
|
$
|
105
|
|
6.
|
Property, Plant and Equipment, Net
|
|
2018
|
|
2017
|
|
Depreciable Lives
|
||||
Buildings, machinery and equipment
|
$
|
16,400
|
|
|
$
|
16,506
|
|
|
1.5 – 46 Years
|
Geothermal properties
|
1,501
|
|
|
1,494
|
|
|
13 – 58 Years
|
||
Other
|
286
|
|
|
236
|
|
|
3 – 46 Years
|
||
|
18,187
|
|
|
18,236
|
|
|
|
||
Less: Accumulated depreciation
|
6,832
|
|
|
6,383
|
|
|
|
||
|
11,355
|
|
|
11,853
|
|
|
|
||
Land
|
121
|
|
|
117
|
|
|
|
||
Construction in progress
|
966
|
|
|
754
|
|
|
|
||
Property, plant and equipment, net
|
$
|
12,442
|
|
|
$
|
12,724
|
|
|
|
7.
|
Variable Interest Entities and Unconsolidated Investments
|
•
|
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 as contractual changes where 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.
|
|
Ownership Interest as of December 31, 2018
|
|
2018
|
|
2017
|
||||
Greenfield LP
|
50%
|
|
$
|
55
|
|
|
$
|
92
|
|
Whitby
|
50%
|
|
15
|
|
|
6
|
|
||
Calpine Receivables
|
100%
|
|
6
|
|
|
8
|
|
||
Total investments in unconsolidated subsidiaries
|
|
|
$
|
76
|
|
|
$
|
106
|
|
|
(Income) loss from
Unconsolidated Subsidiaries
|
|
Distributions
|
||||||||||||||||||||
|
2018
|
|
2017
|
|
2016
|
|
2018
|
|
2017
|
|
2016
|
||||||||||||
Greenfield LP
|
$
|
(11
|
)
|
|
$
|
(14
|
)
|
|
$
|
(10
|
)
|
|
$
|
48
|
|
|
$
|
8
|
|
|
$
|
8
|
|
Whitby
|
(15
|
)
|
|
(10
|
)
|
|
(14
|
)
|
|
5
|
|
|
20
|
|
|
13
|
|
||||||
Calpine Receivables
|
2
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total
|
$
|
(24
|
)
|
|
$
|
(22
|
)
|
|
$
|
(24
|
)
|
|
$
|
53
|
|
|
$
|
28
|
|
|
$
|
21
|
|
8.
|
Debt
|
|
2018
|
|
2017
|
||||
Senior Unsecured Notes
|
$
|
3,036
|
|
|
$
|
3,417
|
|
First Lien Term Loans
|
2,976
|
|
|
2,995
|
|
||
First Lien Notes
|
2,400
|
|
|
2,396
|
|
||
Project financing, notes payable and other
|
1,264
|
|
|
1,498
|
|
||
CCFC Term Loan
|
974
|
|
|
984
|
|
||
Capital lease obligations
|
105
|
|
|
115
|
|
||
Corporate Revolving Facility
|
30
|
|
|
—
|
|
||
Subtotal
|
10,785
|
|
|
11,405
|
|
||
Less: Current maturities
|
637
|
|
|
225
|
|
||
Total long-term debt
|
$
|
10,148
|
|
|
$
|
11,180
|
|
2019
|
$
|
642
|
|
2020
|
246
|
|
|
2021
|
259
|
|
|
2022
|
1,019
|
|
|
2023
|
2,535
|
|
|
Thereafter
|
6,217
|
|
|
Subtotal
|
10,918
|
|
|
Less: Debt issuance costs
|
112
|
|
|
Less: Discount
|
21
|
|
|
Total debt
|
$
|
10,785
|
|
|
Outstanding at December 31,
|
|
Weighted Average
Effective Interest Rates (1) |
||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||
2023 Senior Unsecured Notes
|
$
|
1,227
|
|
|
$
|
1,239
|
|
|
5.6
|
%
|
|
5.6
|
%
|
2024 Senior Unsecured Notes
|
599
|
|
|
644
|
|
|
5.7
|
|
|
5.7
|
|
||
2025 Senior Unsecured Notes
|
1,210
|
|
|
1,534
|
|
|
6.0
|
|
|
6.0
|
|
||
Total Senior Unsecured Notes
|
$
|
3,036
|
|
|
$
|
3,417
|
|
|
|
|
|
(1)
|
Our weighted average interest rate calculation includes the amortization of debt issuance costs.
|
|
|
Principal Repurchased
|
|
Cash Paid
|
|
Gain on Extinguishment of Debt
|
||||||
|
|
|
|
(in million)
|
|
|
||||||
2023 Senior Unsecured Notes
|
|
$
|
14
|
|
|
$
|
13
|
|
|
$
|
1
|
|
2024 Senior Unsecured Notes
|
|
46
|
|
|
42
|
|
|
4
|
|
|||
2025 Senior Unsecured Notes
|
|
330
|
|
|
300
|
|
|
30
|
|
|||
Total
|
|
$
|
390
|
|
|
$
|
355
|
|
|
$
|
35
|
|
•
|
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.
|
|
Outstanding at December 31,
|
|
Weighted Average
Effective Interest Rates
(1)
|
||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||
2019 First Lien Term Loan
|
$
|
389
|
|
|
$
|
389
|
|
|
4.9
|
%
|
|
4.1
|
%
|
2023 First Lien Term Loans
|
1,059
|
|
|
1,064
|
|
|
5.4
|
|
|
4.6
|
|
||
2024 First Lien Term Loan
(2)
|
1,528
|
|
|
1,542
|
|
|
5.0
|
|
|
4.2
|
|
||
Total First Lien Term Loans
|
$
|
2,976
|
|
|
$
|
2,995
|
|
|
|
|
|
(1)
|
Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount.
|
(2)
|
Our 2024 First Lien Term Loan carries substantially similar terms as our 2023 First Lien Term Loans as discussed below.
|
|
Outstanding at December 31,
|
|
Weighted Average
Effective Interest Rates (1) |
||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||
2022 First Lien Notes
|
$
|
743
|
|
|
$
|
741
|
|
|
6.4
|
%
|
|
6.4
|
%
|
2024 First Lien Notes
|
486
|
|
|
485
|
|
|
6.1
|
|
|
6.1
|
|
||
2026 First Lien Notes
|
1,171
|
|
|
1,170
|
|
|
5.5
|
|
|
5.5
|
|
||
Total First Lien Notes
|
$
|
2,400
|
|
|
$
|
2,396
|
|
|
|
|
|
(1)
|
Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount.
|
•
|
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
|
•
|
consolidate, merge or transfer all or substantially all of our assets and the assets of our restricted subsidiaries on a combined basis.
|
|
Outstanding at
December 31,
|
|
Weighted Average
Effective Interest Rates
(1)
|
||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||
Russell City due 2023
|
$
|
341
|
|
|
$
|
401
|
|
|
6.5
|
%
|
|
6.4
|
%
|
Steamboat due 2025
|
384
|
|
|
414
|
|
|
4.5
|
|
|
4.7
|
|
||
OMEC due 2024
(2)
|
218
|
|
|
294
|
|
|
7.1
|
|
|
7.2
|
|
||
Los Esteros due 2023
|
163
|
|
|
191
|
|
|
4.7
|
|
|
5.3
|
|
||
Pasadena
(3)
|
76
|
|
|
89
|
|
|
8.9
|
|
|
8.9
|
|
||
Bethpage Energy Center 3 due 2020-2025
(4)
|
53
|
|
|
60
|
|
|
7.1
|
|
|
7.1
|
|
||
Other
|
29
|
|
|
49
|
|
|
—
|
|
|
—
|
|
||
Total
|
$
|
1,264
|
|
|
$
|
1,498
|
|
|
|
|
|
(1)
|
Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount.
|
(2)
|
On December 19, 2018, we refinanced the project debt associated with OMEC which lowered the aggregate debt balance to
$220 million
and extended the maturity to August 2024. In the event that the OMEC put option is exercised, the debt will become payable on November 3, 2019. See Note 7 for further information related to the OMEC put option.
|
(3)
|
Represents a failed sale-leaseback transaction that is accounted for as financing transaction under U.S. GAAP.
|
(4)
|
Represents a weighted average of first and second lien loans for the weighted average effective interest rates.
|
|
Outstanding at December 31,
|
|
Weighted Average
Effective Interest Rates
(1)
|
||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||
CCFC Term Loan
|
$
|
974
|
|
|
$
|
984
|
|
|
4.9
|
%
|
|
4.6
|
%
|
(1)
|
Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount.
|
•
|
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.
|
|
Sale-Leaseback Transaction
(1)
|
|
Capital Lease
|
|
Total
|
||||||
2019
|
$
|
21
|
|
|
$
|
19
|
|
|
$
|
40
|
|
2020
|
21
|
|
|
19
|
|
|
40
|
|
|||
2021
|
21
|
|
|
17
|
|
|
38
|
|
|||
2022
|
16
|
|
|
17
|
|
|
33
|
|
|||
2023
|
6
|
|
|
21
|
|
|
27
|
|
|||
Thereafter
|
20
|
|
|
72
|
|
|
92
|
|
|||
Total minimum lease payments
|
105
|
|
|
165
|
|
|
270
|
|
|||
Less: Amount representing interest
|
29
|
|
|
60
|
|
|
89
|
|
|||
Present value of net minimum lease payments
|
$
|
76
|
|
|
$
|
105
|
|
|
$
|
181
|
|
(1)
|
Amounts are accounted for as a financing transaction under U.S. GAAP and are included in our project financing, notes payable and other amounts above.
|
|
2018
|
|
2017
|
||||
Corporate Revolving Facility
|
$
|
693
|
|
|
$
|
629
|
|
CDHI
|
251
|
|
|
244
|
|
||
Various project financing facilities
|
228
|
|
|
196
|
|
||
Other corporate facilities
|
193
|
|
|
—
|
|
||
Total
|
$
|
1,365
|
|
|
$
|
1,069
|
|
|
2018
|
|
2017
|
||||||||||||
|
Fair Value
|
|
Carrying
Value |
|
Fair Value
|
|
Carrying
Value
|
||||||||
Senior Unsecured Notes
|
$
|
2,803
|
|
|
$
|
3,036
|
|
|
$
|
3,294
|
|
|
$
|
3,417
|
|
First Lien Term Loans
|
2,877
|
|
|
2,976
|
|
|
3,043
|
|
|
2,995
|
|
||||
First Lien Notes
|
2,299
|
|
|
2,400
|
|
|
2,437
|
|
|
2,396
|
|
||||
Project financing, notes payable and other
(1)
|
1,209
|
|
|
1,188
|
|
|
1,439
|
|
|
1,409
|
|
||||
CCFC Term Loan
|
938
|
|
|
974
|
|
|
1,000
|
|
|
984
|
|
||||
Corporate Revolving Facility
|
30
|
|
|
30
|
|
|
—
|
|
|
—
|
|
||||
Total
|
$
|
10,156
|
|
|
$
|
10,604
|
|
|
$
|
11,213
|
|
|
$
|
11,201
|
|
(1)
|
Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP.
|
9.
|
Assets and Liabilities with Recurring Fair Value Measurements
|
|
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2018
|
||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
|
(in millions)
|
||||||||||||||
Assets:
|
|
|
|
|
|
|
|
||||||||
Cash equivalents
(1)
|
$
|
168
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
168
|
|
Commodity instruments:
|
|
|
|
|
|
|
|
||||||||
Commodity exchange traded derivatives contracts
|
933
|
|
|
—
|
|
|
—
|
|
|
933
|
|
||||
Commodity forward contracts
(2)
|
—
|
|
|
338
|
|
|
212
|
|
|
550
|
|
||||
Interest rate hedging instruments
|
—
|
|
|
40
|
|
|
—
|
|
|
40
|
|
||||
Effect of netting and allocation of collateral
(3)(4)
|
(933
|
)
|
|
(262
|
)
|
|
(26
|
)
|
|
(1,221
|
)
|
||||
Total assets
|
$
|
168
|
|
|
$
|
116
|
|
|
$
|
186
|
|
|
$
|
470
|
|
Liabilities:
|
|
|
|
|
|
|
|
||||||||
Commodity instruments:
|
|
|
|
|
|
|
|
||||||||
Commodity exchange traded derivatives contracts
|
932
|
|
|
—
|
|
|
—
|
|
|
932
|
|
||||
Commodity forward contracts
(2)
|
—
|
|
|
549
|
|
|
220
|
|
|
769
|
|
||||
Interest rate hedging instruments
|
—
|
|
|
10
|
|
|
—
|
|
|
10
|
|
||||
Effect of netting and allocation of collateral
(3)(4)
|
(932
|
)
|
|
(310
|
)
|
|
(26
|
)
|
|
(1,268
|
)
|
||||
Total liabilities
|
$
|
—
|
|
|
$
|
249
|
|
|
$
|
194
|
|
|
$
|
443
|
|
|
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2017
|
||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
|
(in millions)
|
||||||||||||||
Assets:
|
|
|
|
|
|
|
|
||||||||
Cash equivalents
(1)
|
$
|
131
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
131
|
|
Commodity instruments:
|
|
|
|
|
|
|
|
||||||||
Commodity exchange traded derivatives contracts
|
746
|
|
|
—
|
|
|
—
|
|
|
746
|
|
||||
Commodity forward contracts
(2)
|
—
|
|
|
327
|
|
|
265
|
|
|
592
|
|
||||
Interest rate hedging instruments
|
—
|
|
|
29
|
|
|
—
|
|
|
29
|
|
||||
Effect of netting and allocation of collateral
(3)(4)
|
(746
|
)
|
|
(206
|
)
|
|
(23
|
)
|
|
(975
|
)
|
||||
Total assets
|
$
|
131
|
|
|
$
|
150
|
|
|
$
|
242
|
|
|
$
|
523
|
|
Liabilities:
|
|
|
|
|
|
|
|
||||||||
Commodity instruments:
|
|
|
|
|
|
|
|
||||||||
Commodity exchange traded derivatives contracts
|
790
|
|
|
—
|
|
|
—
|
|
|
790
|
|
||||
Commodity forward contracts
(2)
|
—
|
|
|
461
|
|
|
68
|
|
|
529
|
|
||||
Interest rate hedging instruments
|
—
|
|
|
34
|
|
|
—
|
|
|
34
|
|
||||
Effect of netting and allocation of collateral
(3)(4)
|
(790
|
)
|
|
(224
|
)
|
|
(23
|
)
|
|
(1,037
|
)
|
||||
Total liabilities
|
$
|
—
|
|
|
$
|
271
|
|
|
$
|
45
|
|
|
$
|
316
|
|
(1)
|
As of
December 31, 2018
and
2017
, we had cash equivalents of
$23 million
and
$21 million
included in cash and cash equivalents and
$145 million
and
$110 million
included in restricted cash, respectively.
|
(2)
|
Includes OTC swaps and options.
|
(3)
|
We 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 10 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
$(1) million
,
$48 million
and
nil
, respectively, at
December 31, 2018
. 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
.
|
|
|
Quantitative Information about Level 3 Fair Value Measurements
|
||||||||
|
|
December 31, 2018
|
||||||||
|
|
Fair Value, Net Asset
|
|
|
|
Significant Unobservable
|
|
|
||
|
|
(Liability)
|
|
Valuation Technique
|
|
Input
|
|
Range
|
||
|
|
(in millions)
|
|
|
|
|
|
|
||
Power Contracts
(1)
|
|
$
|
36
|
|
|
Discounted cash flow
|
|
Market price (per MWh)
|
|
$2.12 — $227.98/MWh
|
Power Congestion Products
|
|
$
|
26
|
|
|
Discounted cash flow
|
|
Market price (per MWh)
|
|
$(11.71) — $11.88/MWh
|
Natural Gas Contracts
|
|
$
|
(73
|
)
|
|
Discounted cash flow
|
|
Market price (per MMBtu)
|
|
$0.75 — $8.87/MMBtu
|
|
|
Quantitative Information about Level 3 Fair Value Measurements
|
||||||||
|
|
December 31, 2017
|
||||||||
|
|
Fair Value, Net Asset
|
|
|
|
Significant Unobservable
|
|
|
||
|
|
(Liability)
|
|
Valuation Technique
|
|
Input
|
|
Range
|
||
|
|
(in millions)
|
|
|
|
|
|
|
||
Power Contracts
(1)
|
|
$
|
149
|
|
|
Discounted cash flow
|
|
Market price (per MWh)
|
|
$4.13 — $119.20/MWh
|
Power Congestion Products
|
|
$
|
11
|
|
|
Discounted cash flow
|
|
Market price (per MWh)
|
|
$(10.54) — $9.13/MWh
|
Natural Gas Contracts
|
|
$
|
34
|
|
|
Discounted cash flow
|
|
Market price (per MMBtu)
|
|
$1.62 — $13.67/MMBtu
|
(1)
|
Power contracts include power and heat rate instruments classified as level 3 in the fair value hierarchy.
|
|
2018
|
|
2017
|
|
2016
|
||||||
Balance, beginning of period
|
$
|
197
|
|
|
$
|
416
|
|
|
$
|
(46
|
)
|
Realized and mark-to-market gains (losses):
|
|
|
|
|
|
||||||
Included in net income (loss):
|
|
|
|
|
|
||||||
Included in operating revenues
(1)
|
(88
|
)
|
|
32
|
|
|
(46
|
)
|
|||
Included in fuel and purchased energy expense
(2)
|
(45
|
)
|
|
50
|
|
|
7
|
|
|||
Change in collateral
|
—
|
|
|
(17
|
)
|
|
17
|
|
|||
Purchases, issuances and settlements:
|
|
|
|
|
|
||||||
Purchases
(3)
|
18
|
|
|
4
|
|
|
426
|
|
|||
Issuances
|
(2
|
)
|
|
(1
|
)
|
|
—
|
|
|||
Settlements
|
(86
|
)
|
|
(179
|
)
|
|
(21
|
)
|
|||
Transfers in and/or out of level 3
(4)
:
|
|
|
|
|
|
||||||
Transfers into level 3
(5)
|
—
|
|
|
(2
|
)
|
|
4
|
|
|||
Transfers out of level 3
(6)
|
(2
|
)
|
|
(106
|
)
|
|
75
|
|
|||
Balance, end of period
|
$
|
(8
|
)
|
|
$
|
197
|
|
|
$
|
416
|
|
Change in unrealized gains (losses) relating to instruments still held at end of period
|
$
|
(133
|
)
|
|
$
|
82
|
|
|
$
|
(39
|
)
|
(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, 2018
,
2017
and
2016
.
|
(5)
|
We had
nil
and
$(2) million
in losses and
$4 million
in gains transferred out of level 2 into level 3 for the years ended
December 31, 2018
,
2017
and
2016
, respectively.
|
(6)
|
We had
$2 million
and
$104 million
in gains and
$(75) million
in losses transferred out of level 3 into level 2 during the years ended
December 31, 2018
,
2017
and
2016
, respectively, due to changes in market liquidity in various power markets and
$2 million
in gains transferred out of level 3 during the years ended December 31, 2017, 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.
|
10.
|
Derivative Instruments
|
Derivative Instruments
|
|
Notional Amounts
|
||||||
|
2018
|
|
2017
|
|||||
Power (MWh)
|
|
(161
|
)
|
|
(119
|
)
|
||
Natural gas (MMBtu)
|
|
1,045
|
|
|
405
|
|
||
Environmental credits (Tonnes)
|
|
13
|
|
|
12
|
|
||
Interest rate hedging instruments
|
|
$
|
4,500
|
|
|
$
|
4,600
|
|
|
|
December 31, 2018
|
||||||||||
|
|
Gross Amounts of Assets and (Liabilities)
|
|
Gross Amounts Offset on the Consolidated Balance Sheets
|
|
Net Amount Presented on the Consolidated Balance Sheets
(1)
|
||||||
Derivative assets:
|
|
|
|
|
|
|
||||||
Commodity exchange traded derivatives contracts
|
|
$
|
820
|
|
|
$
|
(820
|
)
|
|
$
|
—
|
|
Commodity forward contracts
|
|
341
|
|
|
(229
|
)
|
|
112
|
|
|||
Interest rate hedging instruments
|
|
30
|
|
|
—
|
|
|
30
|
|
|||
Total current derivative assets
(2)
|
|
$
|
1,191
|
|
|
$
|
(1,049
|
)
|
|
$
|
142
|
|
Commodity exchange traded derivatives contracts
|
|
113
|
|
|
(113
|
)
|
|
—
|
|
|||
Commodity forward contracts
|
|
209
|
|
|
(59
|
)
|
|
150
|
|
|||
Interest rate hedging instruments
|
|
10
|
|
|
—
|
|
|
10
|
|
|||
Total long-term derivative assets
(2)
|
|
$
|
332
|
|
|
$
|
(172
|
)
|
|
$
|
160
|
|
Total derivative assets
|
|
$
|
1,523
|
|
|
$
|
(1,221
|
)
|
|
$
|
302
|
|
|
|
|
|
|
|
|
||||||
Derivative (liabilities):
|
|
|
|
|
|
|
||||||
Commodity exchange traded derivatives contracts
|
|
$
|
(764
|
)
|
|
$
|
764
|
|
|
$
|
—
|
|
Commodity forward contracts
|
|
(576
|
)
|
|
277
|
|
|
(299
|
)
|
|||
Interest rate hedging instruments
|
|
(4
|
)
|
|
—
|
|
|
(4
|
)
|
|||
Total current derivative (liabilities)
(2)
|
|
$
|
(1,344
|
)
|
|
$
|
1,041
|
|
|
$
|
(303
|
)
|
Commodity exchange traded derivatives contracts
|
|
(168
|
)
|
|
168
|
|
|
—
|
|
|||
Commodity forward contracts
|
|
(193
|
)
|
|
59
|
|
|
(134
|
)
|
|||
Interest rate hedging instruments
|
|
(6
|
)
|
|
—
|
|
|
(6
|
)
|
|||
Total long-term derivative (liabilities)
(2)
|
|
$
|
(367
|
)
|
|
$
|
227
|
|
|
$
|
(140
|
)
|
Total derivative liabilities
|
|
$
|
(1,711
|
)
|
|
$
|
1,268
|
|
|
$
|
(443
|
)
|
Net derivative assets (liabilities)
|
|
$
|
(188
|
)
|
|
$
|
47
|
|
|
$
|
(141
|
)
|
|
|
December 31, 2017
|
||||||||||
|
|
Gross Amounts of Assets and (Liabilities)
|
|
Gross Amounts Offset on the Consolidated Balance Sheets
|
|
Net Amount Presented on the Consolidated Balance Sheets
(1)
|
||||||
Derivative assets:
|
|
|
|
|
|
|
||||||
Commodity exchange traded derivatives contracts
|
|
$
|
672
|
|
|
$
|
(672
|
)
|
|
$
|
—
|
|
Commodity forward contracts
|
|
361
|
|
|
(194
|
)
|
|
167
|
|
|||
Interest rate hedging instruments
|
|
7
|
|
|
—
|
|
|
7
|
|
|||
Total current derivative assets
(3)
|
|
$
|
1,040
|
|
|
$
|
(866
|
)
|
|
$
|
174
|
|
Commodity exchange traded derivatives contracts
|
|
74
|
|
|
(74
|
)
|
|
—
|
|
|||
Commodity forward contracts
|
|
231
|
|
|
(32
|
)
|
|
199
|
|
|||
Interest rate hedging instruments
|
|
22
|
|
|
(3
|
)
|
|
19
|
|
|||
Total long-term derivative assets
(3)
|
|
$
|
327
|
|
|
$
|
(109
|
)
|
|
$
|
218
|
|
Total derivative assets
|
|
$
|
1,367
|
|
|
$
|
(975
|
)
|
|
$
|
392
|
|
|
|
|
|
|
|
|
||||||
Derivative (liabilities):
|
|
|
|
|
|
|
||||||
Commodity exchange traded derivatives contracts
|
|
$
|
(702
|
)
|
|
$
|
702
|
|
|
$
|
—
|
|
Commodity forward contracts
|
|
(389
|
)
|
|
209
|
|
|
(180
|
)
|
|||
Interest rate hedging instruments
|
|
(17
|
)
|
|
—
|
|
|
(17
|
)
|
|||
Total current derivative (liabilities)
(3)
|
|
$
|
(1,108
|
)
|
|
$
|
911
|
|
|
$
|
(197
|
)
|
Commodity exchange traded derivatives contracts
|
|
(88
|
)
|
|
88
|
|
|
—
|
|
|||
Commodity forward contracts
|
|
(140
|
)
|
|
35
|
|
|
(105
|
)
|
|||
Interest rate hedging instruments
|
|
(17
|
)
|
|
3
|
|
|
(14
|
)
|
|||
Total long-term derivative (liabilities)
(3)
|
|
$
|
(245
|
)
|
|
$
|
126
|
|
|
$
|
(119
|
)
|
Total derivative liabilities
|
|
$
|
(1,353
|
)
|
|
$
|
1,037
|
|
|
$
|
(316
|
)
|
Net derivative assets (liabilities)
|
|
$
|
14
|
|
|
$
|
62
|
|
|
$
|
76
|
|
(1)
|
At
December 31, 2018
and
2017
, we had
$244 million
and
$155 million
of collateral under master netting arrangements that were not offset against our derivative instruments on the Consolidated Balance Sheets primarily related to initial margin requirements.
|
(2)
|
At
December 31, 2018
, current and long-term derivative assets are shown net of collateral of
$(58) million
and
$(8) million
, respectively, and current and long-term derivative liabilities are shown net of collateral of
$49 million
and
$64 million
, respectively.
|
(3)
|
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.
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||||||
|
Fair Value
of Derivative
Assets
|
|
Fair Value
of Derivative
Liabilities
|
|
Fair Value
of Derivative
Assets
|
|
Fair Value
of Derivative
Liabilities
|
||||||||
Derivatives designated as cash flow hedging instruments:
|
|
|
|
|
|
|
|
||||||||
Interest rate hedging instruments
|
$
|
40
|
|
|
$
|
10
|
|
|
$
|
26
|
|
|
$
|
31
|
|
Total derivatives designated as cash flow hedging instruments
|
$
|
40
|
|
|
$
|
10
|
|
|
$
|
26
|
|
|
$
|
31
|
|
|
|
|
|
|
|
|
|
||||||||
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
||||||||
Commodity instruments
|
$
|
262
|
|
|
$
|
433
|
|
|
$
|
366
|
|
|
$
|
285
|
|
Total derivatives not designated as hedging instruments
|
$
|
262
|
|
|
$
|
433
|
|
|
$
|
366
|
|
|
$
|
285
|
|
Total derivatives
|
$
|
302
|
|
|
$
|
443
|
|
|
$
|
392
|
|
|
$
|
316
|
|
|
2018
|
|
2017
|
|
2016
|
||||||
Realized gain (loss)
(1)(2)
|
|
|
|
|
|
||||||
Commodity derivative instruments
|
$
|
193
|
|
|
$
|
7
|
|
|
$
|
235
|
|
Total realized gain
|
$
|
193
|
|
|
$
|
7
|
|
|
$
|
235
|
|
|
|
|
|
|
|
||||||
Mark-to-market gain (loss)
(3)
|
|
|
|
|
|
||||||
Commodity derivative instruments
|
$
|
(208
|
)
|
|
$
|
(171
|
)
|
|
$
|
(1
|
)
|
Interest rate hedging instruments
|
3
|
|
|
2
|
|
|
2
|
|
|||
Total mark-to-market gain (loss)
|
$
|
(205
|
)
|
|
$
|
(169
|
)
|
|
$
|
1
|
|
Total activity, net
|
$
|
(12
|
)
|
|
$
|
(162
|
)
|
|
$
|
236
|
|
(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.
|
|
2018
|
|
2017
|
|
2016
|
||||||
Realized and mark-to-market gain (loss)
(1)
|
|
|
|
|
|
||||||
Derivatives contracts included in operating revenues
(2)(3)
|
$
|
(369
|
)
|
|
$
|
(69
|
)
|
|
$
|
109
|
|
Derivatives contracts included in fuel and purchased energy expense
(2)(3)
|
354
|
|
|
(95
|
)
|
|
125
|
|
|||
Interest rate hedging instruments included in interest expense
|
3
|
|
|
2
|
|
|
2
|
|
|||
Total activity, net
|
$
|
(12
|
)
|
|
$
|
(162
|
)
|
|
$
|
236
|
|
(1)
|
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.
|
(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.
|
|
Gain (Loss) Recognized in
OCI (Effective Portion)
|
|
Gain (Loss) Reclassified from
AOCI into Income (Effective
Portion)
(3)(4)
|
||||||||||||||||||||||
|
2018
|
|
2017
|
|
2016
|
|
2018
|
|
2017
|
|
2016
|
|
Affected Line Item on the Consolidated Statements of Operations
|
||||||||||||
Interest rate hedging instruments
(1)(2)
|
$
|
45
|
|
|
$
|
21
|
|
|
$
|
41
|
|
|
$
|
(5
|
)
|
|
$
|
(43
|
)
|
|
$
|
(43
|
)
|
|
Interest expense
|
Interest rate hedging instruments
(1)(2)
|
1
|
|
|
5
|
|
|
—
|
|
|
(1
|
)
|
|
(5
|
)
|
|
—
|
|
|
Depreciation expense
|
||||||
Total
|
$
|
46
|
|
|
$
|
26
|
|
|
$
|
41
|
|
|
$
|
(6
|
)
|
|
$
|
(48
|
)
|
|
$
|
(43
|
)
|
|
|
(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 years ended
December 31, 2018
and
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 year ended
December 31, 2016
.
|
(2)
|
We recorded income tax expense of
$5 million
,
$6 million
and
$1 million
for the years ended
December 31, 2018
,
2017
and
2016
, 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
$34 million
,
$72 million
and
$90 million
at
December 31, 2018
,
2017
and
2016
, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were
$3 million
, $
6 million
and $
8 million
at
December 31, 2018
,
2017
and
2016
, respectively.
|
(4)
|
Includes losses of
$1 million
,
nil
and
$3 million
that were reclassified from AOCI to interest expense for the years ended
December 31, 2018
,
2017
and
2016
, respectively, where the hedged transactions became probable of not occurring.
|
11.
|
Use of Collateral
|
|
2018
|
|
2017
|
||||
Margin deposits
(1)
|
$
|
343
|
|
|
$
|
221
|
|
Natural gas and power prepayments
|
31
|
|
|
23
|
|
||
Total margin deposits and natural gas and power prepayments with our counterparties
(2)
|
$
|
374
|
|
|
$
|
244
|
|
|
|
|
|
||||
Letters of credit issued
|
$
|
1,166
|
|
|
$
|
885
|
|
First priority liens under power and natural gas agreements
|
92
|
|
|
102
|
|
||
First priority liens under interest rate hedging instruments
|
10
|
|
|
31
|
|
||
Total letters of credit and first priority liens with our counterparties
|
$
|
1,268
|
|
|
$
|
1,018
|
|
|
|
|
|
||||
Margin deposits posted with us by our counterparties
(1)(3)
|
$
|
52
|
|
|
$
|
4
|
|
Letters of credit posted with us by our counterparties
|
27
|
|
|
30
|
|
||
Total margin deposits and letters of credit posted with us by our counterparties
|
$
|
79
|
|
|
$
|
34
|
|
(1)
|
We 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 10 for further discussion of our derivative instruments subject to master netting arrangements.
|
(2)
|
At
December 31, 2018
and
2017
,
$79 million
and
$64 million
, respectively, were included in current and long-term derivative assets and liabilities,
$286 million
and
$171 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, 2018
and
2017
,
$32 million
and
$2 million
, respectively, were included in current and long-term derivative assets and liabilities and
$20 million
and
$2 million
, respectively, were included in other current liabilities on our Consolidated Balance Sheets.
|
12.
|
Income Taxes
|
•
|
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.
|
|
2018
|
|
2017
|
|
2016
|
||||||
U.S.
|
$
|
47
|
|
|
$
|
(358
|
)
|
|
$
|
116
|
|
International
|
27
|
|
|
27
|
|
|
24
|
|
|||
Total
|
$
|
74
|
|
|
$
|
(331
|
)
|
|
$
|
140
|
|
|
2018
|
|
2017
|
|
2016
|
||||||
Current:
|
|
|
|
|
|
||||||
Federal
|
$
|
—
|
|
|
$
|
(10
|
)
|
|
$
|
(10
|
)
|
State
|
20
|
|
|
18
|
|
|
14
|
|
|||
Foreign
|
(3
|
)
|
|
(14
|
)
|
|
1
|
|
|||
Total current
|
17
|
|
|
(6
|
)
|
|
5
|
|
|||
Deferred:
|
|
|
|
|
|
||||||
Federal
|
(1
|
)
|
|
5
|
|
|
10
|
|
|||
State
|
(6
|
)
|
|
6
|
|
|
27
|
|
|||
Foreign
|
54
|
|
|
3
|
|
|
6
|
|
|||
Total deferred
|
47
|
|
|
14
|
|
|
43
|
|
|||
Total income tax expense
|
$
|
64
|
|
|
$
|
8
|
|
|
$
|
48
|
|
|
2018
|
|
2017
|
|
2016
|
|||
Federal statutory tax rate
|
21.0
|
%
|
|
35.0
|
%
|
|
35.0
|
%
|
State tax expense, net of federal benefit
|
17.0
|
|
|
(6.0
|
)
|
|
19.4
|
|
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
|
(31.7
|
)
|
|
(33.0
|
)
|
|
(25.0
|
)
|
Valuation allowance related to foreign taxes
|
(138.3
|
)
|
|
0.5
|
|
|
(0.1
|
)
|
Decrease in foreign NOL due to change in ownership
|
202.3
|
|
|
—
|
|
|
—
|
|
Distributions from foreign affiliates and foreign taxes
|
6.6
|
|
|
(2.0
|
)
|
|
(0.6
|
)
|
Change in unrecognized tax benefits
|
(8.0
|
)
|
|
5.1
|
|
|
(0.1
|
)
|
Disallowed compensation
|
7.7
|
|
|
(0.6
|
)
|
|
0.9
|
|
Stock-based compensation
|
(1.5
|
)
|
|
(0.9
|
)
|
|
2.2
|
|
Equity earnings
|
1.4
|
|
|
(0.8
|
)
|
|
2.0
|
|
Merger Related Fees/Expenses
|
12.7
|
|
|
—
|
|
|
—
|
|
Depletion in excess of basis
|
(4.0
|
)
|
|
—
|
|
|
—
|
|
Other differences
|
1.3
|
|
|
0.3
|
|
|
0.6
|
|
Effective income tax rate
|
86.5
|
%
|
|
(2.4
|
)%
|
|
34.3
|
%
|
|
2018
|
|
2017
|
||||
Deferred tax assets:
|
|
|
|
||||
NOL and credit carryforwards
|
$
|
1,595
|
|
|
$
|
1,810
|
|
Taxes related to risk management activities and derivatives
|
7
|
|
|
20
|
|
||
Reorganization items and impairments
|
166
|
|
|
146
|
|
||
Other differences
|
101
|
|
|
28
|
|
||
Deferred tax assets before valuation allowance
|
1,869
|
|
|
2,004
|
|
||
Valuation allowance
|
(1,000
|
)
|
|
(1,168
|
)
|
||
Total deferred tax assets
|
869
|
|
|
836
|
|
||
Deferred tax liabilities:
|
|
|
|
||||
Property, plant and equipment
|
(890
|
)
|
|
(805
|
)
|
||
Total deferred tax liabilities
|
(890
|
)
|
|
(805
|
)
|
||
Net deferred tax asset (liability)
|
(21
|
)
|
|
31
|
|
||
Less: Non-current deferred tax liability
|
(22
|
)
|
|
(28
|
)
|
||
Deferred income tax asset, non-current
|
$
|
1
|
|
|
$
|
59
|
|
|
2018
|
|
2017
|
|
2016
|
||||||
Balance, beginning of period
|
$
|
(38
|
)
|
|
$
|
(59
|
)
|
|
$
|
(58
|
)
|
Increases related to prior year tax positions
|
(7
|
)
|
|
—
|
|
|
—
|
|
|||
Decreases related to prior year tax positions
|
17
|
|
|
11
|
|
|
1
|
|
|||
Increases related to current year tax positions
|
—
|
|
|
(2
|
)
|
|
(2
|
)
|
|||
Decreases related to change in tax rate of net deferred tax asset
|
—
|
|
|
12
|
|
|
—
|
|
|||
Balance, end of period
|
$
|
(28
|
)
|
|
$
|
(38
|
)
|
|
$
|
(59
|
)
|
13.
|
Stock-Based Compensation
|
•
|
all restricted stock and restricted stock units were vested and canceled and the holders received a cash payment equal to a share price of
$15.25
per share less any applicable withholding taxes;
|
•
|
all vested and unvested stock options were vested (in the case of unvested stock options) and canceled and the holders of the stock options received a cash payment equal to the intrinsic value based on a share price of
$15.25
per share less any applicable withholding taxes; and
|
•
|
all Performance Share Units (“PSUs”), including the PSUs awarded in 2015 for the measurement period of January 1, 2015 through December 31, 2017, were 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.
|
14.
|
Defined Contribution and Defined Benefit Plans
|
15.
|
Capital Structure
|
|
Shares
Issued
|
|
Shares
Held in
Treasury
|
|
Shares
Outstanding
|
|||
Balance, December 31, 2015
|
356,755,747
|
|
|
(93,743
|
)
|
|
356,662,004
|
|
Shares issued under Calpine Equity Incentive Plans
|
2,871,366
|
|
|
(449,079
|
)
|
|
2,422,287
|
|
Share repurchase program
|
—
|
|
|
(22,527
|
)
|
|
(22,527
|
)
|
Balance, December 31, 2016
|
359,627,113
|
|
|
(565,349
|
)
|
|
359,061,764
|
|
Shares issued under Calpine Equity Incentive Plans
|
2,050,778
|
|
|
(596,451
|
)
|
|
1,454,327
|
|
Balance, December 31, 2017
|
361,677,891
|
|
|
(1,161,800
|
)
|
|
360,516,091
|
|
Shares issued under Calpine Equity Incentive Plans
|
355,805
|
|
|
(477,711
|
)
|
|
(121,906
|
)
|
Cancellation of Calpine Corporation common stock in accordance with the Merger Agreement
|
(362,033,696
|
)
|
|
1,639,511
|
|
|
(360,394,185
|
)
|
Conversion of Merger Sub common stock to Calpine Corporation common stock in accordance with the Merger Agreement
|
105.2
|
|
|
—
|
|
|
105.2
|
|
Balance, December 31, 2018
|
105.2
|
|
|
—
|
|
|
105.2
|
|
16.
|
Commitments and Contingencies
|
|
Initial
Year
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
Thereafter
|
|
Total
|
||||||||||||||
Land and other operating leases
|
various
|
|
$
|
13
|
|
|
$
|
13
|
|
|
$
|
12
|
|
|
$
|
10
|
|
|
$
|
10
|
|
|
$
|
174
|
|
|
$
|
232
|
|
Power plant operating lease
|
2000
|
|
31
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
31
|
|
|||||||
Total leases
|
|
|
$
|
44
|
|
|
$
|
13
|
|
|
$
|
12
|
|
|
$
|
10
|
|
|
$
|
10
|
|
|
$
|
174
|
|
|
$
|
263
|
|
2019
|
$
|
6
|
|
2020
|
6
|
|
|
2021
|
8
|
|
|
2022
|
8
|
|
|
2023
|
7
|
|
|
Thereafter
|
18
|
|
|
Total
|
$
|
53
|
|
2019
|
$
|
415
|
|
2020
|
172
|
|
|
2021
|
134
|
|
|
2022
|
101
|
|
|
2023
|
93
|
|
|
Thereafter
|
201
|
|
|
Total
|
$
|
1,116
|
|
Guarantee Commitments
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
Thereafter
|
|
Total
|
||||||||||||||
Guarantee of subsidiary debt
(1)
|
|
$
|
30
|
|
|
$
|
30
|
|
|
$
|
29
|
|
|
$
|
24
|
|
|
$
|
14
|
|
|
$
|
52
|
|
|
$
|
179
|
|
Standby letters of credit
(2)(3)(4)
|
|
1,321
|
|
|
6
|
|
|
—
|
|
|
—
|
|
|
38
|
|
|
—
|
|
|
1,365
|
|
|||||||
Surety bonds
(4)(5)(6)
|
|
12
|
|
|
7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
76
|
|
|
95
|
|
|||||||
Guarantee under Accounts Receivable Sales Program
(7)
|
|
238
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
238
|
|
|||||||
Total
|
|
$
|
1,601
|
|
|
$
|
43
|
|
|
$
|
29
|
|
|
$
|
24
|
|
|
$
|
52
|
|
|
$
|
128
|
|
|
$
|
1,877
|
|
(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 8.
|
(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, 2018
,
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 29, 2019
.
|
17.
|
Related Party Transactions
|
18.
|
Segment and Significant Customer Information
|
|
Year Ended December 31, 2018
|
||||||||||||||||||||||
|
Wholesale
|
|
|
|
|
|
|
||||||||||||||||
|
West
|
|
Texas
|
|
East
|
|
Retail
|
|
Consolidation
and
Elimination
|
|
Total
|
||||||||||||
Total operating revenues
(1)
|
$
|
1,988
|
|
|
$
|
2,860
|
|
|
$
|
1,987
|
|
|
$
|
3,976
|
|
|
$
|
(1,299
|
)
|
|
$
|
9,512
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity Margin
|
$
|
1,060
|
|
|
$
|
646
|
|
|
$
|
970
|
|
|
$
|
357
|
|
|
$
|
—
|
|
|
$
|
3,033
|
|
Add: Mark-to-market commodity activity, net and other
(2)
|
(165
|
)
|
|
(197
|
)
|
|
40
|
|
|
84
|
|
|
(32
|
)
|
|
(270
|
)
|
||||||
Less:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Operating and maintenance expense
|
348
|
|
|
272
|
|
|
269
|
|
|
163
|
|
|
(32
|
)
|
|
1,020
|
|
||||||
Depreciation and amortization expense
|
269
|
|
|
237
|
|
|
180
|
|
|
53
|
|
|
—
|
|
|
739
|
|
||||||
General and other administrative expense
|
40
|
|
|
61
|
|
|
38
|
|
|
19
|
|
|
—
|
|
|
158
|
|
||||||
Other operating expenses
|
42
|
|
|
24
|
|
|
32
|
|
|
—
|
|
|
—
|
|
|
98
|
|
||||||
Impairment losses
|
—
|
|
|
—
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
10
|
|
||||||
(Income) from unconsolidated subsidiaries
|
—
|
|
|
—
|
|
|
(26
|
)
|
|
2
|
|
|
—
|
|
|
(24
|
)
|
||||||
Income (loss) from operations
|
196
|
|
|
(145
|
)
|
|
507
|
|
|
204
|
|
|
—
|
|
|
762
|
|
||||||
Interest expense
|
|
|
|
|
|
|
|
|
|
|
617
|
|
|||||||||||
(Gain) loss on extinguishment of debt and other (income) expense, net
|
|
|
|
|
|
|
|
|
|
|
53
|
|
|||||||||||
Income before income taxes
|
|
|
|
|
|
|
|
|
|
|
$
|
92
|
|
|
Year Ended December 31, 2017
|
||||||||||||||||||||||
|
Wholesale
|
|
|
|
|
|
|
||||||||||||||||
|
West
|
|
Texas
|
|
East
|
|
Retail
|
|
Consolidation
and
Elimination
|
|
Total
|
||||||||||||
Total operating revenues
(1)
|
$
|
1,881
|
|
|
$
|
2,342
|
|
|
$
|
1,658
|
|
|
$
|
3,797
|
|
|
$
|
(926
|
)
|
|
$
|
8,752
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity Margin
|
$
|
970
|
|
|
$
|
552
|
|
|
$
|
790
|
|
|
$
|
396
|
|
|
$
|
—
|
|
|
$
|
2,708
|
|
Add: Mark-to-market commodity activity, net and other
(2)
|
(19
|
)
|
|
(174
|
)
|
|
(62
|
)
|
|
(10
|
)
|
|
(29
|
)
|
|
(294
|
)
|
||||||
Less:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Operating and maintenance expense
|
361
|
|
|
308
|
|
|
302
|
|
|
138
|
|
|
(29
|
)
|
|
1,080
|
|
||||||
Depreciation and amortization expense
|
240
|
|
|
208
|
|
|
201
|
|
|
75
|
|
|
—
|
|
|
724
|
|
||||||
General and other administrative expense
|
45
|
|
|
66
|
|
|
27
|
|
|
17
|
|
|
—
|
|
|
155
|
|
||||||
Other operating expenses
|
38
|
|
|
14
|
|
|
33
|
|
|
—
|
|
|
—
|
|
|
85
|
|
||||||
Impairment losses
|
28
|
|
|
13
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
41
|
|
||||||
(Gain) on sale of assets, net
|
—
|
|
|
—
|
|
|
(27
|
)
|
|
—
|
|
|
—
|
|
|
(27
|
)
|
||||||
(Income) from unconsolidated subsidiaries
|
—
|
|
|
—
|
|
|
(24
|
)
|
|
2
|
|
|
—
|
|
|
(22
|
)
|
||||||
Income (loss) from operations
|
239
|
|
|
(231
|
)
|
|
216
|
|
|
154
|
|
|
—
|
|
|
378
|
|
||||||
Interest expense
|
|
|
|
|
|
|
|
|
|
|
621
|
|
|||||||||||
Debt modification and extinguishment costs and other (income) expense, net
|
|
|
|
|
|
|
|
|
|
|
70
|
|
|||||||||||
Loss before income taxes
|
|
|
|
|
|
|
|
|
|
|
$
|
(313
|
)
|
|
Year Ended December 31, 2016
|
||||||||||||||||||||||
|
Wholesale
|
|
|
|
|
|
|
||||||||||||||||
|
West
|
|
Texas
|
|
East
|
|
Retail
|
|
Consolidation
and
Elimination
|
|
Total
|
||||||||||||
Total operating revenues
(1)
|
$
|
1,545
|
|
|
$
|
2,145
|
|
|
$
|
1,657
|
|
|
$
|
1,520
|
|
|
$
|
(151
|
)
|
|
$
|
6,716
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity Margin
|
$
|
984
|
|
|
$
|
543
|
|
|
$
|
905
|
|
|
$
|
172
|
|
|
$
|
—
|
|
|
$
|
2,604
|
|
Add: Mark-to-market commodity activity, net and other
(2)
|
(11
|
)
|
|
12
|
|
|
15
|
|
|
(62
|
)
|
|
(29
|
)
|
|
(75
|
)
|
||||||
Less:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Operating and maintenance expense
|
355
|
|
|
298
|
|
|
312
|
|
|
41
|
|
|
(29
|
)
|
|
977
|
|
||||||
Depreciation and amortization expense
|
224
|
|
|
205
|
|
|
214
|
|
|
19
|
|
|
—
|
|
|
662
|
|
||||||
General and other administrative expense
|
38
|
|
|
56
|
|
|
40
|
|
|
6
|
|
|
—
|
|
|
140
|
|
||||||
Other operating expenses
|
33
|
|
|
8
|
|
|
38
|
|
|
—
|
|
|
—
|
|
|
79
|
|
||||||
Impairment losses
|
13
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
13
|
|
||||||
(Gain) on sale of assets, net
|
—
|
|
|
—
|
|
|
(157
|
)
|
|
—
|
|
|
—
|
|
|
(157
|
)
|
||||||
(Income) from unconsolidated subsidiaries
|
—
|
|
|
—
|
|
|
(24
|
)
|
|
—
|
|
|
—
|
|
|
(24
|
)
|
||||||
Income (loss) from operations
|
310
|
|
|
(12
|
)
|
|
497
|
|
|
44
|
|
|
—
|
|
|
839
|
|
||||||
Interest expense
|
|
|
|
|
|
|
|
|
|
|
631
|
|
|||||||||||
Debt modification and extinguishment costs and other (income) expense, net
|
|
|
|
|
|
|
|
|
|
|
49
|
|
|||||||||||
Income before income taxes
|
|
|
|
|
|
|
|
|
|
|
$
|
159
|
|
(1)
|
Includes intersegment revenues of
$488 million
,
$324 million
and
$20 million
in the West,
$573 million
,
$361 million
and
$81 million
in Texas,
$234 million
,
$237 million
and
$48 million
in the East and
$4 million
,
$4 million
,
$2 million
in Retail for the years ended
December 31, 2018
,
2017
and
2016
, respectively.
|
(2)
|
Includes
nil
,
$(8) million
and
$(2) million
of lease levelization and
$104 million
,
$178 million
and
$122 million
of amortization expense for the years ended
December 31, 2018
,
2017
and
2016
, respectively.
|
19.
|
Quarterly Consolidated Financial Data (unaudited)
|
|
Quarter Ended
|
||||||||||||||
|
December 31
|
|
September 30
|
|
June 30
|
|
March 31
|
||||||||
|
(in millions)
|
||||||||||||||
2018
|
|
|
|
|
|
|
|
||||||||
Operating revenues
|
$
|
2,354
|
|
|
$
|
2,890
|
|
|
$
|
2,259
|
|
|
$
|
2,009
|
|
Income (loss) from operations
|
$
|
105
|
|
|
$
|
568
|
|
|
$
|
417
|
|
|
$
|
(328
|
)
|
Net income (loss) attributable to Calpine
|
$
|
(16
|
)
|
|
$
|
272
|
|
|
$
|
352
|
|
|
$
|
(598
|
)
|
|
|
|
|
|
|
|
|
||||||||
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
|
)
|
Description
|
Balance at
Beginning
of Year
|
|
Charged to
Expense
|
|
Charged to Other Accounts
|
|
Deductions
(1)
|
|
Balance at
End of Year
|
||||||||||
|
(in millions)
|
||||||||||||||||||
Year Ended December 31, 2018
|
|
|
|
|
|
|
|
|
|
||||||||||
Allowance for doubtful accounts
|
$
|
9
|
|
|
$
|
5
|
|
|
$
|
1
|
|
|
$
|
(6
|
)
|
|
$
|
9
|
|
Deferred tax asset valuation allowance
|
1,168
|
|
|
(168
|
)
|
|
—
|
|
|
—
|
|
|
1,000
|
|
|||||
Year Ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
||||||||||
Allowance for doubtful accounts
|
$
|
6
|
|
|
$
|
4
|
|
|
$
|
2
|
|
|
$
|
(3
|
)
|
|
$
|
9
|
|
Deferred tax asset valuation allowance
|
1,581
|
|
|
(413
|
)
|
|
—
|
|
|
—
|
|
|
1,168
|
|
|||||
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
||||||||||
Allowance for doubtful accounts
|
$
|
2
|
|
|
$
|
4
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
6
|
|
Deferred tax asset valuation allowance
|
1,637
|
|
|
(56
|
)
|
|
—
|
|
|
—
|
|
|
1,581
|
|
CPN MANAGEMENT, LP
717 TEXAS AVENUE
SUITE 100 HOUSTON, TEXAS 77002 |
|
Re:
|
Award of Class B Interest in CPN Management, LP
|
Total Class B Interest subject to vesting
(as of the Date of Grant)
|
Incremental Vesting of
Award
(as of annual vesting dates)
|
[ ], 2018: [ ]%
|
March 8, 2019: 20%
March 8, 2020: 20%
March 8, 2021: 20%
March 8, 2022: 20%
March 8, 2023: 20%
|
|
|
|
Sincerely,
|
|
|
|
|
|
|
|
|
|
Calpine Corporation
|
|
|
|
|
|
|
|
|
|
By:
|
/s/ HETHER BENJAMIN BROWN
|
|
|
|
Name:
|
Hether Benjamin Brown
|
|
|
|
Title:
|
Sr. Vice President, Chief Administrative Officer
|
ACKNOWLEDGED & AGREED
|
|
|
|
|
|
|
|
|
|
Charles M. Gates
|
|
|
|
|
|
|
|
|
|
By:
|
/s/ CHARLES M. GATES
|
|
|
|
Name:
|
Charles M. Gates
|
|
|
|
Title:
|
Executive Vice President, Power Operations
|
|
|
|
Severance Benefits Eligibility:
|
As an Executive Vice President, and in the event of severance, your severance benefits are defined and will be subject to the Calpine Corporation Change in Control and Severance Benefits Plan, as in effect as of today’s date (the “
Plan
”). Your status as a Tier 3 Participant, and your benefits as a Tier 3 Participant set forth in the Plan as it stands today will remain unchanged notwithstanding anything to the contrary in Section 2.01(a) or Section 7.03 of the Plan. For the avoidance of doubt, any target bonus amount under the Plan shall be determined based on your participation in the Calpine Incentive Plan and not any other bonus program or arrangement. Notwithstanding the foregoing, following the third anniversary of the date of this letter, if your employment terminates for any reason, you shall be entitled to the benefits provided in this paragraph, without duplication of any other severance payments for which you may be eligible under the Plan:
(a)
Calpine shall, on the date on which bonuses are paid to all other employees, provided that such payment shall be made in all events in the calendar year immediately following the calendar year of such termination of employment, pay you an amount equal to your annual cash bonus that you would have been entitled to receive in respect of the fiscal year in which the termination date occurs, had you continued in employment until the end of such fiscal year, which amount, determined based on Calpine’s actual performance for such year relative to the performance goals applicable to you, shall be multiplied by a fraction (i) the numerator of which is the number of days in such fiscal year through the termination date and (ii) the denominator of which is 365;
(b)
upon your election, CPN Management’s, LP, a Delaware limited partnership (the “
Partnership
”) and/or Calpine’s exercise of the Partnership Redemption Right (as defined in the Amended and Restated Limited Partnership Agreement of CPN Management, LP, dated and effective as of March 8, 2018 (the “
LP Agreement
”)), and/or the Calpine Repurchase Right (as defined in the LP Agreement), respectively, and/or any other applicable call right in favor of the Partnership and/or Calpine that may be applicable to vested Class B Interests (as defined in the LP Agreement) under the plans, documents and agreements governing such interests shall be subject to your consent, which may be withheld in your absolute discretion.
|
|
|
Section 280G Gross-Up
:
|
(a) Calpine shall pay to or for your benefit, at the time specified in this paragraph, an additional amount (the “
Gross-up Payment
”) such that the net after-tax amount of the Gross-Up Payment retained by you, after deduction of any Excise Tax (as defined below) and any federal and state and local taxes imposed on the Gross-Up Payment itself, shall be equal to the Excise Tax imposed on the 280G Payments (as defined below) if:
|
|
(i)
there is a change in the ownership of Calpine, a change in the effective control of Calpine or a change in the ownership of a substantial portion of the assets of Calpine (in each case, within the meaning of Section 280G of Code and the regulations thereunder);
(ii)
immediately before the change described in subparagraph (a)(i), the stock in Calpine was readily tradeable on an established securities market or otherwise (within the meaning of Section 280G of the Code and the regulations thereunder); and
(iii)
it is determined that any payments, rights or benefits, or the lapse or termination of any restriction, whether pursuant to the terms of this Offer Letter or any other plan, arrangement or agreement between you and Calpine or with any person affiliated with Calpine, or with any person who acquires ownership or effective control or ownership of a substantial portion of Calpine’s assets (within the meaning of Section 280G of the Code and the regulations thereunder) or with any affiliate of such person, and whether or not your employment has then terminated (collectively, the “
280G Payments
”), would be subject to the excise tax imposed by Section 4999 of the Code or any interest or penalties with respect to such excise tax (such excise tax, together with any such interest and penalties, are collectively referred to as the “
Excise Tax
”).
The Gross-Up Payment shall be paid to or for your benefit no later than fifteen (15) business days prior to the date by which you are required to pay the Excise Tax or any portion thereof to any federal, state or local taxing authority, without regard to extensions, subject to the terms of this paragraph.
(b)
For purposes of determining the amount of the Gross-Up Payment, you shall be deemed to pay federal income taxes at the highest marginal rate of federal income taxation in the calendar year in which the Gross-Up Payment is to be made and state and local income taxes at the highest marginal rate of taxation in the state and locality of your residence in the calendar year in which the Gross-Up Payment is made, net of the maximum reduction in federal income taxes, if any, which could be obtained from deduction of such state and local taxes. For the avoidance of doubt, the intent of the Gross-Up Payment is solely to make the imposition of the Excise Tax tax-neutral for you.
(c)
Subject to any determinations made by the Internal Revenue Service (the “
IRS
”), all determinations required to be made under this paragraph relating to the Gross-Up Payment, including whether and when a Gross-Up Payment is required and the amount of such Gross-Up Payment and the assumptions to be utilized in arriving at such determination, shall be made by a nationally recognized certified public accounting firm or a consulting firm (the “
Accountants
”) as may be designated by Calpine and that is not serving as accountant or auditor for Calpine or the individual, entity or group effecting the
|
|
Change in Control (as defined in the award agreement granting you Class B Interests (as defined in the Amended and Restated Limited Partnership Agreement of CPN Management, LP, dated and effective as of March 8, 2018), which shall provide detailed supporting calculations both to you and Calpine. All fees and expenses of the Accountants will be borne by Calpine. Subject to any determinations made by the IRS, determinations of the Accountants under this Offer Letter with respect to (i) the initial amount of any Gross-Up Payment and (ii) any subsequent adjustment of such payment shall be binding on you and Calpine.
(d)
In the event that the Excise Tax is subsequently determined to be less than the amount taken into account hereunder, you shall repay to Calpine at the time that the amount of such reduction in Excise Tax is finally determined, the portion of the Gross-Up Payment attributable to such reduction, with the amount of such repayment determined by the Accountants; provided, however, that if Calpine determines that such repayment obligation would be or result in an unlawful extension of credit under Section 13(k) of the Securities Exchange Act of 1934, as amended (the “
Exchange Act
”), repayment shall not be required. In the event that the Excise Tax is determined by the Accountants to exceed the amount taken into account hereunder (including by reason of any payment the existence or amount of which cannot be determined at the time of the Gross-Up Payment), Calpine shall make an additional Gross-Up Payment in respect of such excess (plus any interest and penalties payable with respect to such excess) at the time that the amount of such excess is finally determined.
(e)
You shall notify Calpine of any audit or review by the IRS of your federal income tax return for the year in which a payment under this Offer Letter is made within ten (10) days of your receipt of notification of such audit or review. You shall not pay any IRS claim resulting from any such audit or review prior to the expiration of the thirty (30)-day period following the date on which he gives notice to Calpine (or such shorter period ending on the date that any payment of taxes with respect to such claim is due). If Calpine notifies you in writing prior to the expiration of such period that it desires to contest such claim, you shall:
(i)
give Calpine any information reasonably requested by Calpine relating to such claim;
(ii)
take such action in connection with contesting such claim as Calpine shall reasonably request in writing from time to time, including without limitation, accepting legal representation with respect to such claim by an attorney reasonably selected by Calpine;
(iii)
cooperate with Calpine in good faith in order to effectively contest such claim; and
(iv)
permit Calpine to participate in any proceedings relating to such claim; provided, however, that Calpine shall bear directly all costs and expenses (including additional interest and penalties) incurred in
|
|
connection with such contest and shall indemnify and hold you harmless, on an after-tax basis, for any Excise Tax or federal, state and local income and employment tax (including interest and penalties with respect thereto) imposed as a result of such representation and payment of costs and expenses. Without limitation on the foregoing provisions of this subparagraph (e), Calpine shall control all proceedings taken in connection with such contest and, at its sole option, may pursue or forgo any and all administrative appeals, proceedings, hearings and conferences with the taxing authority in respect of such claim and may, at its sole option, either direct you to pay the tax claimed and sue for a refund or to contest the claim in any permissible manner, and you agree to prosecute such contest to a determination before any administrative tribunal, in a court of initial jurisdiction and in one or more appellate courts, as Calpine shall determine; provided, however, that if Calpine directs you to pay such claim and sue for a refund, Calpine shall advance the amount of such payment to you, on an after-tax basis, and shall hold you harmless from any Excise Tax or federal, state or local income or employment tax (including interest or penalties with respect thereto) imposed with respect to such advance or with respect to any imputed income with respect to such advance; and further provided that any extension of the statute of limitations relating to your payment of taxes for the taxable year with respect to with such contested amount is claimed to be due is limited solely to such contested amount. The Company’s control of the contest, however, shall be limited to issues with respect to which a Gross-Up Payment would be payable hereunder, and you shall be entitled to settle or contest, as the case may be, any other issue raised by the IRS or any other taxing authority. If, after your receipt of an amount advanced by Calpine pursuant to this subparagraph, you become entitled to receive any refund with respect to such claim, you shall (subject to Calpine’s complying with the requirements of this subparagraph) promptly pay to Calpine the amount of such refund (together with any interest paid or credited thereon after taxes applicable thereto); provided, however, that if Calpine determines that such repayment obligation would be or result in an unlawful extension of credit under Section 13(k) of the Exchange Act, repayment shall not be required. If, after your receipt of an amount advanced by Calpine pursuant to this subparagraph, a determination is made that you shall not be entitled to any refund with respect to any such claim and Calpine does not notify you in writing of its intent to contest such denial of refund prior to the expiration of thirty (30) days after such determination, then such advance shall be forgiven and shall not be required to be repaid and the amount of such advance shall offset, to the extent thereof, the amount of Gross-Up Payment required to be paid.
(f)
If, other than in the circumstances described in subparagraph (a), it is determined that any of the 280G Payments would be subject to the Excise Tax, then, to the extent necessary to make such portion of the 280G Payments not
|
|
subject to the Excise Tax (and after taking into account any reduction in the 280G Payments provided by reason of Section 280G of the Code under any other plan, arrangement or agreement), the portion of the 280G Payments that do not constitute deferred compensation within the meaning of Section 409A shall first be reduced (if necessary, to zero), and all other 280G Payments shall thereafter be reduced (if necessary, to zero) with cash payments being reduced before noncash payments, and payments to be paid last being reduced first, but only if (i) the net amount of such 280G Payments, as so reduced (and after subtracting the net amount of federal, state and local income taxes on such reduced 280G Payments and after taking into account any phase out of itemized deductions and personal exemptions attributable to such reduced 280G Payments) is greater than or equal to (ii) the net amount of such 280G Payments without such reduction (but after subtracting the net amount of federal, state and local income taxes on such 280G Payments and the amount of Excise Tax to which you would be subject in respect of such unreduced 280G Payments and after taking into account any phase out of itemized deductions and personal exemptions attributable to such unreduced 280G Payments).
|
Subsidiaries of the Company
|
|
|
|
|
|
|
|
Entity
|
|
Jurisdiction
|
|
1066917 Ontario Inc.
|
|
Ontario
|
|
Anacapa Land Company, LLC
|
|
Delaware
|
|
Anderson Springs Energy Company
|
|
California
|
|
Auburndale Peaker Energy Center, LLC
|
|
Delaware
|
|
Aviation Funding Corp.
|
|
Delaware
|
|
Baytown Energy Center, LLC
|
|
Delaware
|
|
Bethpage Energy Center 3, LLC
|
|
Delaware
|
|
Big Blue River Wind Farm, LLC
|
|
Delaware
|
|
Bluestone Wind, LLC
|
|
Delaware
|
|
Butter Creek Energy Center, LLC
|
|
Delaware
|
|
Byron Highway Energy Center, LLC
|
|
Delaware
|
|
CalBatt Energy Storage, LLC
|
|
Delaware
|
|
CalGen Expansion Company, LLC
|
|
Delaware
|
|
CalGen Project Equipment Finance Company Three, LLC
|
|
Delaware
|
|
Calnex Holdings, LLC
|
|
Delaware
|
|
Calpine Acquisition Company II, LLC
|
|
Delaware
|
|
Calpine Acquisition Company III, LLC
|
|
Delaware
|
|
Calpine Acquisition Company, LLC
|
|
Delaware
|
|
Calpine Administrative Services Company, Inc.
|
|
Delaware
|
|
Calpine Agnews, Inc.
|
|
California
|
|
Calpine Auburndale Holdings, LLC
|
|
Delaware
|
|
Calpine Bethlehem, LLC
|
|
Delaware
|
|
Calpine Bosque Energy Center, LLC
|
|
Delaware
|
|
Calpine c*Power, Inc.
|
|
Delaware
|
|
Calpine CalGen Holdings, Inc.
|
|
Delaware
|
|
Calpine Calistoga Holdings, LLC
|
|
Delaware
|
|
Calpine Canada Energy Finance ULC
|
|
Nova Scotia
|
|
Calpine Canada Energy Ltd.
|
|
Nova Scotia
|
|
Calpine CCFC GP, LLC
|
|
Delaware
|
|
Calpine CCFC LP, LLC
|
|
Delaware
|
|
Calpine Central Texas GP, Inc.
|
|
Delaware
|
|
Calpine Central, Inc.
|
|
Delaware
|
|
Calpine Central-Texas, Inc.
|
|
Delaware
|
|
Calpine Cogeneration Corporation
|
|
Delaware
|
|
Calpine Construction Finance Company, L.P.
|
|
Delaware
|
|
Calpine Construction Management Company, Inc.
|
|
Delaware
|
|
Calpine Development Holdings, Inc.
|
|
Delaware
|
|
Calpine Eastern Corporation
|
|
Delaware
|
|
Calpine Edinburg, Inc.
|
|
Delaware
|
|
Calpine Energy Financial Holdings, LLC
|
|
Delaware
|
|
Calpine Energy Services GP, LLC
|
|
Delaware
|
|
Calpine Energy Services Holdco II, LLC
|
|
Delaware
|
|
Calpine Energy Services Holdco LLC
|
|
Delaware
|
|
Calpine Energy Services LP, LLC
|
|
Delaware
|
|
Calpine Energy Services, L.P.
|
|
Delaware
|
|
Calpine Energy Solutions, LLC
|
|
California
|
|
Calpine Fore River Energy Center, LLC
|
|
Delaware
|
|
Subsidiaries of the Company
|
|
|
|
|
|
|
|
Entity
|
|
Jurisdiction
|
|
Calpine Fore River Operating Company, LLC
|
|
Delaware
|
|
Calpine Foundation
|
|
Delaware
|
|
Calpine Fuels Corporation
|
|
California
|
|
Calpine GEC Holdings, LLC
|
|
Delaware
|
|
Calpine Generating Company, LLC
|
|
Delaware
|
|
Calpine Geysers Company, LLC
|
|
Delaware
|
|
Calpine Gilroy 1, LLC
|
|
Delaware
|
|
Calpine Gilroy Cogen, L.P.
|
|
Delaware
|
|
Calpine Global Services Company, Inc.
|
|
Delaware
|
|
Calpine Granite Holdings, LLC
|
|
Delaware
|
|
Calpine Greenfield (Holdings) Corporation
|
|
Delaware
|
|
Calpine Greenleaf Holdings, Inc.
|
|
Delaware
|
|
Calpine Greenleaf, Inc.
|
|
Delaware
|
|
Calpine Guadalupe GP, LLC
|
|
Delaware
|
|
Calpine Guadalupe LP, LLC
|
|
Delaware
|
|
Calpine Hidalgo Energy Center, L.P.
|
|
Delaware
|
|
Calpine Hidalgo Holdings, Inc.
|
|
Delaware
|
|
Calpine Hidalgo, Inc.
|
|
Delaware
|
|
Calpine Holdings Development, LLC
|
|
Delaware
|
|
Calpine Holdings, LLC
|
|
Delaware
|
|
Calpine International Holdings, LLC
|
|
Delaware
|
|
Calpine Kennedy Operators, Inc.
|
|
New York
|
|
Calpine KIA, Inc.
|
|
New York
|
|
Calpine King City Cogen, LLC
|
|
Delaware
|
|
Calpine King City, Inc.
|
|
Delaware
|
|
Calpine Leasing Inc.
|
|
Delaware
|
|
Calpine Long Island, Inc.
|
|
Delaware
|
|
Calpine Magic Valley Pipeline, LLC
|
|
Delaware
|
|
Calpine Mexican Holdings, LLC
|
|
Delaware
|
|
Calpine Mid Merit, LLC
|
|
Delaware
|
|
Calpine Mid-Atlantic Development, LLC
|
|
Delaware
|
|
Calpine Mid-Atlantic Energy, LLC
|
|
Delaware
|
|
Calpine Mid-Atlantic Generation, LLC
|
|
Delaware
|
|
Calpine Mid-Atlantic Marketing, LLC
|
|
Delaware
|
|
Calpine Mid-Atlantic Operating, LLC
|
|
Delaware
|
|
Calpine Mid-Merit II, LLC
|
|
Delaware
|
|
Calpine Monterey Cogeneration, Inc.
|
|
California
|
|
Calpine MVP, LLC
|
|
Delaware
|
|
Calpine New Jersey Generation, LLC
|
|
Delaware
|
|
Calpine Newark, LLC
|
|
Delaware
|
|
Calpine Northbrook Holdings Corporation
|
|
Delaware
|
|
Calpine Northbrook Investors, LLC
|
|
Delaware
|
|
Calpine Northbrook Project Holdings, LLC
|
|
Delaware
|
|
Calpine Operating Services Company, Inc.
|
|
Delaware
|
|
Calpine Operations Management Company, Inc.
|
|
Delaware
|
|
Calpine Pasadena Cogeneration, Inc.
|
|
Delaware
|
|
Calpine Philadelphia, Inc.
|
|
Delaware
|
|
Calpine Pittsburg, LLC
|
|
Delaware
|
|
Calpine Power Company
|
|
California
|
|
Calpine Power Management, LLC
|
|
Delaware
|
|
Subsidiaries of the Company
|
|
|
|
|
|
|
|
Entity
|
|
Jurisdiction
|
|
Calpine Power, Inc.
|
|
Virginia
|
|
Calpine PowerAmerica, LLC
|
|
Delaware
|
|
Calpine PowerAmerica-CA, LLC
|
|
Delaware
|
|
Calpine PowerAmerica-MA, LLC
|
|
Delaware
|
|
Calpine PowerAmerica-ME, LLC
|
|
Delaware
|
|
Calpine Project Holdings, Inc.
|
|
Delaware
|
|
Calpine Receivables, LLC
|
|
Delaware
|
|
Calpine Retail Holdings, LLC
|
|
Delaware
|
|
Calpine Riverside Holdings, LLC
|
|
Delaware
|
|
Calpine Russell City, LLC
|
|
Delaware
|
|
Calpine Siskiyou Geothermal Partners, L.P.
|
|
California
|
|
Calpine Solar Development Holdings, LLC
|
|
Delaware
|
|
Calpine Solar, LLC
|
|
Delaware
|
|
Calpine Steamboat Holdings, LLC
|
|
Delaware
|
|
Calpine Stony Brook Operators, Inc.
|
|
New York
|
|
Calpine Stony Brook, Inc.
|
|
New York
|
|
Calpine TCCL Holdings, Inc.
|
|
Delaware
|
|
Calpine Texas Cogeneration, Inc.
|
|
Delaware
|
|
Calpine Texas Pipeline GP, LLC
|
|
Delaware
|
|
Calpine Texas Pipeline LP, LLC
|
|
Delaware
|
|
Calpine Texas Pipeline, L.P.
|
|
Delaware
|
|
Calpine ULC I Holding, LLC
|
|
Delaware
|
|
Calpine University Power, Inc.
|
|
Delaware
|
|
Calpine Vineland Solar, LLC
|
|
Delaware
|
|
Calpine Wind Holdings, LLC
|
|
Delaware
|
|
Calpine York Holdings, LLC
|
|
Delaware
|
|
Cavallo Energy Texas LLC
|
|
Texas
|
|
CCFC Finance Corp.
|
|
Delaware
|
|
CCFC Preferred Holdings, LLC
|
|
Delaware
|
|
CCFC Sutter Energy, LLC
|
|
Delaware
|
|
CES Marketing IX, LLC
|
|
Delaware
|
|
CES Marketing X, LLC
|
|
Delaware
|
|
Champion Energy Marketing LLC
|
|
Delaware
|
|
Champion Energy Services, LLC
|
|
Texas
|
|
Champion Energy, LLC
|
|
Texas
|
|
Channel Energy Center, LLC
|
|
Delaware
|
|
Chisholm Breeze Wind, LLC
|
|
Delaware
|
|
Clear Lake Cogeneration Limited Partnership
|
|
Delaware
|
|
CM Greenfield Power Corp.
|
|
Canada
|
|
Corpus Christi Cogeneration, LLC
|
|
Delaware
|
|
CPN 3rd Turbine, Inc.
|
|
Delaware
|
|
CPN Acadia, Inc.
|
|
Delaware
|
|
CPN Bethpage 3rd Turbine, Inc.
|
|
Delaware
|
|
CPN Cascade, Inc.
|
|
Delaware
|
|
CPN Clear Lake, Inc.
|
|
Delaware
|
|
CPN Insurance Corporation
|
|
Hawaii
|
|
CPN Pipeline Company
|
|
Delaware
|
|
CPN Pryor Funding Corporation
|
|
Delaware
|
|
CPN Telephone Flat, Inc.
|
|
Delaware
|
|
CPN Wild Horse Geothermal LLC
|
|
Delaware
|
|
Subsidiaries of the Company
|
|
|
|
|
|
|
|
Entity
|
|
Jurisdiction
|
|
Creed Energy Center, LLC
|
|
Delaware
|
|
Deer Park Energy Center LLC
|
|
Delaware
|
|
Deer Park Holdings, LLC
|
|
Delaware
|
|
Delta Energy Center, LLC
|
|
Delaware
|
|
Delta, LLC
|
|
Delaware
|
|
Freeport Energy Center, LLC
|
|
Delaware
|
|
Freestone Power Generation, LLC
|
|
Delaware
|
|
Garrison Energy Center LLC
|
|
Delaware
|
|
GEC Bethpage Inc.
|
|
Delaware
|
|
GEC Holdings, LLC
|
|
Delaware
|
|
Geysers Holdings LLC
|
|
Delaware
|
|
Geysers Intermediate Holdings LLC
|
|
Delaware
|
|
Geysers Power Company, LLC
|
|
Delaware
|
|
Geysers Power I Company
|
|
Delaware
|
|
Gilroy Energy Center, LLC
|
|
Delaware
|
|
Goose Haven Energy Center, LLC
|
|
Delaware
|
|
Grange Hall Wind, LLC
|
|
Delaware
|
|
Granite Ridge Energy, LLC
|
|
Delaware
|
|
Granite Ridge Operating, LLC
|
|
Delaware
|
|
Greenfield Energy Centre LP
|
|
Ontario
|
|
Guadalupe Peaking Energy Center, LLC
|
|
Delaware
|
|
Guadalupe Power Partners, LP
|
|
Delaware
|
|
Hermiston Power LLC
|
|
Delaware
|
|
High Bridge Wind, LLC
|
|
Delaware
|
|
Horizon Hill Wind, LLC
|
|
Delaware
|
|
Idlewild Fuel Management Corp.
|
|
Delaware
|
|
Jack A. Fusco Energy Center, LLC
|
|
Delaware
|
|
JMC Bethpage, Inc.
|
|
Delaware
|
|
Johanna Energy Center, LLC
|
|
Delaware
|
|
Johanna Energy Storage, LLC
|
|
Delaware
|
|
KC Wind, LLC
|
|
Delaware
|
|
KIAC Partners
|
|
New York
|
|
Long Mountain Wind, LLC
|
|
Delaware
|
|
Los Esteros Critical Energy Facility, LLC
|
|
Delaware
|
|
Los Esteros Holdings, LLC
|
|
Delaware
|
|
Los Medanos Energy Center LLC
|
|
Delaware
|
|
Magic Valley Pipeline, L.P.
|
|
Delaware
|
|
Mankato Holdings, LLC
|
|
Delaware
|
|
Metcalf Energy Center, LLC
|
|
Delaware
|
|
Metcalf Funding, LLC
|
|
Delaware
|
|
Metcalf Holdings, LLC
|
|
Delaware
|
|
Mission Rock Energy Center, LLC
|
|
Delaware
|
|
Modoc Power, Inc.
|
|
California
|
|
Morgan Energy Center, LLC
|
|
Delaware
|
|
Mount Hoffman Geothermal Company, L.P.
|
|
California
|
|
NAPB Holdco, LLC
|
|
Delaware
|
|
NAPGS Holdco, LLC
|
|
Delaware
|
|
New Development Holdings, LLC
|
|
Delaware
|
|
New Steamboat Holdings, LLC
|
|
Delaware
|
|
Nissequogue Cogen Partners
|
|
New York
|
|
Subsidiaries of the Company
|
|
|
|
|
|
|
|
Entity
|
|
Jurisdiction
|
|
North American Power and Gas Services, LLC
|
|
Delaware
|
|
North American Power and Gas, LLC
|
|
Delaware
|
|
North American Power Business, LLC
|
|
Delaware
|
|
NTC Five, Inc.
|
|
Delaware
|
|
O.L.S. Energy-Agnews, Inc.
|
|
Delaware
|
|
Osprey Energy Center, LLC
|
|
Delaware
|
|
Otay Holdings, LLC
|
|
Delaware
|
|
Otay Mesa Energy Center, LLC
|
|
Delaware
|
|
Pasadena Cogen LLC
|
|
Delaware
|
|
Pasadena Cogeneration L.P.
|
|
Delaware
|
|
Pastoria Energy Center, LLC
|
|
Delaware
|
|
Pastoria Energy Facility L.L.C.
|
|
Delaware
|
|
Pastoria Solar Energy Company, LLC
|
|
Delaware
|
|
Philadelphia Biogas Supply, Inc.
|
|
Delaware
|
|
Pine Bluff Energy, LLC
|
|
Delaware
|
|
Pioneer Valley Energy Center, LLC
|
|
Massachusetts
|
|
Power Contract Financing, L.L.C.
|
|
Delaware
|
|
Rancho Dominguez Energy Center, LLC
|
|
Delaware
|
|
Rio Hondo Energy Center, LLC
|
|
Delaware
|
|
RockGen Energy LLC
|
|
Wisconsin
|
|
Russell City Energy Company, LLC
|
|
Delaware
|
|
SoCal Development Holdings, LLC
|
|
Delaware
|
|
South Point Energy Center, LLC
|
|
Delaware
|
|
South Point Holdings, LLC
|
|
Delaware
|
|
Stony Brook Cogeneration Inc.
|
|
Delaware
|
|
Stony Brook Fuel Management Corp.
|
|
Delaware
|
|
Sutter Dryers, Inc.
|
|
California
|
|
TBG Cogen Partners
|
|
New York
|
|
Texas City Cogeneration, LLC
|
|
Delaware
|
|
Texas Cogeneration Five, Inc.
|
|
Delaware
|
|
Texas Cogeneration One Company
|
|
Delaware
|
|
The Calpine Employee Relief Fund
|
|
Texas
|
|
Thermal Power Company
|
|
California
|
|
Washington Parish Energy Center One, LLC
|
|
Delaware
|
|
Washington Parish Holdings, LLC
|
|
Delaware
|
|
Westbrook Blackstart, LLC
|
|
Delaware
|
|
Westbrook Energy Center, LLC
|
|
Delaware
|
|
Whitby Cogeneration Limited Partnership
|
|
Ontario
|
|
White Rock Wind East, LLC
|
|
Delaware
|
|
White Rock Wind West, LLC
|
|
Delaware
|
|
Zion Energy LLC
|
|
Delaware
|
|
1.
|
I have reviewed this annual report on Form 10-K of Calpine Corporation (the “registrant”);
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
|
c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
/s/ JOHN B. (THAD) HILL III
|
John B. (Thad) Hill III
|
President, Chief Executive Officer and Director
|
Calpine Corporation
|
1.
|
I have reviewed this annual report on Form 10-K of Calpine Corporation (the “registrant”);
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
|
c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
/s/ ZAMIR RAUF
|
Zamir Rauf
|
Executive Vice President and
Chief Financial Officer
|
Calpine Corporation
|
(1)
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
|
|
|
|
|
|
|
|
/s/ JOHN B. (THAD) HILL III
|
|
|
|
/s/ ZAMIR RAUF
|
|
|
John B. (Thad) Hill III
|
|
|
|
Zamir Rauf
|
|
|
President,
|
|
|
|
Executive Vice President and
|
|
|
Chief Executive Officer and Director
|
|
|
|
Chief Financial Officer
|
|
|
Calpine Corporation
|
|
|
|
Calpine Corporation
|
|