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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, 2016
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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 [X]
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Accelerated filer [ ]
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Non-accelerated filer [ ]
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Smaller reporting company [ ]
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(Do not check if a smaller reporting 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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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
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2019 First Lien Notes
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The $400 million aggregate principal amount of 8.0% senior secured notes due 2019, issued May 25, 2010, and repaid in a series of transactions on November 7, 2012, December 2, 2013 and July 22, 2014
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2019 First Lien Term Loan
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The $835 million first lien senior secured term loan, dated October 9, 2012, among Calpine Corporation, as borrower, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent, repaid on May 31, 2016
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2020 First Lien Term Loan
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The $390 million first lien senior secured term loan, dated October 23, 2013, among Calpine Corporation, as borrower, the lenders party thereto, Citibank, N.A., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent, repaid on May 31, 2016
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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, and partially repaid in a series of transactions on November 7, 2012, December 2, 2013, December 4, 2014, February 3, 2015, December 7, 2015 and December 19, 2016
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2023 First Lien Term Loan
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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
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2023 First Lien Term Loans
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Collectively, the 2023 First Lien Term Loan and the New 2023 First Lien Term Loan
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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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The $625 million aggregate principal amount of 5.25% senior secured notes due 2026, issued May 31, 2016
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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, formerly Noble Solutions, and Calpine Receivables, formerly Noble Americas Treasury Solutions LLC, and the purchase and sale agreement between Calpine Receivables and an unaffiliated financial institution, both which allows for the revolving sale of up to $250 million in certain trade accounts receivables to third parties
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Adjusted EBITDA
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EBITDA as adjusted for the effects of (a) impairment charges, (b) major maintenance expense, (c) operating lease expense, (d) gains or losses on commodity derivative mark-to-market activity, (e) adjustments to reflect only the Adjusted EBITDA from our unconsolidated investments, (f) adjustments to exclude the Adjusted EBITDA related to the noncontrolling interest, (g) stock-based compensation expense, (h) gains or losses on sales, dispositions or retirements of assets, (i) non-cash gains and losses from foreign currency translations, (j) gains or losses on the repurchase, modification or extinguishment of debt, (k) non-cash GAAP-related adjustments to levelize revenues from tolling agreements and (l) other extraordinary, unusual or non-recurring items
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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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Bcf
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Billion cubic feet
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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
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Calpine Equity Incentive Plans
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Collectively, the Director Plan and the Equity Plan, which provide for grants of equity awards to Calpine non-union employees and non-employee members of Calpine’s Board of Directors
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Calpine Receivables
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Calpine Receivables, LLC, formerly Noble Americas Treasury Solutions LLC, an indirect, wholly-owned subsidiary of Calpine, which was established as bankruptcy remote, special purpose subsidiary and is responsible for administering the Accounts Receivable Sales Program
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Calpine Solutions
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Calpine Energy Solutions, LLC, formerly Noble Solutions, an indirect, wholly-owned subsidiary of Calpine, which is the third largest supplier of power to commercial and industrial retail customers in the United States with customers in 19 states, including presence in California, Texas, the Mid-Atlantic and the Northeast
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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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CARB
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California Air Resources Board
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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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ABBREVIATION
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DEFINITION
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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
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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 Texas, Illinois, Pennsylvania, Ohio, New Jersey, Maryland, Massachusetts, New York, Delaware, Maine, Connecticut, California and the District of Columbia
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Chapter 11
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Chapter 11 of the U.S. Bankruptcy Code
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CO
2
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Carbon dioxide
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COD
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Commercial operations date
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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, fuel transportation expense, transmission expense, environmental compliance expense and realized settlements from our marketing, hedging and optimization activities including natural gas and fuel oil transactions hedging future power sales, but excludes our mark-to-market activity
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Commodity Margin
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Non-GAAP financial measure that includes power and steam revenues, sales of purchased power and physical natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, environmental compliance expense, and realized settlements from our marketing, hedging, optimization and trading activities, but excludes our mark-to-market activity and other revenues
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Commodity revenue
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The sum of our revenues from power and steam sales, sales of purchased power and physical natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue and realized settlements from our marketing, hedging, optimization and trading activities, but excludes our mark-to-market activity
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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 $1.8 billion aggregate amount revolving credit facility credit agreement, dated as of December 10, 2010, as amended on June 27, 2013, July 30, 2014, February 8, 2016 and December 1, 2016 among Calpine Corporation, the Bank of Tokyo-Mitsubishi UFJ, Ltd., as successor administrative agent, MUFG Union Bank, N.A., as successor collateral agent, the lenders party thereto and the other parties thereto
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CPUC
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California Public Utilities Commission
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CSAPR
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Cross-State Air Pollution Rule
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D.C. Circuit
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U.S. Court of Appeals for the District of Columbia Circuit
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Director Plan
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The Amended and Restated Calpine Corporation 2008 Director Incentive Plan
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Dodd-Frank Act
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The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
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ABBREVIATION
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DEFINITION
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EBITDA
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Net income (loss) attributable to Calpine before net (income) loss attributable to the noncontrolling interest, interest, taxes, depreciation and amortization
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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 Plan
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The Amended and Restated Calpine Corporation 2008 Equity Incentive Plan
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ERCOT
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Electric Reliability Council of Texas
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EWG(s)
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Exempt wholesale generator(s)
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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 2023 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 2017 First Lien Term Loan, the 2019 First Lien Term Loan, the 2020 First Lien Term Loan, the 2023 First Lien Term Loans and the 2024 First Lien Term Loan
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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
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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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Hg
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Mercury
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IPP(s)
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Independent Power Producers
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IPP Peers
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Dynegy Inc. and NRG Energy, Inc.
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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)
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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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ABBREVIATION
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DEFINITION
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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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Market Heat Rate(s)
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The regional power price divided by the corresponding regional natural gas price
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MATS
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Mercury and Air Toxics Standard
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MISO
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Midwest ISO
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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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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 growing retail energy supplier for homes and small businesses primarily concentrated in the Northeast U.S.
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NERC
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North American Electric Reliability Council
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New 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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New 2023 First Lien Term Loan
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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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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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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
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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 of Calpine that owns the Otay Mesa Energy Center, a 608 MW natural gas-fired, combined-cycle power plant located in San Diego county, California
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ABBREVIATION
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DEFINITION
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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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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, 2016, filed with the SEC on February 10, 2017
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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(s)
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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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ABBREVIATION
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DEFINITION
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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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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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TCEQ
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Texas Commission on Environmental Quality
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TRE
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Texas Reliability Entity, Inc.
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TSR
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Total shareholder return
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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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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 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 Loans 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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Competition, including from renewable sources of power, interference by states in competitive power markets through subsidies or similar support for new or existing power plants, and other risks associated with marketing and selling power in the evolving energy markets;
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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 headquarters;
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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;
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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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Focus on disciplined capital allocation.
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1.
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Focus on Being a Premier Operating Company
—
Our objective is to be the “best-in-class” in regards to certain operational performance metrics, such as safety, availability, reliability, efficiency and cost management. We operate and maintain our fleet with the objective of ensuring that our plants remain among the most flexible in the sector and are best positioned to capture value in response to grid needs, especially in light of the continued integration of intermittent renewable resources.
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•
|
During 2016, our employees achieved a total recordable incident rate of 0.55 recordable injuries per 100 employees which places us in the first quartile performance for power generation companies with 1,000 or more employees.
|
•
|
Our entire fleet achieved a forced outage factor of 2.8% and a starting reliability of 97.9% during the year ended December 31, 2016.
|
•
|
During 2016, our outage services subsidiary completed 17 major inspections and eight hot gas path inspections.
|
•
|
For the past 16 years, our Geysers Assets have reliably generated, on average, approximately six million MWh of renewable power per year.
|
2.
|
Focus on Expanding our Customer Sales Channels
—
We continue to focus on getting closer to our customers through expansion of our retail platform which began with the acquisition of Champion Energy in 2015 and was followed by the acquisitions of Calpine Solutions in late 2016 and North American Power in early 2017. Our retail platform geographically and strategically complements our wholesale generation fleet by providing forward liquidity with sufficient margins. The combination of our wholesale origination and retail platforms provides Calpine access to both direct and mass market sales channels. Our direct sales efforts aim to provide our larger customers with customized products, leveraging both our successful wholesale origination efforts and Calpine Solutions’ presence among large commercial and industrial organizations to secure new contracts. Our mass market approach relies upon our expanded Champion Energy retail platform to serve the needs of both residential and smaller commercial and industrial customers across the country. We believe that our retail platform is strategically complete and are now focused on integrating it into our business and optimizing its financial performance. A summary of our more significant customer sales channel efforts and retail growth in 2016 and through the filing of this Report is as follows:
|
•
|
Our ten-year PPA with Southern California Edison for 50 MW of capacity and renewable energy from our Geysers Assets commencing in January 2018 was approved by the CPUC in the second quarter of 2016.
|
•
|
We entered into a new five-year PPA with USS-POSCO Industries to provide 50 MW of energy and steam from our Los Medanos Energy Center commencing in January 2017 which also provides for annual extensions through 2024.
|
•
|
We entered into a new five-year steam agreement, subject to certain conditions precedent, with a wholly-owned subsidiary of The Dow Chemical Company to provide steam from our Texas City Power Plant through 2021.
|
•
|
We entered into a new five-year PPA with a third party to provide 50 MW of capacity from our RockGen Energy Center commencing in June 2017, which increases to 100 MW of capacity commencing in June 2019.
|
•
|
We entered into a new ten-year PPA with the Tennessee Valley Authority to provide 615 MW of energy and capacity from our Morgan Energy Center commencing in February 2016.
|
•
|
In 2016, our retail subsidiaries served approximately 65 million MWh of customer load consisting of approximately 6.5 million annualized residential customer equivalents at December 31, 2016.
|
•
|
During the third quarter of 2016, Champion Energy was ranked highest in customer satisfaction among Texas retail electric providers according to the J.D. Power 2016 Electric Provider Retail Customer Satisfaction Study. This is the sixth time Champion Energy has received the top ranking in the past seven years.
|
•
|
During 2016, Champion Energy expanded its service territory to include commercial and industrial customers in Maine, Connecticut and California.
|
•
|
On December 1, 2016, we completed the purchase of Calpine Solutions, formerly Noble Solutions, along with a swap contract for approximately $800 million plus approximately $350 million of net working capital at closing. We recovered approximately $250 million in cash subsequent to closing and expect to recover an additional approximately $200 million through collateral synergies and the runoff of acquired legacy hedges, substantially within the first year. Calpine Solutions is a commercial and industrial retail electricity provider with customers in 19 states in the U.S., including presence in California, Texas, the Mid-Atlantic and Northeast, where our wholesale power generation fleet is primarily concentrated. The acquisition of this best-in-class direct energy sales platform is consistent with our stated goal of getting closer to our end-use customers and expands our retail customer base, complementing our existing retail business while providing us a valuable sales channel for reaching a much greater portion of the load we seek to serve.
|
•
|
On January 17, 2017, we completed the purchase of North American Power for approximately $105 million, excluding working capital and other adjustments. North American Power is a growing retail energy supplier for homes and small businesses and is primarily concentrated in the Northeast U.S. where Calpine has a substantial power generation presence and where Champion Energy has a substantial retail sales footprint that will be enhanced by the addition of North American Power, which will be integrated into our Champion Energy retail platform.
|
3.
|
Focus on Optimizing our Portfolio
—
Our goal is to take advantage of favorable opportunities to continue to design, develop, acquire, construct and operate the next generation of highly efficient, operationally flexible and environmentally responsible power plants where such investment meets our rigorous financial hurdles, particularly if power contracts and financing are available and attractive returns are expected. Likewise, we actively seek to divest non-core assets where we can find opportunities to do so accretively.
During
2016
and through the filing of this Report, we strategically repositioned our portfolio by adding capacity in our core regions, divesting positions in non-core markets and retiring uneconomic plants through the following transactions:
|
•
|
On February 5, 2016, we completed the purchase of Granite Ridge Energy Center, a power plant with a nameplate capacity of 745 MW (summer peaking capacity of 695 MW), for approximately $500 million, excluding working capital and other adjustments. The addition of this modern, efficient, natural gas-fired, combined-cycle power plant increased capacity in our East segment, specifically the constrained New England market.
|
•
|
On April 1, 2016, we entered into an asset sale agreement for the sale of substantially all of the assets comprising our South Point Energy Center to Nevada Power Company d/b/a NV Energy for approximately $76 million plus the assumption by the purchaser of existing transmission capacity contracts with a future net present value payment obligation of approximately $112 million, approximately $9 million in remaining tribal lease costs and approximately $21 million in near-term repairs, maintenance and capital improvements to restore the power plant to full capacity. The sale is subject to certain conditions precedent, as well as federal and state regulatory approvals. This transaction supports our effort to divest non-core assets outside our strategic concentration. In December 2016, the Nevada Public Utility Commission issued an order rejecting the asset sale agreement. In January 2017, Nevada Power Company filed a motion for reconsideration of this order. In February 2017, the FERC approved Nevada Power Company’s acquisition of the South Point Energy Center. However, on February 8, 2017, the Nevada Public Utility Commission denied Nevada Power Company’s purchase of the South Point Energy Center. Nevada Power Company has the right to appeal this decision. We are also currently assessing our options; however, we do not anticipate that the denial of the sale by the Nevada Public Utility Commission will have a material effect on our financial condition, results of operations or cash flows.
|
•
|
During the third quarter of 2016, we filed with ERCOT to retire our 400 MW Clear Lake Power Plant. ERCOT subsequently approved our plan to discontinue operations. Built in 1985, Clear Lake utilizes an older technology. Due to growing maintenance costs and lack of adequate compensation in Texas, we retired the power plant on February 1, 2017. The book value associated with our Clear Lake Power Plant is immaterial.
|
•
|
On October 26, 2016, we completed the sale of our Mankato Power Plant, a 375 MW natural gas-fired, combined-cycle power plant and 345 MW expansion project under advanced development located in Minnesota, to Southern Power Company, a subsidiary of Southern Company, for $396 million, excluding working capital and other adjustments. This transaction supports our effort to divest non-core assets outside our strategic concentration.
|
•
|
On January 3, 2017, we completed the sale of our Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million, excluding working capital and other adjustments. This transaction supports our effort to divest non-core assets outside our strategic concentration.
|
•
|
York 2 Energy Center —
York 2 Energy Center is an 828 MW dual-fuel, combined-cycle project that is co-located with our York Energy Center in Peach Bottom Township, Pennsylvania. Once complete, the power plant will feature two combustion turbines, two heat recovery steam generators and one steam turbine. The project is under construction and the initial 760 MW of capacity cleared PJM’s last three base residual auctions with the 68 MW of incremental capacity clearing the last two base residual auctions. Due to construction delays, we are now targeting COD in late 2017.
|
•
|
Guadalupe Peaking Energy Center —
In April 2015, we executed an agreement with Guadalupe Valley Electric Cooperative (“GVEC”) related to the construction of a 418 MW natural gas-fired peaking power plant to be co-located with our Guadalupe Energy Center. Under the terms of the agreement, construction of the Guadalupe Peaking Energy Center (“GPEC”) may commence at our discretion, so long as the power plant reaches COD by June 1, 2019. When the power plant begins commercial operation, GVEC will purchase a 50% ownership interest in GPEC. Once built, GPEC will feature two fast-ramping combustion turbines capable of responding to peaks in power
|
4.
|
Focus on Advocacy and Corporate Responsibility
—
We recognize that our business is heavily influenced by laws, regulations and rules at federal, state and local levels as well as by rules of the ISOs and RTOs that oversee the competitive markets in which we operate. We believe that being active participants in the legislative, regulatory and rulemaking processes may yield better outcomes for all stakeholders, including Calpine. Our three basic areas of focus are competitive wholesale power markets, competitive retail power markets and environmental stewardship in power generation. Below are some recent examples of our advocacy efforts:
|
•
|
Successfully advocated for the PUCT to evaluate the performance of the Operating Reserve Demand Curve, and to pursue improvements as necessary. The PUCT received several rounds of comments from Calpine and other market participants, and we are currently awaiting a decision from the agency.
|
•
|
Worked individually and with trade groups to remove language in the proposed federal energy bill that would have resulted in rules that could potentially undermine the PJM and ISO-NE capacity markets.
|
•
|
Participated with a coalition of generators and others opposed to the sole source PPAs between regulated utilities and their unregulated generation affiliates in Ohio. In response to this opposition, the FERC decided that the contracts were not exempt from their
Edgar Standard
review regarding affiliate power sales restrictions and directed both utilities to submit the PPAs for review and approval prior to transacting under the contracts. As a result, both of the regulated utilities dropped their efforts.
|
•
|
Worked with other generators to stop legislation in Connecticut that would have provided out-of-market subsidies to the Millstone nuclear power plant. We expect this legislation to be reintroduced this year and will continue to oppose.
|
5.
|
Focus on Disciplined Capital Allocation
—
We seek to enhance shareholder value through optimizing our portfolio, prudently managing our balance sheet and returning capital to shareholders. We continue our disciplined approach to capital allocation, benchmarking each decision against the opportunity to repurchase shares of our own common stock. In the current environment, we believe that paying down debt and strengthening our balance sheet is a high return investment for our shareholders. We further optimized our capital structure by refinancing, redeeming or amending several of our debt instruments during the year ended December 31, 2016:
|
•
|
On February 8, 2016, we amended our Corporate Revolving Facility, extending the maturity by two years to June 27, 2020, and increasing the capacity by an additional $178 million to $1,678 million through June 27, 2018, reverting back to $1,520 million through the maturity date. Further, we increased the letter of credit sublimit by $250 million to $1.0 billion and extended the maturity by two years to June 27, 2020.
|
•
|
In May 2016, we repaid our 2019 and 2020 First Lien Term Loans with the proceeds from our New 2023 First Lien Term Loan and 2026 First Lien Notes which extended the maturity on approximately $1.2 billion of corporate debt.
|
•
|
On December 1, 2016, we amended our Corporate Revolving Facility to increase the aggregate revolving loan commitments available thereunder by approximately $112 million to $1,790 million for the full term through the maturity date of June 27, 2020.
|
•
|
In December 2016, we used cash on hand to redeem $120 million of our 2023 First Lien Notes, plus accrued and unpaid interest.
|
•
|
In December 2016, we repriced our 2023 First Lien Term Loans by lowering the margin over LIBOR by 0.25% to 2.75% and extended the maturity of our 2024 First Lien Term Loan from May 2022 to January 2024.
|
•
|
As part of our stated goal to reduce debt and interest expense, on February 3, 2017, we issued a notice of redemption to repay the remaining $453 million of our outstanding 2023 First Lien Notes using cash on hand along with the proceeds from the New 2019 First Lien Term Loan which contains a substantially lower variable rate of LIBOR plus 1.75% per annum. We intend to repay the New 2019 First Lien Term Loan in full by the end of 2018. This accelerates debt reduction and achieves substantial annual interest savings of more than $20 million.
|
•
|
First, we are a provider of power to utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities and other governmental entities, power marketers as well as retail commercial, industrial, governmental and residential customers. We continue to focus on getting closer to our customers through expansion of our retail platform which began with the acquisition of Champion Energy in 2015 and was followed by the acquisitions of Calpine Solutions in late 2016 and North American Power in early 2017. Our power sales occur in several different product categories including baseload (around the clock generation), intermediate (generation typically more expensive than baseload and utilized during higher demand periods to meet shifting demand needs), and peaking energy (most expensive variable cost and utilized during the highest demand periods), for which the latter is provided by some of our stand-alone peaking power plants/units and from our combined-cycle power plants by using technologies such as steam injection or duct firing additional burners in the heat recovery steam generators. Many of our units have operated more frequently as baseload units at times when low natural gas prices have driven their production costs below those of some competing coal-fired units. We also sell “full requirements” electricity for wholesale and retail customers, whereby we utilize our power plants as well as market purchases to serve the total electricity demand of the customer even as it varies across time.
|
•
|
Second, we provide capacity for sale to utilities, independent electric system operators and retail power providers. In various markets, retail power providers (or independent electric system operators on their behalf) are required to demonstrate adequate resources to meet their power sales commitments. To meet this obligation, they procure a market product known as capacity from power plant owners or resellers. Most electricity market administrators have acknowledged that an energy only market does not provide sufficient revenues to enable existing merchant generators to recover all of their costs or to encourage the construction of new power plants. Capacity auctions have been implemented in the Northeast, Mid-Atlantic and certain Midwest regional markets to address this issue. California has a bilateral capacity program. Texas does not presently have a capacity market or a requirement for retailers to ensure adequate resources.
|
•
|
Third, we sell RECs from our Geysers Assets in northern California. California has an RPS that requires load serving entities to have RECs for a certain percentage of their demand for the purpose of guaranteeing a certain level of renewable generation in the state or in neighboring areas. Because geothermal is a renewable source of energy, we receive a REC for each MWh we produce and are able to sell our RECs to load serving entities. We also purchase RECs from other sources for resale to our customers.
|
•
|
Fourth, our cogeneration power plants produce steam, in addition to electricity, for sale to industrial customers for use in their manufacturing processes or heating, ventilation and air conditioning operations.
|
•
|
Fifth, we provide ancillary service products to wholesale power markets. These products include the right for the purchaser to call on our generation to provide flexibility to the market and support operation of the electric grid. For example, we are sometimes paid to reserve a portion of capacity at some of our power plants that could be deployed quickly should there be an unexpected increase in load or to assure reliability due to fluctuations in the supply of power from variable renewable resources such as wind and solar generation. These ramping characteristics are becoming increasingly necessary in markets where intermittent renewables have large penetrations.
|
(1)
|
Data source is NERC weather-normalized estimates for 2016 published in May 2016.
|
•
|
Economic pressures continue to increase for coal-fired power generation as natural gas prices remain low and state and federal agencies enact environmental regulations to reduce air emissions of certain pollutants such as SO
2
, NO
X
, GHG, Hg and acid gases, restrict the use of once-through cooling, and provide for stricter standards for managing coal combustion residuals. Depending on how the new presidential administration approaches existing and proposed rules, older, less efficient fossil-fuel power plants that emit much higher amounts of GHG, SO
2
, NO
X
, Hg and acid gases, which operate nationwide, but more prominently in the eastern U.S., may need to install expensive air pollution controls or reduce or discontinue operations. Any retirements or curtailments could enhance our growth opportunities through greater utilization of our existing power plants and development of new power plants. The estimated capacity for fossil-fueled plants older than 50 years and the total estimated capacity for fossil-fueled plants by NERC region are as follows:
|
|
|
Generating Capacity Older Than 50 years
|
|
Total Generating Capacity
|
||||
West:
|
|
|
|
|
|
|
||
WECC
|
|
9,212
|
|
MW
|
|
132,279
|
|
MW
|
Texas:
|
|
|
|
|
|
|
||
TRE
|
|
4,225
|
|
MW
|
|
87,047
|
|
MW
|
East:
|
|
|
|
|
|
|
||
NPCC
|
|
8,503
|
|
MW
|
|
56,471
|
|
MW
|
MRO
|
|
4,428
|
|
MW
|
|
45,008
|
|
MW
|
RFC
|
|
20,408
|
|
MW
|
|
185,251
|
|
MW
|
SERC
|
|
24,796
|
|
MW
|
|
224,903
|
|
MW
|
FRCC
|
|
844
|
|
MW
|
|
60,818
|
|
MW
|
Total
|
|
72,416
|
|
MW
|
|
791,777
|
|
MW
|
•
|
An increase in power generated from renewable sources could lead to an increased need for flexible power that many of our power plants provide to protect the reliability of the grid and earn premium compensation for that flexibility;
|
•
|
One small but growing source of competing renewable generation in some of our regional markets (primarily California) is customer-sited (primarily rooftop) solar generation. Levelized costs for solar installation have fallen significantly over the past several years, aided by federal tax subsidies and other local incentives, and are now in some regions lower than customer retail electric rates. To the extent on-site solar generation is compensated at the full retail rate (an increasingly controversial policy known as “net energy metering”), rooftop solar installations may continue to grow. Should net energy metered solar installations remain at relatively low levels of penetration or net energy metering policies be weakened (by rate structure reforms that charge customers fixed amounts regardless of the level of electricity consumed, thus lowering the variable portion of the rates), rooftop solar growth might diminish. Absent incentives and supportive policies, rooftop solar is currently generally not competitive with wholesale power.
|
•
|
The regulators in our core markets remain committed to the competitive wholesale power model, particularly in ERCOT, PJM and ISO-NE where they continue to focus on market design and rules to assure the long-term viability of competition and the benefits to customers that justify competition. However, certain states have taken or are considering subsidizing or otherwise providing economic support to existing, uneconomic power plants such as nuclear power plants. These efforts, if successful, could reduce the number of nuclear unit retirements that would result from currently low market prices.
|
•
|
Utilities are increasingly focused on demand side management – managing the level and timing of power usage through load curtailment, dispatching generators located at commercial or industrial sites, and “smart grid” technologies that may improve the efficiencies, dispatch usage and reliability of electric grids. Performance standards for demand side resources have been made more stringent recently as system operators evaluate their reliability (especially at high levels of penetration) and environmental authorities deal with the implications of relying on smaller, less environmentally efficient generation sources during periods of peak demand when air quality is already challenged.
|
•
|
Environmental permitting requirements for new power plants, transmission lines and pipelines continue to increase in stringency and complexity, resulting in prolonged, expensive development cycles and high capital investments.
|
•
|
provide affordable, reliable services to our customers;
|
•
|
maintain excellence in operations;
|
•
|
achieve and maintain a lower cost of production, primarily by maintaining unit availability, efficiency and production cost management;
|
•
|
effectively utilize our sales channels to reach our customers;
|
•
|
accurately assess and effectively manage our risks; and
|
•
|
accomplish all of the above with an environmental effect that is lower than the competition and further decreasing over time.
|
Geographic Diversity
|
Dispatch Technology
|
|
|
|
•
|
26% related to leases with the federal government via the Office of Natural Resources Revenue,
|
•
|
30% related to leases with the California State Lands Commission and
|
•
|
44% related to leases with private landowners/leaseholders.
|
SEGMENT / Power Plant
|
|
NERC
Region
|
|
U.S. State or
Canadian
Province
|
|
Technology
|
|
Calpine
Interest
Percentage
|
|
Calpine Net
Interest
Baseload
(MW)
(1)(3)
|
|
Calpine Net
Interest
With Peaking
(MW)
(2)(3)
|
|
2016
Total MWh
Generated
(4)
|
||||
WEST
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Geothermal
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
McCabe #5 & #6
|
|
WECC
|
|
CA
|
|
Renewable
|
|
100
|
%
|
|
84
|
|
|
84
|
|
|
696,123
|
|
Ridge Line #7 & #8
|
|
WECC
|
|
CA
|
|
Renewable
|
|
100
|
%
|
|
76
|
|
|
76
|
|
|
659,244
|
|
Calistoga
|
|
WECC
|
|
CA
|
|
Renewable
|
|
100
|
%
|
|
69
|
|
|
69
|
|
|
557,650
|
|
Eagle Rock
|
|
WECC
|
|
CA
|
|
Renewable
|
|
100
|
%
|
|
68
|
|
|
68
|
|
|
585,585
|
|
Big Geysers
|
|
WECC
|
|
CA
|
|
Renewable
|
|
100
|
%
|
|
61
|
|
|
61
|
|
|
603,910
|
|
Lake View
|
|
WECC
|
|
CA
|
|
Renewable
|
|
100
|
%
|
|
54
|
|
|
54
|
|
|
502,494
|
|
Quicksilver
|
|
WECC
|
|
CA
|
|
Renewable
|
|
100
|
%
|
|
53
|
|
|
53
|
|
|
254,294
|
|
Sonoma
|
|
WECC
|
|
CA
|
|
Renewable
|
|
100
|
%
|
|
53
|
|
|
53
|
|
|
242,481
|
|
Cobb Creek
|
|
WECC
|
|
CA
|
|
Renewable
|
|
100
|
%
|
|
51
|
|
|
51
|
|
|
439,944
|
|
Socrates
|
|
WECC
|
|
CA
|
|
Renewable
|
|
100
|
%
|
|
50
|
|
|
50
|
|
|
240,569
|
|
Sulphur Springs
|
|
WECC
|
|
CA
|
|
Renewable
|
|
100
|
%
|
|
47
|
|
|
47
|
|
|
487,859
|
|
Grant
|
|
WECC
|
|
CA
|
|
Renewable
|
|
100
|
%
|
|
41
|
|
|
41
|
|
|
158,948
|
|
Aidlin
|
|
WECC
|
|
CA
|
|
Renewable
|
|
100
|
%
|
|
18
|
|
|
18
|
|
|
125,287
|
|
Natural Gas-Fired
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Delta Energy Center
|
|
WECC
|
|
CA
|
|
Combined Cycle
|
|
100
|
%
|
|
835
|
|
|
857
|
|
|
3,434,343
|
|
Pastoria Energy Center
|
|
WECC
|
|
CA
|
|
Combined Cycle
|
|
100
|
%
|
|
770
|
|
|
749
|
|
|
4,366,356
|
|
Hermiston Power Project
|
|
WECC
|
|
OR
|
|
Combined Cycle
|
|
100
|
%
|
|
566
|
|
|
635
|
|
|
3,179,622
|
|
Otay Mesa Energy Center
|
|
WECC
|
|
CA
|
|
Combined Cycle
|
|
100
|
%
|
|
513
|
|
|
608
|
|
|
2,668,269
|
|
Metcalf Energy Center
|
|
WECC
|
|
CA
|
|
Combined Cycle
|
|
100
|
%
|
|
564
|
|
|
605
|
|
|
2,709,083
|
|
Sutter Energy Center
(5)
|
|
WECC
|
|
CA
|
|
Combined Cycle
|
|
100
|
%
|
|
542
|
|
|
578
|
|
|
—
|
|
Los Medanos Energy Center
|
|
WECC
|
|
CA
|
|
Cogen
|
|
100
|
%
|
|
518
|
|
|
572
|
|
|
2,889,852
|
|
South Point Energy Center
(6)
|
|
WECC
|
|
AZ
|
|
Combined Cycle
|
|
100
|
%
|
|
520
|
|
|
530
|
|
|
—
|
|
Russell City Energy Center
|
|
WECC
|
|
CA
|
|
Combined Cycle
|
|
75
|
%
|
|
429
|
|
|
464
|
|
|
585,552
|
|
Los Esteros Critical Energy Facility
|
|
WECC
|
|
CA
|
|
Combined Cycle
|
|
100
|
%
|
|
243
|
|
|
309
|
|
|
153,482
|
|
Gilroy Energy Center
|
|
WECC
|
|
CA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
141
|
|
|
18,167
|
|
Gilroy Cogeneration Plant
|
|
WECC
|
|
CA
|
|
Cogen
|
|
100
|
%
|
|
109
|
|
|
130
|
|
|
141,394
|
|
King City Cogeneration Plant
|
|
WECC
|
|
CA
|
|
Cogen
|
|
100
|
%
|
|
120
|
|
|
120
|
|
|
416,343
|
|
Wolfskill Energy Center
|
|
WECC
|
|
CA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
48
|
|
|
16,429
|
|
Yuba City Energy Center
|
|
WECC
|
|
CA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
47
|
|
|
30,535
|
|
Feather River Energy Center
|
|
WECC
|
|
CA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
47
|
|
|
26,088
|
|
Creed Energy Center
|
|
WECC
|
|
CA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
47
|
|
|
8,502
|
|
Lambie Energy Center
|
|
WECC
|
|
CA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
47
|
|
|
9,299
|
|
Goose Haven Energy Center
|
|
WECC
|
|
CA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
47
|
|
|
8,742
|
|
Riverview Energy Center
|
|
WECC
|
|
CA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
47
|
|
|
18,119
|
|
King City Peaking Energy Center
|
|
WECC
|
|
CA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
44
|
|
|
4,391
|
|
Agnews Power Plant
|
|
WECC
|
|
CA
|
|
Combined Cycle
|
|
100
|
%
|
|
28
|
|
|
28
|
|
|
16,924
|
|
Subtotal
|
|
|
|
|
|
|
|
|
|
6,482
|
|
|
7,425
|
|
|
26,255,880
|
|
SEGMENT / Power Plant
|
|
NERC
Region
|
|
U.S. State or
Canadian
Province
|
|
Technology
|
|
Calpine
Interest
Percentage
|
|
Calpine Net
Interest
Baseload
(MW)
(1)(3)
|
|
Calpine Net
Interest
With Peaking
(MW)
(2)(3)
|
|
2016
Total MWh
Generated
(4)
|
||||
TEXAS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Deer Park Energy Center
|
|
TRE
|
|
TX
|
|
Cogen
|
|
100
|
%
|
|
1,103
|
|
|
1,204
|
|
|
6,697,711
|
|
Guadalupe Energy Center
|
|
TRE
|
|
TX
|
|
Combined Cycle
|
|
100
|
%
|
|
1,009
|
|
|
1,000
|
|
|
5,277,381
|
|
Baytown Energy Center
|
|
TRE
|
|
TX
|
|
Cogen
|
|
100
|
%
|
|
782
|
|
|
842
|
|
|
4,563,333
|
|
Channel Energy Center
|
|
TRE
|
|
TX
|
|
Cogen
|
|
100
|
%
|
|
723
|
|
|
808
|
|
|
4,264,358
|
|
Pasadena Power Plant
(7)
|
|
TRE
|
|
TX
|
|
Cogen/Combined Cycle
|
|
100
|
%
|
|
763
|
|
|
781
|
|
|
4,865,887
|
|
Bosque Energy Center
|
|
TRE
|
|
TX
|
|
Combined Cycle
|
|
100
|
%
|
|
740
|
|
|
762
|
|
|
4,586,639
|
|
Freestone Energy Center
|
|
TRE
|
|
TX
|
|
Combined Cycle
|
|
75
|
%
|
|
779
|
|
|
746
|
|
|
4,466,975
|
|
Magic Valley Generating Station
|
|
TRE
|
|
TX
|
|
Combined Cycle
|
|
100
|
%
|
|
682
|
|
|
712
|
|
|
3,198,311
|
|
Brazos Valley Power Plant
|
|
TRE
|
|
TX
|
|
Combined Cycle
|
|
100
|
%
|
|
523
|
|
|
609
|
|
|
2,858,695
|
|
Corpus Christi Energy Center
|
|
TRE
|
|
TX
|
|
Cogen
|
|
100
|
%
|
|
426
|
|
|
500
|
|
|
2,478,834
|
|
Texas City Power Plant
|
|
TRE
|
|
TX
|
|
Cogen
|
|
100
|
%
|
|
400
|
|
|
453
|
|
|
875,156
|
|
Hidalgo Energy Center
|
|
TRE
|
|
TX
|
|
Combined Cycle
|
|
78.5
|
%
|
|
392
|
|
|
374
|
|
|
2,168,654
|
|
Freeport Energy Center
(8)
|
|
TRE
|
|
TX
|
|
Cogen
|
|
100
|
%
|
|
210
|
|
|
236
|
|
|
1,230,677
|
|
Subtotal
|
|
|
|
|
|
|
|
|
|
8,532
|
|
|
9,027
|
|
|
47,532,611
|
|
|
EAST
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Bethlehem Energy Center
|
|
RFC
|
|
PA
|
|
Combined Cycle
|
|
100
|
%
|
|
1,062
|
|
|
1,130
|
|
|
5,343,008
|
|
Hay Road Energy Center
|
|
RFC
|
|
DE
|
|
Combined Cycle
|
|
100
|
%
|
|
1,039
|
|
|
1,130
|
|
|
3,858,419
|
|
Morgan Energy Center
|
|
SERC
|
|
AL
|
|
Cogen
|
|
100
|
%
|
|
720
|
|
|
807
|
|
|
4,154,885
|
|
Fore River Energy Center
|
|
NPCC
|
|
MA
|
|
Combined Cycle
|
|
100
|
%
|
|
750
|
|
|
731
|
|
|
3,840,808
|
|
Edge Moor Energy Center
|
|
RFC
|
|
DE
|
|
Steam Cycle
|
|
100
|
%
|
|
—
|
|
|
725
|
|
|
869,844
|
|
Granite Ridge Energy Center
|
|
NPCC
|
|
NH
|
|
Combined Cycle
|
|
100
|
%
|
|
745
|
|
|
695
|
|
|
3,221,204
|
|
York Energy Center
|
|
RFC
|
|
PA
|
|
Combined Cycle
|
|
100
|
%
|
|
519
|
|
|
565
|
|
|
1,552,415
|
|
Westbrook Energy Center
|
|
NPCC
|
|
ME
|
|
Combined Cycle
|
|
100
|
%
|
|
552
|
|
|
552
|
|
|
2,183,066
|
|
Greenfield Energy Centre
(9)
|
|
NPCC
|
|
ON
|
|
Combined Cycle
|
|
50
|
%
|
|
422
|
|
|
519
|
|
|
873,687
|
|
RockGen Energy Center
|
|
MRO
|
|
WI
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
503
|
|
|
394,661
|
|
Zion Energy Center
|
|
RFC
|
|
IL
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
503
|
|
|
435,494
|
|
Garrison Energy Center
|
|
RFC
|
|
DE
|
|
Combined Cycle
|
|
100
|
%
|
|
273
|
|
|
309
|
|
|
1,565,129
|
|
Pine Bluff Energy Center
|
|
SERC
|
|
AR
|
|
Cogen
|
|
100
|
%
|
|
184
|
|
|
215
|
|
|
1,205,874
|
|
Cumberland Energy Center
|
|
RFC
|
|
NJ
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
191
|
|
|
115,967
|
|
Kennedy International Airport Power Plant
|
|
NPCC
|
|
NY
|
|
Cogen
|
|
100
|
%
|
|
110
|
|
|
121
|
|
|
686,542
|
|
Auburndale Peaking Energy Center
|
|
FRCC
|
|
FL
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
117
|
|
|
22,004
|
|
Sherman Avenue Energy Center
|
|
RFC
|
|
NJ
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
92
|
|
|
48,823
|
|
Bethpage Energy Center 3
|
|
NPCC
|
|
NY
|
|
Combined Cycle
|
|
100
|
%
|
|
60
|
|
|
80
|
|
|
284,539
|
|
Carll
’
s Corner Energy Center
|
|
RFC
|
|
NJ
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
73
|
|
|
19,265
|
|
Mickleton Energy Center
|
|
RFC
|
|
NJ
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
67
|
|
|
6,102
|
|
Bethpage Power Plant
|
|
NPCC
|
|
NY
|
|
Combined Cycle
|
|
100
|
%
|
|
55
|
|
|
56
|
|
|
299,586
|
|
Christiana Energy Center
|
|
RFC
|
|
DE
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
53
|
|
|
103
|
|
Bethpage Peaker
|
|
NPCC
|
|
NY
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
48
|
|
|
202,980
|
|
Stony Brook Power Plant
|
|
NPCC
|
|
NY
|
|
Cogen
|
|
100
|
%
|
|
45
|
|
|
47
|
|
|
285,091
|
|
Tasley Energy Center
|
|
RFC
|
|
VA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
33
|
|
|
1,575
|
|
Whitby Cogeneration
(10)
|
|
NPCC
|
|
ON
|
|
Cogen
|
|
50
|
%
|
|
25
|
|
|
25
|
|
|
198,526
|
|
Delaware City Energy Center
|
|
RFC
|
|
DE
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
23
|
|
|
57
|
|
West Energy Center
|
|
RFC
|
|
DE
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
20
|
|
|
352
|
|
SEGMENT / Power Plant
|
|
NERC
Region
|
|
U.S. State or
Canadian
Province
|
|
Technology
|
|
Calpine
Interest
Percentage
|
|
Calpine Net
Interest
Baseload
(MW)
(1)(3)
|
|
Calpine Net
Interest
With Peaking
(MW)
(2)(3)
|
|
2016
Total MWh
Generated
(4)
|
||||
Bayview Energy Center
|
|
RFC
|
|
VA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
12
|
|
|
3,933
|
|
Crisfield Energy Center
|
|
RFC
|
|
MD
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
10
|
|
|
1,467
|
|
Vineland Solar Energy Center
|
|
RFC
|
|
NJ
|
|
Renewable
|
|
100
|
%
|
|
—
|
|
|
4
|
|
|
5,666
|
|
Subtotal
|
|
|
|
|
|
|
|
|
|
6,561
|
|
|
9,456
|
|
|
31,681,072
|
|
|
Total operating power plants
|
|
79
|
|
|
|
|
|
|
|
21,575
|
|
|
25,908
|
|
|
105,469,563
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Power plants sold or retired during 2016 and early 2017
|
|
|
|
|
|
|
|
|
|
|
||||||||
Mankato Power Plant
|
|
MRO
|
|
MN
|
|
Combined Cycle
|
|
100%
|
|
|
n/a
|
|
|
n/a
|
|
|
799,611
|
|
Osprey Energy Center
|
|
FRCC
|
|
FL
|
|
Combined Cycle
|
|
100%
|
|
|
n/a
|
|
|
n/a
|
|
|
2,953,901
|
|
Clear Lake Power Plant
|
|
TRE
|
|
TX
|
|
Cogen
|
|
100%
|
|
|
n/a
|
|
|
n/a
|
|
|
343,900
|
|
Subtotal
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,097,412
|
|
|||
Total operating, sold and retired power plants
|
|
|
|
|
|
|
|
|
|
|
|
|
|
109,566,975
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Projects Under Construction and Advanced Development
|
||||||||||||||||||
Projects Under Construction
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
York 2 Energy Center
|
|
RFC
|
|
PA
|
|
Combined Cycle
|
|
100
|
%
|
|
736
|
|
|
828
|
|
|
n/a
|
|
Projects Under Advanced Development
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Guadalupe Peaking Energy Center
(11)
|
|
TRE
|
|
TX
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
418
|
|
|
n/a
|
|
Total operating power plants and projects
|
|
|
|
|
|
|
|
|
|
22,311
|
|
|
27,154
|
|
|
|
(1)
|
Natural gas-fired fleet capacities are generally derived on as-built as-designed outputs, including upgrades, based on site specific annual average temperatures and average process steam flows for cogeneration power plants, as applicable. Geothermal capacities are derived from historical generation output and steam reservoir modeling under average ambient conditions (temperatures and rainfall).
|
(2)
|
Natural gas-fired fleet peaking capacities are primarily derived on as-built as-designed peaking outputs based on site specific average summer temperatures and include power enhancement features such as heat recovery steam generator duct-firing, gas turbine power augmentation, and/or other power augmentation features. For certain power plants with definitive contracts, capacities at contract conditions have been included. Oil-fired capacities reflect capacity test results.
|
(3)
|
These outputs do not factor in the typical MW loss and recovery profiles over time, which natural gas-fired turbine power plants display associated with their planned major maintenance schedules.
|
(4)
|
MWh generation is shown here as our net operating interest.
|
(5)
|
We suspended operations at our Sutter Energy Center to assess the future of the facility.
|
(6)
|
We have entered into an agreement to sell South Point Energy Center. South Point Unit 2 experienced a combustion turbine outage in the Fall of 2015 and we are currently evaluating the timing of repairs in light of the impending sale. Further, the balance of the facility is not currently operating, however, it can be operated at our discretion based on market conditions.
|
(7)
|
Pasadena is comprised of 260 MW of cogen technology and 521 MW of combined cycle (non-cogen) technology.
|
(8)
|
Freeport Energy Center is owned by Calpine; however, it is contracted and operated by The Dow Chemical Company.
|
(9)
|
Calpine holds a 50% partnership interest in Greenfield LP through its subsidiaries; however, it is operated by a third party.
|
(10)
|
Calpine holds a 50% partnership interest in Whitby Cogeneration through its subsidiaries; however, it is operated by Atlantic Packaging Products Ltd.
|
(11)
|
In accordance with a power purchase agreement, a third party will purchase a 50% ownership interest in this power plant upon achieving commercial operation.
|
|
|
Air Pollutant Emission Rates —
Pounds of Pollutant Emitted
Per MWh of Power Generated
|
||||
Air Pollutants
|
|
Average U.S. Coal-, Oil-,
and Natural Gas-Fired
Power Plant
(1)
|
|
Calpine
Natural Gas-Fired,
Combined-Cycle
Power Plant
(2)
|
|
Advantage Compared to
Average U.S. Coal-, Oil-,
and Natural Gas-Fired
Power Plant
|
Nitrogen Oxides, NOx
|
|
1.49
|
|
0.121
|
|
91.9%
|
Acid rain, smog and fine particulate formation
|
|
|
|
|
|
|
Sulfur Dioxide, SO
2
|
|
2.08
|
|
0.0052
|
|
99.8%
|
Acid rain and fine particulate formation
|
|
|
|
|
|
|
Mercury Compounds
(3)
|
|
0.00002
|
|
—
|
|
100%
|
Neurotoxin
|
|
|
|
|
|
|
Carbon Dioxide, CO
2
|
|
1,657
|
|
860
|
|
48.1%
|
Principal GHG — contributor to climate change
|
|
|
|
|
|
|
(1)
|
The average U.S. coal-, oil- and natural gas-fired power plants’ emission rates were obtained from the U.S. Department of Energy’s Electric Power Annual Report for 2015. Emission rates are based on 2015 emissions and net generation. The U.S. Department of Energy has not yet released 2016 information.
|
(2)
|
Our natural gas-fired, combined-cycle power plant estimated emission rates are based on our 2015 emissions and power generation data from our natural gas-fired, combined-cycle power plants (excluding combined heat power plants) as measured under the EPA reporting requirements.
|
(3)
|
The U.S. coal-, oil- and natural gas-fired power plant air emissions of mercury compounds were obtained from the EPA Toxics Release Inventory for 2014. Emission rates are based on 2015 emissions and net generation from U.S. Department of Energy’s Electric Power Annual Report for 2015.
|
•
|
We receive and inject an average of approximately
14 million gallons
of reclaimed water per day into the geothermal steam reservoir at The Geysers where the water is naturally heated by the Earth, creating additional steam to fuel our Geysers Assets. Approximately
12 million gallons
per day are received from the Santa Rosa Geysers Recharge Project, which we developed jointly with the City of Santa Rosa, and we receive, on average, approximately
two million gallons
a day from The Lake County Recharge Project from Lake County.
|
•
|
In our combined-cycle power plants, we use mechanical draft cooling towers, which use up to 90% less water than conventional once-through cooling systems.
|
•
|
Three of our power plants (Sutter Energy Center, Otay Mesa Energy Center and Fore River Energy Center) employ air cooled condensers for cooling, consuming virtually no water for cooling.
|
•
|
In 12 of our operating natural gas-fired power plants equipped with cooling towers, we reuse treated water from municipal treatment systems for cooling. By reusing water in these cooling towers, we avoid the usage of as much as 38 million gallons per day of valuable surface and/or groundwater for cooling.
|
Item 1A.
|
Risk Factors
|
•
|
increases and decreases in generation capacity in our markets, including the addition of new supplies of power as a result of the development of new power plants, expansion of existing power plants or additional transmission capacity;
|
•
|
changes in power transmission or fuel transportation capacity constraints or inefficiencies;
|
•
|
power supply disruptions, including power plant outages and transmission disruptions;
|
•
|
weather conditions, particularly unusually mild summers or warm winters in our market areas;
|
•
|
quarterly and seasonal fluctuations;
|
•
|
an economic downturn which could negatively affect demand for power;
|
•
|
changes in the supply of commodities, including but not limited to coal, natural gas and fuel oil;
|
•
|
changes in the demand for power or in patterns of power usage, including the potential development of demand-side management tools and practices;
|
•
|
development of new fuels or new technologies for the production or storage of power;
|
•
|
federal and state regulations and actions of the ISOs;
|
•
|
federal and state power, market and environmental regulation and legislation, including mandating an RPS or creating financial incentives, each resulting in new renewable energy generation capacity creating oversupply;
|
•
|
changes in prices related to RECs and other environmental allowance products; and
|
•
|
changes in capacity prices and capacity markets.
|
•
|
rate caps, price limitations and bidding rules imposed by ISOs, RTOs and other market regulators that may impair our ability to recover our costs and limit our return on our capital investments;
|
•
|
regulations promulgated by the FERC and the CFTC;
|
•
|
sufficient liquidity in the forward commodity markets to conduct our hedging activities;
|
•
|
some of our competitors (mainly utilities) receive entitlement-guaranteed rates of return on their capital investments, with returns that exceed market returns and may affect our ability to sell our power at economical rates;
|
•
|
structure and operating characteristics of our capacity markets such as our PJM capacity auctions and our NYISO markets; and
|
•
|
regulations and market rules related to our RECs.
|
•
|
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 or to repurchase equity issued by certain of our subsidiaries to third parties; and
|
•
|
limiting our ability to enter into marketing, hedging and optimization activities by reducing the number of counterparties with whom we can transact as well as the volume and type of those transactions.
|
•
|
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
|
|
High
|
|
Low
|
||||
2016
|
|
|
|
||||
First Quarter
|
$
|
16.49
|
|
|
$
|
11.53
|
|
Second Quarter
|
16.07
|
|
|
13.22
|
|
||
Third Quarter
|
15.12
|
|
|
11.97
|
|
||
Fourth Quarter
|
13.22
|
|
|
10.39
|
|
||
2015
|
|
|
|
||||
First Quarter
|
$
|
22.89
|
|
|
$
|
20.16
|
|
Second Quarter
|
23.51
|
|
|
17.66
|
|
||
Third Quarter
|
19.73
|
|
|
14.09
|
|
||
Fourth Quarter
|
16.60
|
|
|
11.75
|
|
Period
|
|
(a)
Total Number of
Shares Purchased
(1)
|
|
(b)
Average Price
Paid Per Share
|
|
(c)
Total Number of
Shares Purchased
as Part of
Publicly Announced
Plans or Programs
(2)
|
|
(d)
Maximum Dollar Value of Shares That May
Yet Be Purchased
Under the Plans or
Programs (in millions)
|
||||||
October
|
|
1,837
|
|
|
$
|
12.09
|
|
|
—
|
|
|
$
|
307
|
|
November
|
|
6,281
|
|
|
$
|
11.48
|
|
|
—
|
|
|
$
|
307
|
|
December
|
|
27,290
|
|
|
$
|
11.40
|
|
|
—
|
|
|
$
|
307
|
|
Total
|
|
35,408
|
|
|
$
|
11.45
|
|
|
—
|
|
|
$
|
307
|
|
(1)
|
To satisfy tax withholding obligations associated with the vesting of restricted stock awarded to employees during the fourth quarter of
2016
, we withheld a total of 35,408 shares that are included in the total number of shares purchased.
|
(2)
|
In November 2014, our Board of Directors authorized an increase in the total authorization of our multi-year share repurchase program to $1.0 billion. There is no expiration date on the repurchase authorization and the amount and timing of future share repurchases, if any, will be determined as market and business conditions warrant.
|
Company / Index
|
|
December 31,
2011 |
|
December 31,
2012 |
|
December 31,
2013 |
|
December 31,
2014 |
|
December 31,
2015 |
|
December 31,
2016
|
||||||||||||
Calpine Corporation
|
|
$
|
100.00
|
|
|
$
|
111.02
|
|
|
$
|
119.47
|
|
|
$
|
135.52
|
|
|
$
|
88.61
|
|
|
$
|
69.99
|
|
S&P 500 Index
|
|
100.00
|
|
|
115.99
|
|
|
153.55
|
|
|
174.57
|
|
|
176.98
|
|
|
198.15
|
|
||||||
S&P Utilities Index
|
|
100.00
|
|
|
101.28
|
|
|
114.66
|
|
|
147.89
|
|
|
140.72
|
|
|
163.64
|
|
|
Years Ended December 31,
|
||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
|
(in millions, except per share amounts)
|
||||||||||||||||||
Statement of Operations data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating revenues
|
$
|
6,716
|
|
|
$
|
6,472
|
|
|
$
|
8,030
|
|
|
$
|
6,301
|
|
|
$
|
5,478
|
|
Net income attributable to Calpine
|
$
|
92
|
|
|
$
|
235
|
|
|
$
|
946
|
|
|
$
|
14
|
|
|
$
|
199
|
|
Basic earnings per common share:
|
|
|
|
|
|
|
|
|
|
||||||||||
Net income per common share attributable to Calpine
|
$
|
0.26
|
|
|
$
|
0.65
|
|
|
$
|
2.34
|
|
|
$
|
0.03
|
|
|
$
|
0.43
|
|
Diluted earnings per common share:
|
|
|
|
|
|
|
|
|
|
||||||||||
Net income per common share attributable to Calpine
|
$
|
0.26
|
|
|
$
|
0.64
|
|
|
$
|
2.31
|
|
|
$
|
0.03
|
|
|
$
|
0.42
|
|
Balance Sheet data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Total assets
(1)
|
$
|
19,317
|
|
|
$
|
18,681
|
|
|
$
|
18,228
|
|
|
$
|
16,402
|
|
|
$
|
16,394
|
|
Short-term debt and capital lease obligations
(1)
|
$
|
748
|
|
|
$
|
221
|
|
|
$
|
199
|
|
|
$
|
204
|
|
|
$
|
115
|
|
Long-term debt and capital lease obligations
(1)
|
$
|
11,431
|
|
|
$
|
11,716
|
|
|
$
|
10,933
|
|
|
$
|
10,751
|
|
|
$
|
10,480
|
|
(1)
|
We retrospectively adopted Accounting Standards Update 2015-03 in the first quarter of 2016. As a result, we reclassified our debt issuance costs from other assets to debt, net of current portion on our Consolidated Balance Sheets. See Note 2 of the Notes to Consolidated Financial Statements for further information related to our adoption of Accounting Standards Update 2015-03.
|
Item 7.
|
Management’s Discussion and Analysis of Financial Condition and Results of Operation
s
|
|
2016
|
|
2015
|
|
Change
|
|
% Change
|
|||||||
Operating revenues:
|
|
|
|
|
|
|
|
|||||||
Commodity revenue
|
$
|
6,943
|
|
|
$
|
6,389
|
|
|
$
|
554
|
|
|
9
|
|
Mark-to-market gain (loss)
|
(245
|
)
|
|
65
|
|
|
(310
|
)
|
|
#
|
|
|||
Other revenue
|
18
|
|
|
18
|
|
|
—
|
|
|
—
|
|
|||
Operating revenues
|
6,716
|
|
|
6,472
|
|
|
244
|
|
|
4
|
|
|||
Operating expenses:
|
|
|
|
|
|
|
|
|||||||
Fuel and purchased energy expense:
|
|
|
|
|
|
|
|
|||||||
Commodity expense
|
4,431
|
|
|
3,589
|
|
|
(842
|
)
|
|
(23
|
)
|
|||
Mark-to-market (gain) loss
|
(244
|
)
|
|
178
|
|
|
422
|
|
|
#
|
|
|||
Fuel and purchased energy expense
|
4,187
|
|
|
3,767
|
|
|
(420
|
)
|
|
(11
|
)
|
|||
Plant operating expense
|
977
|
|
|
1,018
|
|
|
41
|
|
|
4
|
|
|||
Depreciation and amortization expense
|
662
|
|
|
638
|
|
|
(24
|
)
|
|
(4
|
)
|
|||
Sales, general and other administrative expense
|
140
|
|
|
138
|
|
|
(2
|
)
|
|
(1
|
)
|
|||
Other operating expenses
|
79
|
|
|
80
|
|
|
1
|
|
|
1
|
|
|||
Total operating expenses
|
6,045
|
|
|
5,641
|
|
|
(404
|
)
|
|
(7
|
)
|
|||
Impairment losses
|
13
|
|
|
—
|
|
|
(13
|
)
|
|
#
|
|
|||
(Gain) on sale of assets, net
|
(157
|
)
|
|
—
|
|
|
157
|
|
|
#
|
|
|||
(Income) from unconsolidated subsidiaries
|
(24
|
)
|
|
(24
|
)
|
|
—
|
|
|
—
|
|
|||
Income from operations
|
839
|
|
|
855
|
|
|
(16
|
)
|
|
(2
|
)
|
|||
Interest expense
|
631
|
|
|
628
|
|
|
(3
|
)
|
|
—
|
|
|||
Debt modification and extinguishment costs
|
25
|
|
|
40
|
|
|
15
|
|
|
38
|
|
|||
Other (income) expense, net
|
24
|
|
|
14
|
|
|
(10
|
)
|
|
(71
|
)
|
|||
Income before income taxes
|
159
|
|
|
173
|
|
|
(14
|
)
|
|
(8
|
)
|
|||
Income tax expense (benefit)
|
48
|
|
|
(76
|
)
|
|
(124
|
)
|
|
#
|
|
|||
Net income
|
111
|
|
|
249
|
|
|
(138
|
)
|
|
(55
|
)
|
|||
Net income attributable to the noncontrolling interest
|
(19
|
)
|
|
(14
|
)
|
|
(5
|
)
|
|
(36
|
)
|
|||
Net income attributable to Calpine
|
$
|
92
|
|
|
$
|
235
|
|
|
$
|
(143
|
)
|
|
(61
|
)
|
|
2016
|
|
2015
|
|
Change
|
|
% Change
|
||||
Operating Performance Metrics:
|
|
|
|
|
|
|
|
||||
MWh generated (in thousands)
(1)(2)
|
107,264
|
|
|
112,150
|
|
|
(4,886
|
)
|
|
(4
|
)
|
Average availability
(2)
|
90.5
|
%
|
|
89.2
|
%
|
|
1.3
|
%
|
|
1
|
|
Average total MW in operation
(1)
|
26,368
|
|
|
25,785
|
|
|
583
|
|
|
2
|
|
Average capacity factor, excluding peakers
|
51.2
|
%
|
|
55.6
|
%
|
|
(4.4
|
)%
|
|
(8
|
)
|
Steam Adjusted Heat Rate
(2)
|
7,324
|
|
|
7,306
|
|
|
(18
|
)
|
|
—
|
|
#
|
Variance of 100% or greater
|
(1)
|
Represents generation and capacity from power plants that we both consolidate and operate. See “— Description of Our Power Plants – Table of Operating Power Plants and Projects Under Construction and Advanced Development” for our total equity generation and capacities.
|
(2)
|
Generation, average availability and Steam Adjusted Heat Rate exclude power plants and units that are inactive.
|
(in millions)
|
|
|
||
$
|
(215
|
)
|
|
Lower energy margins due to decreased contribution from wholesale hedges, lower realized Spark Spreads in our Texas and West segments and the expiration of the Pastoria Energy Center PPA. These factors were partially offset by increased contribution from our retail hedging activity and the positive effect of a new PPA associated with our Morgan Energy Center in the East segment
(1)
|
(44
|
)
|
|
Lower regulatory capacity revenue primarily in the East and West segments at our power plants which were fully operational period-over-period
(1)
|
|
40
|
|
|
A natural gas pipeline transportation billing credit received in the West segment
(1)
|
|
37
|
|
|
The net year-over-year effect of our portfolio management activities, including the acquisition of our 695 MW Granite Ridge Energy Center on February 5, 2016 and the commencement of commercial operations at our 309 MW Garrison Energy Center in June 2015 partially offset by the sale of our 375 MW Mankato Power Plant in October 2016 and the expiration of the operating lease related to the Greenleaf power plants in June 2015
(1)
|
|
(106
|
)
|
|
Contract amortization, lease levelization related to tolling contracts and other
(2)
|
|
$
|
(288
|
)
|
|
|
(1)
|
These items comprise the year-over-year change in our Commodity Margin which is a non-GAAP financial measure. See “Commodity Margin and Adjusted EBITDA” for a description of our Non-GAAP financial measures and a discussion of the year-over-year change in Commodity Margin by segment.
|
(2)
|
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.
|
|
2015
|
|
2014
|
|
Change
|
|
% Change
|
|||||||
Operating revenues:
|
|
|
|
|
|
|
|
|||||||
Commodity revenue
|
$
|
6,389
|
|
|
$
|
7,595
|
|
|
$
|
(1,206
|
)
|
|
(16
|
)
|
Mark-to-market gain (loss)
|
65
|
|
|
419
|
|
|
(354
|
)
|
|
(84
|
)
|
|||
Other revenue
|
18
|
|
|
16
|
|
|
2
|
|
|
13
|
|
|||
Operating revenues
|
6,472
|
|
|
8,030
|
|
|
(1,558
|
)
|
|
(19
|
)
|
|||
Operating expenses:
|
|
|
|
|
|
|
|
|||||||
Fuel and purchased energy expense:
|
|
|
|
|
|
|
|
|||||||
Commodity expense
|
3,589
|
|
|
4,815
|
|
|
1,226
|
|
|
25
|
|
|||
Mark-to-market (gain) loss
|
178
|
|
|
77
|
|
|
(101
|
)
|
|
#
|
|
|||
Fuel and purchased energy expense
|
3,767
|
|
|
4,892
|
|
|
1,125
|
|
|
23
|
|
|||
Plant operating expense
|
1,018
|
|
|
969
|
|
|
(49
|
)
|
|
(5
|
)
|
|||
Depreciation and amortization expense
|
638
|
|
|
603
|
|
|
(35
|
)
|
|
(6
|
)
|
|||
Sales, general and other administrative expense
|
138
|
|
|
144
|
|
|
6
|
|
|
4
|
|
|||
Other operating expenses
|
80
|
|
|
88
|
|
|
8
|
|
|
9
|
|
|||
Total operating expenses
|
5,641
|
|
|
6,696
|
|
|
1,055
|
|
|
16
|
|
|||
Impairment losses
|
—
|
|
|
123
|
|
|
123
|
|
|
#
|
|
|||
(Gain) on sale of assets, net
|
—
|
|
|
(753
|
)
|
|
(753
|
)
|
|
#
|
|
|||
(Income) from unconsolidated subsidiaries
|
(24
|
)
|
|
(25
|
)
|
|
(1
|
)
|
|
(4
|
)
|
|||
Income from operations
|
855
|
|
|
1,989
|
|
|
(1,134
|
)
|
|
(57
|
)
|
|||
Interest expense
|
628
|
|
|
645
|
|
|
17
|
|
|
3
|
|
|||
Debt extinguishment costs
|
40
|
|
|
346
|
|
|
306
|
|
|
88
|
|
|||
Other (income) expense, net
|
14
|
|
|
15
|
|
|
1
|
|
|
7
|
|
|||
Income before income taxes
|
173
|
|
|
983
|
|
|
(810
|
)
|
|
(82
|
)
|
|||
Income tax expense (benefit)
|
(76
|
)
|
|
22
|
|
|
98
|
|
|
#
|
|
|||
Net income
|
249
|
|
|
961
|
|
|
(712
|
)
|
|
(74
|
)
|
|||
Net income attributable to the noncontrolling interest
|
(14
|
)
|
|
(15
|
)
|
|
1
|
|
|
7
|
|
|||
Net income attributable to Calpine
|
$
|
235
|
|
|
$
|
946
|
|
|
$
|
(711
|
)
|
|
(75
|
)
|
|
2015
|
|
2014
|
|
Change
|
|
% Change
|
||||
Operating Performance Metrics:
|
|
|
|
|
|
|
|
||||
MWh generated (in thousands)
(1)(2)
|
112,150
|
|
|
100,617
|
|
|
11,533
|
|
|
11
|
|
Average availability
(2)
|
89.2
|
%
|
|
90.7
|
%
|
|
(1.5
|
)%
|
|
(2
|
)
|
Average total MW in operation
(1)
|
25,785
|
|
|
26,652
|
|
|
(867
|
)
|
|
(3
|
)
|
Average capacity factor, excluding peakers
|
55.6
|
%
|
|
48.4
|
%
|
|
7.2
|
%
|
|
15
|
|
Steam Adjusted Heat Rate
(2)
|
7,306
|
|
|
7,384
|
|
|
78
|
|
|
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 Construction and Advanced Development” for our total equity generation and capacities.
|
(2)
|
Generation, average availability and Steam Adjusted Heat Rate exclude power plants and units that are inactive.
|
(1)
|
These items comprise the year-over-year change in our Commodity Margin which is a non-GAAP financial measure. See “Commodity Margin and Adjusted EBITDA” for a description of our Non-GAAP financial measures and a discussion of the year-over-year change in Commodity Margin by segment.
|
(2)
|
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:
|
2016
|
|
2015
|
|
Change
|
|
% Change
|
|||||||
Commodity Margin (in millions)
|
$
|
991
|
|
|
$
|
1,106
|
|
|
$
|
(115
|
)
|
|
(10
|
)
|
Commodity Margin per MWh generated
|
$
|
37.74
|
|
|
$
|
31.75
|
|
|
$
|
5.99
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|||||||
MWh generated (in thousands)
|
26,256
|
|
|
34,836
|
|
|
(8,580
|
)
|
|
(25
|
)
|
|||
Average availability
|
92.0
|
%
|
|
89.2
|
%
|
|
2.8
|
%
|
|
3
|
|
|||
Average total MW in operation
|
7,425
|
|
|
7,475
|
|
|
(50
|
)
|
|
(1
|
)
|
|||
Average capacity factor, excluding peakers
|
43.2
|
%
|
|
56.8
|
%
|
|
(13.6
|
)%
|
|
(24
|
)
|
|||
Steam Adjusted Heat Rate
|
7,277
|
|
|
7,320
|
|
|
43
|
|
|
1
|
|
Texas:
|
2016
|
|
2015
|
|
Change
|
|
% Change
|
|||||||
Commodity Margin (in millions)
|
$
|
655
|
|
|
$
|
736
|
|
|
$
|
(81
|
)
|
|
(11
|
)
|
Commodity Margin per MWh generated
|
$
|
14.04
|
|
|
$
|
15.37
|
|
|
$
|
(1.33
|
)
|
|
(9
|
)
|
|
|
|
|
|
|
|
|
|||||||
MWh generated (in thousands)
|
46,646
|
|
|
47,873
|
|
|
(1,227
|
)
|
|
(3
|
)
|
|||
Average availability
|
90.3
|
%
|
|
89.4
|
%
|
|
0.9
|
%
|
|
1
|
|
|||
Average total MW in operation
|
9,191
|
|
|
9,191
|
|
|
—
|
|
|
—
|
|
|||
Average capacity factor, excluding peakers
|
57.8
|
%
|
|
59.5
|
%
|
|
(1.7
|
)%
|
|
(3
|
)
|
|||
Steam Adjusted Heat Rate
|
7,143
|
|
|
7,089
|
|
|
(54
|
)
|
|
(1
|
)
|
East:
|
2016
|
|
2015
|
|
Change
|
|
% Change
|
|||||||
Commodity Margin (in millions)
|
$
|
958
|
|
|
$
|
944
|
|
|
$
|
14
|
|
|
1
|
|
Commodity Margin per MWh generated
|
$
|
27.88
|
|
|
$
|
32.06
|
|
|
$
|
(4.18
|
)
|
|
(13
|
)
|
|
|
|
|
|
|
|
|
|||||||
MWh generated (in thousands)
|
34,362
|
|
|
29,441
|
|
|
4,921
|
|
|
17
|
|
|||
Average availability
|
89.7
|
%
|
|
89.0
|
%
|
|
0.7
|
%
|
|
1
|
|
|||
Average total MW in operation
|
9,752
|
|
|
9,119
|
|
|
633
|
|
|
7
|
|
|||
Average capacity factor, excluding peakers
|
50.4
|
%
|
|
48.8
|
%
|
|
1.6
|
%
|
|
3
|
|
|||
Steam Adjusted Heat Rate
|
7,617
|
|
|
7,663
|
|
|
46
|
|
|
1
|
|
West:
|
2015
|
|
2014
|
|
Change
|
|
% Change
|
|||||||
Commodity Margin (in millions)
|
$
|
1,106
|
|
|
$
|
1,050
|
|
|
$
|
56
|
|
|
5
|
|
Commodity Margin per MWh generated
|
$
|
31.75
|
|
|
$
|
30.71
|
|
|
$
|
1.04
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|||||||
MWh generated (in thousands)
|
34,836
|
|
|
34,195
|
|
|
641
|
|
|
2
|
|
|||
Average availability
|
89.2
|
%
|
|
92.9
|
%
|
|
(3.7
|
)%
|
|
(4
|
)
|
|||
Average total MW in operation
|
7,475
|
|
|
7,524
|
|
|
(49
|
)
|
|
(1
|
)
|
|||
Average capacity factor, excluding peakers
|
56.8
|
%
|
|
55.4
|
%
|
|
1.4
|
%
|
|
3
|
|
|||
Steam Adjusted Heat Rate
|
7,320
|
|
|
7,314
|
|
|
(6
|
)
|
|
—
|
|
Texas:
|
2015
|
|
2014
|
|
Change
|
|
% Change
|
|||||||
Commodity Margin (in millions)
|
$
|
736
|
|
|
$
|
760
|
|
|
$
|
(24
|
)
|
|
(3
|
)
|
Commodity Margin per MWh generated
|
$
|
15.37
|
|
|
$
|
19.65
|
|
|
$
|
(4.28
|
)
|
|
(22
|
)
|
|
|
|
|
|
|
|
|
|||||||
MWh generated (in thousands)
|
47,873
|
|
|
38,678
|
|
|
9,195
|
|
|
24
|
|
|||
Average availability
|
89.4
|
%
|
|
90.5
|
%
|
|
(1.1
|
)%
|
|
(1
|
)
|
|||
Average total MW in operation
|
9,191
|
|
|
8,856
|
|
|
335
|
|
|
4
|
|
|||
Average capacity factor, excluding peakers
|
59.5
|
%
|
|
49.9
|
%
|
|
9.6
|
%
|
|
19
|
|
|||
Steam Adjusted Heat Rate
|
7,089
|
|
|
7,203
|
|
|
114
|
|
|
2
|
|
East:
|
2015
|
|
2014
|
|
Change
|
|
% Change
|
|||||||
Commodity Margin (in millions)
|
$
|
944
|
|
|
$
|
949
|
|
|
$
|
(5
|
)
|
|
(1
|
)
|
Commodity Margin per MWh generated
|
$
|
32.06
|
|
|
$
|
34.21
|
|
|
$
|
(2.15
|
)
|
|
(6
|
)
|
|
|
|
|
|
|
|
|
|||||||
MWh generated (in thousands)
|
29,441
|
|
|
27,744
|
|
|
1,697
|
|
|
6
|
|
|||
Average availability
|
89.0
|
%
|
|
89.2
|
%
|
|
(0.2
|
)%
|
|
—
|
|
|||
Average total MW in operation
|
9,119
|
|
|
10,272
|
|
|
(1,153
|
)
|
|
(11
|
)
|
|||
Average capacity factor, excluding peakers
|
48.8
|
%
|
|
40.0
|
%
|
|
8.8
|
%
|
|
22
|
|
|||
Steam Adjusted Heat Rate
|
7,663
|
|
|
7,721
|
|
|
58
|
|
|
1
|
|
|
2016
|
||||||||||||||||||
|
West
|
|
Texas
|
|
East
|
|
Consolidation
and
Elimination
|
|
Total
|
||||||||||
Net income attributable to Calpine
|
|
|
|
|
|
|
|
|
$
|
92
|
|
||||||||
Net income attributable to the noncontrolling interest
|
|
|
|
|
|
|
|
|
19
|
|
|||||||||
Income tax expense
|
|
|
|
|
|
|
|
|
48
|
|
|||||||||
Debt modification and extinguishment costs and other (income) expense, net
|
|
|
|
|
|
|
|
|
49
|
|
|||||||||
Interest expense
|
|
|
|
|
|
|
|
|
631
|
|
|||||||||
Income from operations
|
$
|
322
|
|
|
$
|
37
|
|
|
$
|
480
|
|
|
$
|
—
|
|
|
$
|
839
|
|
Add:
|
|
|
|
|
|
|
|
|
|
||||||||||
Adjustments to reconcile income from operations to Adjusted EBITDA:
|
|
|
|
|
|
|
|
|
|
||||||||||
Depreciation and amortization expense, excluding debt issuance costs
(1)
|
219
|
|
|
213
|
|
|
224
|
|
|
—
|
|
|
656
|
|
|||||
Major maintenance expense
|
70
|
|
|
88
|
|
|
93
|
|
|
—
|
|
|
251
|
|
|||||
Operating lease expense
|
—
|
|
|
—
|
|
|
26
|
|
|
—
|
|
|
26
|
|
|||||
Mark-to-market (gain) loss on commodity derivative activity
|
38
|
|
|
(22
|
)
|
|
(15
|
)
|
|
—
|
|
|
1
|
|
|||||
Impairment losses
|
13
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
13
|
|
|||||
(Gain) on sale of assets, net
|
—
|
|
|
—
|
|
|
(157
|
)
|
|
—
|
|
|
(157
|
)
|
|||||
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest
(2)
|
(27
|
)
|
|
—
|
|
|
36
|
|
|
—
|
|
|
9
|
|
|||||
Stock-based compensation expense
|
11
|
|
|
11
|
|
|
9
|
|
|
—
|
|
|
31
|
|
|||||
Loss (gain) on dispositions of assets
|
3
|
|
|
5
|
|
|
(5
|
)
|
|
—
|
|
|
3
|
|
|||||
Contract amortization
|
4
|
|
|
74
|
|
|
44
|
|
|
—
|
|
|
122
|
|
|||||
Other
|
16
|
|
|
3
|
|
|
2
|
|
|
—
|
|
|
21
|
|
|||||
Total Adjusted EBITDA
|
$
|
669
|
|
|
$
|
409
|
|
|
$
|
737
|
|
|
$
|
—
|
|
|
$
|
1,815
|
|
|
2015
|
||||||||||||||||||
|
West
|
|
Texas
|
|
East
|
|
Consolidation
and
Elimination
|
|
Total
|
||||||||||
Net income attributable to Calpine
|
|
|
|
|
|
|
|
|
$
|
235
|
|
||||||||
Net income attributable to the noncontrolling interest
|
|
|
|
|
|
|
|
|
14
|
|
|||||||||
Income tax benefit
|
|
|
|
|
|
|
|
|
(76
|
)
|
|||||||||
Debt modification and extinguishment costs and other (income) expense, net
|
|
|
|
|
|
|
|
|
54
|
|
|||||||||
Interest expense
|
|
|
|
|
|
|
|
|
628
|
|
|||||||||
Income from operations
|
$
|
528
|
|
|
$
|
2
|
|
|
$
|
324
|
|
|
$
|
1
|
|
|
$
|
855
|
|
Add:
|
|
|
|
|
|
|
|
|
|
||||||||||
Adjustments to reconcile income from operations to Adjusted EBITDA:
|
|
|
|
|
|
|
|
|
|
||||||||||
Depreciation and amortization expense, excluding debt issuance costs
(1)
|
244
|
|
|
204
|
|
|
184
|
|
|
—
|
|
|
632
|
|
|||||
Major maintenance expense
|
86
|
|
|
103
|
|
|
79
|
|
|
—
|
|
|
268
|
|
|||||
Operating lease expense
|
4
|
|
|
—
|
|
|
26
|
|
|
—
|
|
|
30
|
|
|||||
Mark-to-market (gain) loss on commodity derivative activity
|
(121
|
)
|
|
147
|
|
|
87
|
|
|
—
|
|
|
113
|
|
|||||
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest
(2)
|
(24
|
)
|
|
—
|
|
|
34
|
|
|
—
|
|
|
10
|
|
|||||
Stock-based compensation expense
|
10
|
|
|
10
|
|
|
6
|
|
|
—
|
|
|
26
|
|
|||||
Loss on dispositions of assets
|
3
|
|
|
9
|
|
|
4
|
|
|
—
|
|
|
16
|
|
|||||
Contract amortization
|
—
|
|
|
4
|
|
|
16
|
|
|
—
|
|
|
20
|
|
|||||
Other
|
5
|
|
|
2
|
|
|
—
|
|
|
(1
|
)
|
|
6
|
|
|||||
Total Adjusted EBITDA
|
$
|
735
|
|
|
$
|
481
|
|
|
$
|
760
|
|
|
$
|
—
|
|
|
$
|
1,976
|
|
|
2014
|
||||||||||||||||||
|
West
|
|
Texas
|
|
East
(3)
|
|
Consolidation
and
Elimination
|
|
Total
|
||||||||||
Net income attributable to Calpine
|
|
|
|
|
|
|
|
|
$
|
946
|
|
||||||||
Net income attributable to the noncontrolling interest
|
|
|
|
|
|
|
|
|
15
|
|
|||||||||
Income tax expense
|
|
|
|
|
|
|
|
|
22
|
|
|||||||||
Debt extinguishment costs and other (income) expense, net
|
|
|
|
|
|
|
|
|
361
|
|
|||||||||
Interest expense
|
|
|
|
|
|
|
|
|
645
|
|
|||||||||
Income from operations
|
$
|
549
|
|
|
$
|
329
|
|
|
$
|
1,111
|
|
|
$
|
—
|
|
|
$
|
1,989
|
|
Add:
|
|
|
|
|
|
|
|
|
|
||||||||||
Adjustments to reconcile income from operations to Adjusted EBITDA:
|
|
|
|
|
|
|
|
|
|
||||||||||
Depreciation and amortization expense, excluding debt issuance costs
(1)
|
240
|
|
|
191
|
|
|
167
|
|
|
—
|
|
|
598
|
|
|||||
Major maintenance expense
|
64
|
|
|
91
|
|
|
79
|
|
|
—
|
|
|
234
|
|
|||||
Operating lease expense
|
8
|
|
|
—
|
|
|
26
|
|
|
—
|
|
|
34
|
|
|||||
Mark-to-market gain on commodity derivative activity
|
(172
|
)
|
|
(114
|
)
|
|
(56
|
)
|
|
—
|
|
|
(342
|
)
|
|||||
Impairment losses
|
—
|
|
|
—
|
|
|
123
|
|
|
—
|
|
|
123
|
|
|||||
(Gain) on sale of assets, net
|
—
|
|
|
—
|
|
|
(753
|
)
|
|
—
|
|
|
(753
|
)
|
|||||
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest
(2)
|
(24
|
)
|
|
—
|
|
|
29
|
|
|
—
|
|
|
5
|
|
|||||
Stock-based compensation expense
|
12
|
|
|
14
|
|
|
10
|
|
|
—
|
|
|
36
|
|
|||||
Loss on dispositions of assets
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|||||
Contract amortization
|
—
|
|
|
—
|
|
|
14
|
|
|
—
|
|
|
14
|
|
|||||
Other
|
—
|
|
|
3
|
|
|
7
|
|
|
—
|
|
|
10
|
|
|||||
Total Adjusted EBITDA
|
$
|
678
|
|
|
$
|
514
|
|
|
$
|
757
|
|
|
$
|
—
|
|
|
$
|
1,949
|
|
(1)
|
Excludes depreciation and amortization expense attributable to the noncontrolling interest.
|
(2)
|
Adjustments to reflect Adjusted EBITDA from unconsolidated investments include (gain) loss on mark-to-market activity of nil for each of the years ended
December 31, 2016
,
2015
and
2014
, respectively.
|
(3)
|
Our East segment includes Adjusted EBITDA of $43 million for the year ended December 31, 2014 related to the six power plants in our East segment that were sold in July 2014.
|
|
2016
|
|
2015
|
||||
Cash and cash equivalents, corporate
(1)
|
$
|
345
|
|
|
$
|
850
|
|
Cash and cash equivalents, non-corporate
|
73
|
|
|
56
|
|
||
Total cash and cash equivalents
|
418
|
|
|
906
|
|
||
Restricted cash
|
188
|
|
|
228
|
|
||
Corporate Revolving Facility availability
(2)
|
1,255
|
|
|
1,184
|
|
||
CDHI letter of credit facility availability
|
50
|
|
|
59
|
|
||
Total current liquidity availability
(3)
|
$
|
1,911
|
|
|
$
|
2,377
|
|
(1)
|
Includes $16 million and $35 million of margin deposits posted with us by our counterparties at
December 31, 2016
and
2015
, respectively. See Note 9 of the Notes to Consolidated Financial Statements for further information related to our collateral. On January 3, 2017, we received $162 million in cash proceeds from the sale of Osprey Energy Center. See Note 3 of the Notes to Consolidated Financial Statements for further information related to our sale of Osprey Energy Center.
|
(2)
|
Our ability to use availability under our Corporate Revolving Facility is unrestricted. On February 8, 2016, we amended our Corporate Revolving Facility, extending the maturity by two years to June 27, 2020, and increasing the capacity by an additional $178 million to $1,678 million through June 27, 2018, reverting back to $1,520 million through the maturity date. Further, we increased the letter of credit sublimit by $250 million to $1.0 billion and extended the maturity by two years to June 27, 2020. On December 1, 2016, we amended our Corporate Revolving Facility, increasing the capacity by
$112 million
to
$1,790 million
for the full term through June 27, 2020.
|
(3)
|
Our ability to use corporate cash and cash equivalents is unrestricted. See Note 2 of the Notes to Consolidated Financial Statements for a description of the restrictions on our use of non-corporate cash and cash equivalents and restricted cash. Our $300 million CDHI letter of credit facility is restricted to support certain obligations under PPAs and power transmission and natural gas transportation agreements.
|
•
|
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.
|
|
2016
|
|
2015
|
||||
Corporate Revolving Facility
(1)
|
$
|
535
|
|
|
$
|
316
|
|
CDHI
|
250
|
|
|
241
|
|
||
Various project financing facilities
|
206
|
|
|
198
|
|
||
Total
|
$
|
991
|
|
|
$
|
755
|
|
(1)
|
The Corporate Revolving Facility represents our primary revolving facility.
|
|
2017
|
||
Major maintenance expense
|
$
|
315
|
|
Maintenance capital expenditures
|
120
|
|
|
Growth related capital expenditures
|
220
|
|
|
Total major maintenance expense and capital spending
|
$
|
655
|
|
|
2016
|
|
2015
|
|
2014
|
||||||
Beginning cash and cash equivalents
|
$
|
906
|
|
|
$
|
717
|
|
|
$
|
941
|
|
Net cash provided by (used in):
|
|
|
|
|
|
||||||
Operating activities
|
1,030
|
|
|
876
|
|
|
870
|
|
|||
Investing activities
|
(1,919
|
)
|
|
(841
|
)
|
|
(84
|
)
|
|||
Financing activities
|
401
|
|
|
154
|
|
|
(1,010
|
)
|
|||
Net (decrease) increase in cash and cash equivalents
|
(488
|
)
|
|
189
|
|
|
(224
|
)
|
|||
Ending cash and cash equivalents
|
$
|
418
|
|
|
$
|
906
|
|
|
$
|
717
|
|
•
|
Income from operations —
Income from operations, adjusted for non-cash items, decreased by $136 million for the year ended December 31, 2016, compared to the same period in 2015. Non-cash items consist primarily of depreciation
|
•
|
Working capital employed
—
Working capital employed decreased by $202 million for the year ended December 31, 2016, compared to the same period in 2015, after adjusting for changes in debt, restricted cash and mark-to-market related balances which did not affect cash provided by operating activities. The decrease was primarily due to the recovery of cash margin posted by Calpine Solutions through position netting and letter of credit conversion opportunities.
|
•
|
Interest paid
—
Cash paid for interest decreased by $36 million to $584 million for the year ended December 31, 2016, from $620 million for the year ended December 31, 2015. The decrease was primarily due to our refinancing activities and timing of interest payments.
|
•
|
Debt modification & extinguishment payments
—
During the year ended December 31, 2016, we made cash payments of $5 million related to the repurchase penalties for a portion of the 2023 First Lien Notes and the refinancing and upsizing of Steamboat project debt as compared to $34 million during the year ended December 31, 2015, associated with the repurchase penalties for a portion of the 2023 First Lien Notes and debt modification costs related to the issuance of the 2024 First Lien Term Loan.
|
•
|
Purchase of Calpine Solutions and Champion Energy —
During the year ended December 31, 2016, we purchased the retail electric provider Calpine Solutions, formerly Noble Solutions, for $1.15 billion compared to the purchase of Champion Energy for $296 million during the year ended December 31, 2015.
|
•
|
Purchase of Granite Ridge Energy Center —
During the year ended December 31, 2016, we purchased a natural gas-fired combined-cycle power plant located in Londonderry, New Hampshire for $526 million. There were no similar acquisitions during the year ended December 31, 2015.
|
•
|
Proceeds from the sale of Mankato Power Plant —
During the year ended December 31, 2016, we received net proceeds after the pay-down of Steamboat project debt of approximately $164 million for the sale of Mankato Power Plant. There were no power plants sold during the year ended December 31, 2015.
|
•
|
Capital expenditures —
Capital expenditures for the year ended December 31, 2016, were $489 million, a decrease of $76 million, compared to expenditures of $565 million for the year ended December 31, 2015. The decrease was primarily due to lower expenditures on construction projects and outages.
|
•
|
First Lien Term Loans, First Lien Notes and Senior Unsecured Notes —
During the year ended December 31, 2016, we received proceeds of $545 million from the issuance of the 2017 First Lien Term Loan used to partially fund the purchase of Calpine Solutions and redeemed $120 million of the 2023 First Lien Notes. In addition, we utilized proceeds from the issuance of the New 2023 First Lien Term Loan and the 2026 First Lien Notes to repay the 2019 and 2020 First Lien Term Loans of $1.2 billion. During the year ended December 31, 2015, we received proceeds of $650 million from the issuance of the 2024 Senior Unsecured Notes, proceeds of $545 million from the issuance of 2023 First Lien Term Loan used to fund the purchase of Granite Ridge Energy Center and repurchased $267 million of the 2023 First Lien Notes. In addition, we utilized proceeds from the issuance of the 2024 First Lien Term Loan to repay the 2018 First Lien Term Loan of $1.6 billion.
|
•
|
Stock repurchases —
During the year ended December 31, 2016, we repurchased an immaterial amount of common stock as compared to $529 million paid to repurchase our common stock during the year ended December 31, 2015.
|
•
|
Project financing, notes payable and other
—
During the year ended December 31, 2016, we refinanced and upsized Steamboat project debt following the sale of Mankato Power Plant. The refinancing resulted in net proceeds received of $20 million after the noncash pay-down of the debt in the amount of $243 million in conjunction with the sale of Mankato and proceeds received from the upsizing and refinancing in the amount of $263 million. There were no similar activities during the year ended December 31, 2015.
|
•
|
Income from operations —
Income from operations, adjusted for non-cash items, increased by $59 million for the year ended December 31, 2015, compared to the year ended December 31, 2014. Non-cash items consist primarily of depreciation and amortization, income from unconsolidated subsidiaries, impairment losses, gain on sale of assets, net and mark-to-market activity. The increase in income from operations was primarily driven by a $94 million increase in Commodity revenue, net of Commodity expense, excluding non-cash amortization of purchased intangible assets, partially offset by a $49 million increase in plant operating expense for the year ended December 31, 2015 compared to the year ended December 31, 2014. See “Results of Operations for the Years Ended December 31, 2015 and 2014” above for further discussion of these changes.
|
•
|
Working capital employed
—
Working capital employed increased by $331 million for the year ended December 31, 2015, compared to the year ended December 31, 2014, 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 the change in net margining requirements for the year ended December 31, 2015, compared to the year ended December 31, 2014.
|
•
|
Debt modification and extinguishment payments
—
Cash paid for debt modification and extinguishment decreased $276 million to $34 million during the year ended December 31, 2015, from $310 million for the year ended December 31, 2014. During the year ended December 31, 2015, we made cash payments of $13 million related to issuance costs associated with our 2024 First Lien Term Loan and cash payments of $21 million related to the repayment of a portion of our 2023 First Lien Notes, as compared to $310 million during the year ended December 31, 2014, which was associated with the repayment of our 2019 First Lien Notes, 2020 First Lien Notes and 2021 First Lien Notes and a portion of our 2023 First Lien Notes.
|
•
|
Proceeds from the sale of power plants and other
—
During the year ended December 31, 2014, we received proceeds of approximately $1.57 billion related to the completion of the sale of six power plants in our East segment. There was no similar activity during the year ended December 31, 2015.
|
•
|
Purchase of Champion Energy, Fore River and Guadalupe Energy Centers —
During the year ended December 31, 2015, we purchased the retail electric provider Champion Energy for $296 million compared to the purchase of two natural gas-fired, combined-cycle power plants located in North Weymouth, Massachusetts and Guadalupe County, Texas for $541 million and $656 million, respectively, during the year ended December 31, 2014.
|
•
|
Capital expenditures —
Capital expenditures for the year ended December 31, 2015, were $565 million, an increase of $73 million, compared to expenditures of $492 million for the year ended December 31, 2014. The increase was primarily due to higher expenditures on construction projects and outages during the year ended December 31, 2015, as compared to the year ended December 31, 2014.
|
•
|
First Lien Term Loans —
During the year ended December 31, 2015, we received proceeds of approximately $1.6 billion from the issuance of the 2024 First Lien Term Loan which was used to repay the 2018 First Lien Term Loan of $1.6 billion. In addition, we received proceeds of approximately $545 million from the issuance of the 2023 First Lien Term Loan which is intended to be used, together with operating cash on hand, to fund the acquisition of Granite
|
•
|
CCFC refinancing
—
During the year ended December 31, 2014, we received proceeds of $420 million under the CCFC Term Loans, which were used to fund a portion of the purchase price paid in connection with the acquisition of the Guadalupe Energy Center. There was no similar activity during the year ended December 31, 2015.
|
•
|
First Lien Notes and Senior Unsecured Notes —
During the year ended December 31, 2015, we received proceeds of $650 million from the issuance of the 2024 Senior Unsecured Notes which were used to replenish cash on hand used for the acquisition of Fore River Energy Center in the fourth quarter of 2014, to repurchase $147 million of our 2023 First Lien Notes and for general corporate purposes. In addition, we redeemed $120 million of our 2023 First Lien Notes. During the year ended December 31, 2014, we received proceeds of $2.8 billion from the issuance of Senior Unsecured Notes, which were used to repurchase our 2019 First Lien Notes, 2020 First Lien Notes and 2021 First Lien Notes of $2.8 billion and we repurchased $120 million of our 2023 First Lien Notes.
|
•
|
Stock repurchases —
During the year ended December 31, 2015, we made payments of $529 million to repurchase our common stock compared to $1.1 billion during the year ended December 31, 2014. The decrease is primarily due to the repurchase of $311 million of common stock from a shareholder in a private transaction during the year ended December 31, 2014.
|
|
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
|
|
Stable
|
|
Total
|
|
Less than 1
Year
|
|
1-3 Years
|
|
3-5 Years
|
|
More than 5
Years
|
||||||||||
Operating lease obligations
(1)
|
$
|
364
|
|
|
$
|
48
|
|
|
$
|
103
|
|
|
$
|
37
|
|
|
$
|
176
|
|
Purchase obligations:
|
|
|
|
|
|
|
|
|
|
||||||||||
Commodity purchase obligations
(2)
|
$
|
1,302
|
|
|
$
|
285
|
|
|
$
|
319
|
|
|
$
|
159
|
|
|
$
|
539
|
|
LTSA
(3)
|
247
|
|
|
34
|
|
|
72
|
|
|
52
|
|
|
89
|
|
|||||
Water agreements
(4)
|
393
|
|
|
25
|
|
|
50
|
|
|
52
|
|
|
266
|
|
|||||
Other purchase obligations
(5)
|
491
|
|
|
201
|
|
|
119
|
|
|
94
|
|
|
77
|
|
|||||
Total purchase obligations
|
$
|
2,433
|
|
|
$
|
545
|
|
|
$
|
560
|
|
|
$
|
357
|
|
|
$
|
971
|
|
Debt
|
$
|
12,369
|
|
|
$
|
762
|
|
|
$
|
723
|
|
|
$
|
1,267
|
|
|
$
|
9,617
|
|
Other contractual obligations:
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest payments on debt
(6)
|
$
|
3,985
|
|
|
$
|
592
|
|
|
$
|
1,181
|
|
|
$
|
1,106
|
|
|
$
|
1,106
|
|
Liability for uncertain tax positions
|
28
|
|
|
17
|
|
|
9
|
|
|
2
|
|
|
—
|
|
|||||
Interest rate hedging instruments
(6)
|
59
|
|
|
29
|
|
|
24
|
|
|
5
|
|
|
1
|
|
|||||
Total other contractual obligations
|
$
|
4,072
|
|
|
$
|
638
|
|
|
$
|
1,214
|
|
|
$
|
1,113
|
|
|
$
|
1,107
|
|
(1)
|
Included in the total are future minimum payments for power plant, office, land and other operating leases. See Note 15 of the Notes to Consolidated Financial Statements for more information.
|
(2)
|
The amounts presented here include contracts for the purchase, transportation or storage of commodities accounted for as executory contracts and therefore not recognized as liabilities on our Consolidated Balance Sheet.
|
(3)
|
The amounts presented here are based on the stated payment terms in the contracts at the time of execution, subject to an annual inflationary adjustment.
|
(4)
|
The amounts presented here are based on contractually obligated amounts over the life of the contract.
|
(5)
|
The amounts presented here include costs to complete construction projects, turbine commitments, parts supply agreements, maintenance agreements, information technology agreements and other purchase obligations.
|
(6)
|
Amounts are projected based upon interest rates at
December 31, 2016
.
|
|
Commodity Instruments
|
|
Interest Rate
Hedging Instruments |
|
Total
|
||||||
Fair value of contracts outstanding at January 1, 2016
|
$
|
(107
|
)
|
|
$
|
(89
|
)
|
|
$
|
(196
|
)
|
Items recognized or otherwise settled during the period
(1)(2)
|
(13
|
)
|
|
46
|
|
|
33
|
|
|||
Fair value attributable to new contracts
|
44
|
|
|
24
|
|
|
68
|
|
|||
Changes in fair value attributable to price movements
|
32
|
|
|
(10
|
)
|
|
22
|
|
|||
Changes in fair value attributable to nonperformance risk
|
(3
|
)
|
|
—
|
|
|
(3
|
)
|
|||
Other changes in fair value
(3)
|
238
|
|
|
—
|
|
|
238
|
|
|||
Fair value of contracts outstanding at December 31, 2016
(4)
|
$
|
191
|
|
|
$
|
(29
|
)
|
|
$
|
162
|
|
(1)
|
Commodity contract settlements consist of the realization of previously recognized gains on contracts not designated as hedging instruments of $102 million (represents a portion of Commodity revenue and Commodity expense as reported on our Consolidated Statements of Operations) and $89 million related to current period gains from other changes in derivative assets and liabilities not reflected in OCI or earnings.
|
(2)
|
Interest rate settlements consist of $33 million related to realized losses from settlements of designated cash flow hedges and $5 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 $8 million of losses on interest rate hedging instruments that were terminated as a result of the repayment and refinancing of debt in fourth quarter of 2016.
|
(3)
|
Consist of $238 million in gains related to hedges acquired from the acquisition of Calpine Solutions, formerly Noble Solutions.
|
(4)
|
Net commodity and interest rate derivative assets and liabilities reported in Notes 7 and 8 of the Notes to Consolidated Financial Statements.
|
Fair Value Source
|
|
2017
|
|
2018-2019
|
|
2020-2021
|
|
After 2021
|
|
Total
|
||||||||||
Prices actively quoted
|
|
$
|
16
|
|
|
$
|
(38
|
)
|
|
$
|
(5
|
)
|
|
$
|
(1
|
)
|
|
$
|
(28
|
)
|
Prices provided by other external sources
|
|
(40
|
)
|
|
(107
|
)
|
|
(17
|
)
|
|
—
|
|
|
(164
|
)
|
|||||
Prices based on models and other valuation methods
|
|
143
|
|
|
190
|
|
|
46
|
|
|
4
|
|
|
383
|
|
|||||
Total fair value
|
|
$
|
119
|
|
|
$
|
45
|
|
|
$
|
24
|
|
|
$
|
3
|
|
|
$
|
191
|
|
•
|
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, 2016)
|
|
2017
|
|
2018-2019
|
|
2020-2021
|
|
After 2021
|
|
Total
|
||||||||||
Investment grade
|
|
$
|
101
|
|
|
$
|
23
|
|
|
$
|
25
|
|
|
$
|
2
|
|
|
$
|
151
|
|
Non-investment grade
|
|
23
|
|
|
31
|
|
|
3
|
|
|
3
|
|
|
60
|
|
|||||
No external ratings
|
|
(5
|
)
|
|
(9
|
)
|
|
(4
|
)
|
|
(2
|
)
|
|
(20
|
)
|
|||||
Total fair value
|
|
$
|
119
|
|
|
$
|
45
|
|
|
$
|
24
|
|
|
$
|
3
|
|
|
$
|
191
|
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
Thereafter
|
|
Total
|
|
Fair Value
December 31,
2016
|
||||||||||||||||
Debt by Maturity Date:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Fixed Rate
|
$
|
7
|
|
|
$
|
7
|
|
|
$
|
8
|
|
|
$
|
8
|
|
|
$
|
7
|
|
|
$
|
5,799
|
|
|
$
|
5,836
|
|
|
$
|
5,776
|
|
Average Interest Rate
|
6.5
|
%
|
|
6.5
|
%
|
|
6.6
|
%
|
|
6.5
|
%
|
|
6.1
|
%
|
|
5.8
|
%
|
|
|
|
|
||||||||||
Variable Rate
|
$
|
727
|
|
|
$
|
177
|
|
|
$
|
463
|
|
|
$
|
1,015
|
|
|
$
|
181
|
|
|
$
|
3,700
|
|
|
$
|
6,263
|
|
|
$
|
6,270
|
|
Average Interest Rate
(1)
|
3.1
|
%
|
|
3.7
|
%
|
|
3.9
|
%
|
|
4.6
|
%
|
|
4.5
|
%
|
|
5.3
|
%
|
|
|
|
|
(1)
|
Projection based upon forward LIBOR rates inferred from spot rates at
December 31, 2016
.
|
•
|
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
|
•
|
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 that the holders of the equity investment at risk, as a group, lose the power from voting rights or similar rights of those investments to direct the activities of a VIE that most significantly affect the VIE’s economic performance or when there are other changes in the powers held by individual variable interest holders.
|
•
|
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
|
|
Position
|
|
John B. (Thad) Hill III
|
|
49
|
|
|
President and Chief Executive Officer
|
Zamir Rauf
|
|
57
|
|
|
Executive Vice President and Chief Financial Officer
|
W. Thaddeus Miller
|
|
66
|
|
|
Executive Vice President, Chief Legal Officer and Secretary
|
W.G. (Trey) Griggs III
|
|
46
|
|
|
Executive Vice President and President, Calpine Retail
|
Charles M. Gates
|
|
65
|
|
|
Executive Vice President, Power Operations
|
Jeff Koshkin
|
|
42
|
|
|
Senior Vice President and Chief Accounting Officer
|
Item 11.
|
Executive Compensation
|
Item 12.
|
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
|
Item 13.
|
Certain Relationships and Related Transactions, and Director Independence
|
Item 14.
|
Principal Accounting Fees and Services
|
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
|
2.1
|
|
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).
|
|
|
|
2.2
|
|
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).
|
|
|
|
2.3
|
|
Purchase and Sale Agreement, dated April 17, 2014, among Calpine Corporation, Calpine Project Holdings, Inc., Calgen Expansion Company, LLC and NatGen Southeast Power LLC (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 8, 2014).
|
|
|
|
3.1
|
|
Amended and Restated Certificate of Incorporation of the Company, as amended (incorporated by reference to Exhibit 3.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on February 1, 2008).
|
|
|
|
3.2
|
|
Amended and Restated Bylaws of the Company (as amended through May 13, 2015) (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the SEC on May 13, 2015).
|
|
|
|
4.1
|
|
Indenture, dated January 14, 2011, among Calpine Corporation, the guarantors party thereto and Wilmington Trust Company, as trustee, including the form of the 7.875% senior secured notes due 2023 (incorporated by reference to Exhibit 4.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on January 14 , 2011).
|
|
|
|
4.2
|
|
First Supplemental Indenture dated as of April 26, 2011, among each of New Development Holdings, LLC, Calpine Mid-Atlantic Energy, LLC, Calpine Mid-Atlantic Operating, LLC, Calpine Bethlehem, LLC, Calpine New Jersey Generation, LLC, Calpine Mid-Atlantic Generation, LLC, Calpine Solar, LLC, Calpine Vineland Solar, LLC and Calpine Mid-Atlantic Marketing, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of January 14, 2011, providing for the issuance of 7.875% senior secured notes due 2023 (incorporated by reference to Exhibit 4.6 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, filed with the SEC on April 29, 2011).
|
|
|
|
4.3
|
|
Second Supplemental Indenture dated as of July 22, 2011, among each of Deer Park Energy Center LLC, Deer Park Holdings, LLC, Metcalf Energy Center, LLC, Metcalf Holdings, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of January 14, 2011, providing for the issuance of 7.875% senior secured notes due 2023 (incorporated by reference to Exhibit 4.5 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, filed with the SEC on July 29, 2011).
|
|
|
|
4.4
|
|
Third Supplemental Indenture dated as of August 20, 2012, among each of Calpine Energy Services GP, LLC and Calpine Energy Services LP, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of January 14, 2011, providing for the issuance of 7.875% senior secured notes due 2023 (incorporated by reference to Exhibit 4.5 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, filed with the SEC on November 6, 2012).
|
|
|
|
4.5
|
|
Fourth Supplemental Indenture dated as of November 26, 2012, among each of South Point Holdings, LLC, South Point Energy Center, LLC, Broad River Energy LLC, South Point OL-1, LLC, South Point OL-2, LLC, South Point OL-3, LLC, South Point OL-4, LLC, Broad River OL-1, LLC, Broad River OL-2, LLC, Broad River OL-3, LLC and Broad River OL-4, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of January 14, 2011, providing for the issuance of 7.875% senior secured notes due 2023 (incorporated by reference to Exhibit 4.28 to Calpine’s Annual Report on Form 10-K for the year ended December 31, 2012, filed with the SEC on February 13, 2013).
|
|
|
|
4.6
|
|
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).
|
|
|
|
4.7
|
|
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).
|
|
|
|
4.8
|
|
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).
|
|
|
|
Exhibit
Number
|
|
Description
|
4.9
|
|
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).
|
|
|
|
4.10
|
|
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).
|
|
|
|
4.11
|
|
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).
|
|
|
|
4.12
|
|
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).
|
|
|
|
4.13
|
|
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). |
|
|
|
4.14
|
|
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).
|
|
|
|
4.15
|
|
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).
|
|
|
|
10.1
|
|
Financing Agreements.
|
|
|
|
10.1.1
|
|
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).
|
|
|
|
10.1.2
|
|
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).
|
|
|
|
10.1.3
|
|
Credit Agreement, dated May 3, 2013 among Calpine Construction Finance Company as borrower and the lenders party thereto, and Goldman Sachs Lending Partners, LLC (“GSLP”) as administrative agent and as collateral agent, CoBank ACB, ING Capital LLC., Royal Bank of Canada, and The Royal Bank of Scotland PLC as co-documentation agents, GSLP, Deutsche Bank Securities Inc., Credit Suisse Securities (USA) LLC, Merrill Lynch, Pierce Fenner and Smith Incorporated and Union Bank, N.A., as joint lead arrangers, joint bookrunners and co-syndication agents, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed with the SEC on May 3, 2013).
|
|
|
|
10.1.4
|
|
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).
|
|
|
|
10.1.5
|
|
Amendment to the Credit Agreement, dated February 20, 2014, among Calpine Construction Finance Company, L.P. as borrower and the lenders party thereto, and Goldman Sachs Lending Partners, LLC (“GSLP”) as administrative agent and as collateral agent, CoBank ACB, ING Capital LLC., Royal Bank of Canada, and The Royal Bank of Scotland PLC as co-documentation agents, GSLP, Deutsche Bank Securities Inc., Credit Suisse Securities (USA) LLC, Merrill Lynch, Pierce Fenner and Smith Incorporated and Union Bank, N.A., as joint lead arrangers, joint bookrunners and co-syndication agents, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, filed with the SEC on May 1, 2014).
|
|
|
|
10.1.6
|
|
Incremental Term B-2 Loan Commitment Supplement to the Credit Agreement, dated February 26, 2014, among Calpine Construction Finance Company, L.P. as borrower and the lenders party thereto, and Goldman Sachs Lending Partners, LLC as administrative agent and as collateral agent under the Credit Agreement, dated as of May 3, 2013 and as amended on February 20, 2014 (incorporated by reference to Exhibit 10.2 to the Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, filed with the SEC on May 1, 2014).
|
|
|
|
Exhibit
Number
|
|
Description
|
10.1.7
|
|
Calpine Guarantee, dated April 17, 2014 (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 8, 2014).
|
|
|
|
10.1.8
|
|
LS Power Equity Partners Guarantee, dated April 17, 2014 (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 8, 2014).
|
|
|
|
10.1.9
|
|
Confidentiality and Non-Disclosure Agreement, dated February 19, 2014 (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 8, 2014).
|
|
|
|
10.1.10
|
|
Amendment to Confidentiality and Non-disclosure Agreement, dated April 17, 2014 (incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 8, 2014).
|
|
|
|
10.1.11
|
|
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).
|
|
|
|
10.1.12
|
|
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).
|
|
|
|
10.1.13
|
|
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).
|
10.1.14
|
|
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).
|
|
|
|
10.1.15
|
|
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).
|
|
|
|
10.1.16
|
|
Credit Agreement, dated December 1, 2016 among Calpine Corporation, as borrower, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent, MUFG Union Bank, N.A., as collateral agent (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on December 2, 2016).
|
|
|
|
10.1.17
|
|
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).
|
|
|
|
10.1.18
|
|
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.*
|
|
|
|
10.1.19
|
|
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.*
|
|
|
|
Exhibit
Number
|
|
Description
|
10.1.20
|
|
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.*
|
|
|
|
10.2
|
|
Management Contracts or Compensatory Plans, Contracts or Arrangements.
|
|
|
|
10.2.1.1
|
|
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).†
|
|
|
|
10.2.1.2
|
|
Non-Qualified Stock Option Agreement between the Company and John B. (Thad) Hill, dated November 3, 2010 (incorporated by reference to Exhibit 10.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on November 8, 2010).†
|
|
|
|
10.2.1.3
|
|
Employment Agreement, dated November 6, 2013, between the Company and John B. (Thad) Hill (incorporated by reference to Exhibit 10.2.3.7 to Calpine’s Annual Report on Form 10-K for the year ended December 31, 2013, filed with the SEC on February 13, 2014).†
|
|
|
|
10.2.1.4
|
|
Restricted Stock Agreement Pursuant to the Amended and Restated 2008 Equity Incentive Plan, dated May 13, 2014 among John B. (Thad) Hill and Calpine Corporation (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 15, 2014).†
|
|
|
|
10.2.2
|
|
Letter Agreement, dated December 17, 2008, between the Company and Zamir Rauf (incorporated by reference to Exhibit 10.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on December 19, 2008).†
|
|
|
|
10.2.3.1
|
|
Employment Agreement, dated August 11, 2008, between the Company and W. Thaddeus Miller (incorporated by reference to Exhibit 10.2.7 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, filed with the SEC on November 7, 2008).†
|
|
|
|
10.2.3.2
|
|
Amended and Restated Executive Employment Agreement between the Company and W. Thaddeus Miller, dated December 18, 2015 (incorporated by reference to Exhibit 10.3 to Calpine’s Current Report on Form 8-K, filed with the SEC on December 18, 2015).†
|
|
|
|
10.2.4
|
|
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).†
|
|
|
|
10.2.5
|
|
Amended and Restated Calpine Corporation 2008 Equity Incentive Plan, dated February 26, 2014 (incorporated by reference to Exhibit 10.3 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, filed with the SEC on May 1, 2014). †
|
|
|
|
10.2.6
|
|
Form of Non-Qualified Stock Option Agreement (Pursuant to the 2008 Equity Incentive Plan) (incorporated by reference to Exhibit 10.4.3 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, filed with the SEC on May 12, 2008).†
|
|
|
|
10.2.7
|
|
Amended and Restated Calpine Corporation 2008 Director Incentive Plan (incorporated by reference to Annex A to Calpine’s Definitive Proxy Statement on Schedule 14A filed with the SEC on April 5, 2010).†
|
|
|
|
10.2.8
|
|
Calpine Corporation Amended and Restated Change in Control and Severance Benefits Plan.†*
|
|
|
|
10.2.9
|
|
Form of Restricted Stock Award Agreement between the Company and John B. (Thad) Hill and Zamir Rauf (Pursuant to the Amended and Restated Calpine Corporation 2008 Equity Incentive Plan, dated February 26, 2014) (incorporated by reference to Exhibit 10.5 to the Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, filed with the SEC on May 1, 2014). †
|
|
|
|
10.2.10
|
|
Form of Performance Share Unit Award Agreement between the Company and Jack A. Fusco and W. Thaddeus Miller (Pursuant to the Amended and Restated Calpine Corporation 2008 Equity Incentive Plan, dated February 26, 2014) (incorporated by reference to Exhibit 10.6 to the Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, filed with the SEC on May 1, 2014). †
|
|
|
|
10.2.11
|
|
Form of Performance Share Unit Award Agreement between the Company and John B. (Thad) Hill and Zamir Rauf (Pursuant to the Amended and Restated Calpine Corporation 2008 Equity Incentive Plan, dated February 26, 2014) (incorporated by reference to Exhibit 10.7 to the Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, filed with the SEC on May 1, 2014). †
|
|
|
|
Exhibit
Number
|
|
Description
|
10.2.12
|
|
Form of Performance Share Unit Award Agreement Under Amended and Restated Calpine Corporation 2008 Equity Incentive Plan between the Company and W. Thaddeus Miller (incorporated by reference to Exhibit 10.1 to the Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, filed with the SEC on April 29, 2016). †
|
|
|
|
10.2.13
|
|
Form of Performance Share Unit Award Agreement Under Amended and Restated Calpine Corporation 2008 Equity Incentive Plan between the Company and Certain Designated Senior Employees (incorporated by reference to Exhibit 10.2 to the Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, filed with the SEC on April 29, 2016). †
|
|
|
|
10.2.14
|
|
Form of Performance Share Unit Award Agreement Under Amended and Restated Calpine Corporation 2008 Equity Incentive Plan between the Company and Certain Designated Senior Employees. †*
|
|
|
|
10.2.15
|
|
Form of Performance Share Unit Award Agreement Under Amended and Restated Calpine Corporation 2008 Equity Incentive Plan between the Company and W. Thaddeus Miller. †*
|
|
|
|
12.1
|
|
Computation of ratio of earnings to fixed charges.*
|
|
|
|
18.1
|
|
Letter of preferability regarding change in accounting principle from PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm (incorporated by reference to Exhibit 18.1 to Calpine’s Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on February 25, 2010).
|
|
|
|
21.1
|
|
Subsidiaries of the Company.*
|
|
|
|
23.1
|
|
Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.*
|
|
|
|
24.1
|
|
Power of Attorney of Officers and Directors of Calpine Corporation (set forth on the signature pages of this Form 10-K).*
|
|
|
|
31.1
|
|
Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*
|
|
|
|
31.2
|
|
Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*
|
|
|
|
32.1
|
|
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)
|
|
February 9, 2017
|
John B. (Thad) Hill
|
|
|
|
|
|
|
|
||
/s/ ZAMIR RAUF
|
|
Executive Vice President and Chief Financial Officer (principal financial officer)
|
|
February 9, 2017
|
Zamir Rauf
|
|
|
|
|
|
|
|
||
/s/ JEFF KOSHKIN
|
|
Chief Accounting Officer (principal accounting officer)
|
|
February 9, 2017
|
Jeff Koshkin
|
|
|
|
|
|
|
|
|
|
/s/ MARY L. BRLAS
|
|
Director
|
|
February 9, 2017
|
Mary L. Brlas
|
|
|
|
|
|
|
|
|
|
/s/ FRANK CASSIDY
|
|
Chairman
|
|
February 9, 2017
|
Frank Cassidy
|
|
|
|
|
|
|
|
|
|
/s/ JACK A. FUSCO
|
|
Director
|
|
February 9, 2017
|
Jack A. Fusco
|
|
|
|
|
|
|
|
||
/s/ MICHAEL W. HOFMANN
|
|
Director
|
|
February 9, 2017
|
Michael W. Hofmann
|
|
|
|
|
|
|
|
||
/s/ DAVID C. MERRITT
|
|
Director
|
|
February 9, 2017
|
David C. Merritt
|
|
|
|
|
|
|
|
||
/s/ W. BENJAMIN MORELAND
|
|
Director
|
|
February 9, 2017
|
W. Benjamin Moreland
|
|
|
|
|
|
|
|
||
/s/ ROBERT MOSBACHER, JR.
|
|
Director
|
|
February 9, 2017
|
Robert Mosbacher, Jr.
|
|
|
|
|
|
|
|
||
/s/ DENISE M. O'LEARY
|
|
Director
|
|
February 9, 2017
|
Denise M. O’Leary
|
|
|
|
|
|
|
|
Page
|
|
2016
|
|
2015
|
|
2014
|
||||||
Operating revenues:
|
|
|
|
|
|
||||||
Commodity revenue
|
$
|
6,943
|
|
|
$
|
6,389
|
|
|
$
|
7,595
|
|
Mark-to-market gain (loss)
|
(245
|
)
|
|
65
|
|
|
419
|
|
|||
Other revenue
|
18
|
|
|
18
|
|
|
16
|
|
|||
Operating revenues
|
6,716
|
|
|
6,472
|
|
|
8,030
|
|
|||
Operating expenses:
|
|
|
|
|
|
||||||
Fuel and purchased energy expense:
|
|
|
|
|
|
||||||
Commodity expense
|
4,431
|
|
|
3,589
|
|
|
4,815
|
|
|||
Mark-to-market (gain) loss
|
(244
|
)
|
|
178
|
|
|
77
|
|
|||
Fuel and purchased energy expense
|
4,187
|
|
|
3,767
|
|
|
4,892
|
|
|||
Plant operating expense
|
977
|
|
|
1,018
|
|
|
969
|
|
|||
Depreciation and amortization expense
|
662
|
|
|
638
|
|
|
603
|
|
|||
Sales, general and other administrative expense
|
140
|
|
|
138
|
|
|
144
|
|
|||
Other operating expenses
|
79
|
|
|
80
|
|
|
88
|
|
|||
Total operating expenses
|
6,045
|
|
|
5,641
|
|
|
6,696
|
|
|||
Impairment losses
|
13
|
|
|
—
|
|
|
123
|
|
|||
(Gain) on sale of assets, net
|
(157
|
)
|
|
—
|
|
|
(753
|
)
|
|||
(Income) from unconsolidated subsidiaries
|
(24
|
)
|
|
(24
|
)
|
|
(25
|
)
|
|||
Income from operations
|
839
|
|
|
855
|
|
|
1,989
|
|
|||
Interest expense
|
631
|
|
|
628
|
|
|
645
|
|
|||
Debt modification and extinguishment costs
|
25
|
|
|
40
|
|
|
346
|
|
|||
Other (income) expense, net
|
24
|
|
|
14
|
|
|
15
|
|
|||
Income before income taxes
|
159
|
|
|
173
|
|
|
983
|
|
|||
Income tax expense (benefit)
|
48
|
|
|
(76
|
)
|
|
22
|
|
|||
Net income
|
111
|
|
|
249
|
|
|
961
|
|
|||
Net income attributable to the noncontrolling interest
|
(19
|
)
|
|
(14
|
)
|
|
(15
|
)
|
|||
Net income attributable to Calpine
|
$
|
92
|
|
|
$
|
235
|
|
|
$
|
946
|
|
Basic earnings per common share attributable to Calpine:
|
|
|
|
|
|
||||||
Weighted average shares of common stock outstanding (in thousands)
|
354,006
|
|
|
362,033
|
|
|
404,837
|
|
|||
Net income per common share attributable to Calpine — basic
|
$
|
0.26
|
|
|
$
|
0.65
|
|
|
$
|
2.34
|
|
|
|
|
|
|
|
||||||
Diluted earnings per common share attributable to Calpine:
|
|
|
|
|
|
||||||
Weighted average shares of common stock outstanding (in thousands)
|
356,110
|
|
|
364,886
|
|
|
409,360
|
|
|||
Net income per common share attributable to Calpine — diluted
|
$
|
0.26
|
|
|
$
|
0.64
|
|
|
$
|
2.31
|
|
|
|
2016
|
|
2015
|
|
2014
|
||||||
Net income
|
|
$
|
111
|
|
|
$
|
249
|
|
|
$
|
961
|
|
Cash flow hedging activities:
|
|
|
|
|
|
|
||||||
Loss on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income
|
|
(2
|
)
|
|
(24
|
)
|
|
(48
|
)
|
|||
Reclassification adjustment for loss on cash flow hedges realized in net income
|
|
43
|
|
|
47
|
|
|
46
|
|
|||
Unrealized actuarial losses arising during period
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|||
Foreign currency translation gain (loss)
|
|
5
|
|
|
(23
|
)
|
|
(13
|
)
|
|||
Income tax expense
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|||
Other comprehensive income (loss)
|
|
45
|
|
|
—
|
|
|
(19
|
)
|
|||
Comprehensive income
|
|
156
|
|
|
249
|
|
|
942
|
|
|||
Comprehensive (income) attributable to the noncontrolling interest
|
|
(22
|
)
|
|
(15
|
)
|
|
(14
|
)
|
|||
Comprehensive income attributable to Calpine
|
|
$
|
134
|
|
|
$
|
234
|
|
|
$
|
928
|
|
|
2016
|
|
2015
|
||||
ASSETS
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents ($79 and $118 attributable to VIEs)
|
$
|
418
|
|
|
$
|
906
|
|
Accounts receivable, net of allowance of $6 and $2
|
839
|
|
|
644
|
|
||
Inventories
|
581
|
|
|
475
|
|
||
Margin deposits and other prepaid expense
|
441
|
|
|
137
|
|
||
Restricted cash, current ($109 and $132 attributable to VIEs)
|
173
|
|
|
216
|
|
||
Derivative assets, current
|
1,725
|
|
|
1,698
|
|
||
Current assets held for sale ($134 and nil attributable to VIEs)
|
210
|
|
|
—
|
|
||
Other current assets
|
45
|
|
|
19
|
|
||
Total current assets
|
4,432
|
|
|
4,095
|
|
||
Property, plant and equipment, net ($3,979 and $4,062 attributable to VIEs)
|
13,013
|
|
|
13,012
|
|
||
Restricted cash, net of current portion ($14 and $11 attributable to VIEs)
|
15
|
|
|
12
|
|
||
Investments in unconsolidated subsidiaries
|
99
|
|
|
79
|
|
||
Long-term derivative assets
|
543
|
|
|
313
|
|
||
Long-term assets held for sale (nil and $130 attributable to VIEs)
|
—
|
|
|
130
|
|
||
Other assets ($63 and $119 attributable to VIEs)
|
1,215
|
|
|
1,040
|
|
||
Total assets
|
$
|
19,317
|
|
|
$
|
18,681
|
|
LIABILITIES & STOCKHOLDERS’ EQUITY
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts payable
|
$
|
671
|
|
|
$
|
552
|
|
Accrued interest payable
|
125
|
|
|
129
|
|
||
Debt, current portion ($176 and $166 attributable to VIEs)
|
748
|
|
|
221
|
|
||
Derivative liabilities, current
|
1,630
|
|
|
1,734
|
|
||
Other current liabilities
|
528
|
|
|
412
|
|
||
Total current liabilities
|
3,702
|
|
|
3,048
|
|
||
Debt, net of current portion ($2,944 and $3,096 attributable to VIEs)
|
11,431
|
|
|
11,716
|
|
||
Long-term derivative liabilities
|
476
|
|
|
473
|
|
||
Other long-term liabilities
|
369
|
|
|
277
|
|
||
Total liabilities
|
15,978
|
|
|
15,514
|
|
||
|
|
|
|
||||
Commitments and contingencies (see Note 15)
|
|
|
|
||||
Stockholders’ equity:
|
|
|
|
||||
Preferred stock, $0.001 par value per share; authorized 100,000,000 shares, none issued and outstanding at December 31, 2016 and 2015
|
—
|
|
|
—
|
|
||
Common stock, $0.001 par value per share; authorized 1,400,000,000 shares, 359,627,113 shares issued and 359,061,764 shares outstanding at December 31, 2016, and 356,755,747 shares issued and 356,662,004 shares outstanding at December 31, 2015
|
—
|
|
|
—
|
|
||
Treasury stock, at cost, 565,349 and 93,743 shares, respectively
|
(7
|
)
|
|
(1
|
)
|
||
Additional paid-in capital
|
9,625
|
|
|
9,594
|
|
||
Accumulated deficit
|
(6,213
|
)
|
|
(6,305
|
)
|
||
Accumulated other comprehensive loss
|
(137
|
)
|
|
(179
|
)
|
||
Total Calpine stockholders’ equity
|
3,268
|
|
|
3,109
|
|
||
Noncontrolling interest
|
71
|
|
|
58
|
|
||
Total stockholders’ equity
|
3,339
|
|
|
3,167
|
|
||
Total liabilities and stockholders’ equity
|
$
|
19,317
|
|
|
$
|
18,681
|
|
|
Common
Stock
|
|
Treasury
Stock
|
|
Additional
Paid-In
Capital
|
|
Accumulated
Deficit
|
|
Accumulated
Other
Comprehensive
Loss
|
|
Noncontrolling
Interest
|
|
Total
Stockholders’
Equity
|
||||||||||||||
Balance, December 31, 2013
|
$
|
1
|
|
|
$
|
(1,230
|
)
|
|
$
|
12,389
|
|
|
$
|
(7,486
|
)
|
|
$
|
(160
|
)
|
|
$
|
54
|
|
|
$
|
3,568
|
|
Treasury stock transactions
|
—
|
|
|
(1,115
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,115
|
)
|
|||||||
Stock-based compensation expense
|
—
|
|
|
—
|
|
|
31
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
31
|
|
|||||||
Option exercises
|
—
|
|
|
—
|
|
|
20
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
20
|
|
|||||||
Distribution to the noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(15
|
)
|
|
(15
|
)
|
|||||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
946
|
|
|
—
|
|
|
15
|
|
|
961
|
|
|||||||
Other comprehensive loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(18
|
)
|
|
(1
|
)
|
|
(19
|
)
|
|||||||
Balance, December 31, 2014
|
$
|
1
|
|
|
$
|
(2,345
|
)
|
|
$
|
12,440
|
|
|
$
|
(6,540
|
)
|
|
$
|
(178
|
)
|
|
$
|
53
|
|
|
$
|
3,431
|
|
Treasury stock transactions
|
—
|
|
|
(541
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(541
|
)
|
|||||||
Retirement of shares held in treasury
|
(1
|
)
|
|
2,885
|
|
|
(2,885
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|||||||
Stock-based compensation expense
|
—
|
|
|
—
|
|
|
31
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
31
|
|
|||||||
Option exercises
|
—
|
|
|
—
|
|
|
8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|||||||
Distribution to the noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(10
|
)
|
|
(10
|
)
|
|||||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
235
|
|
|
—
|
|
|
14
|
|
|
249
|
|
|||||||
Other comprehensive income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
1
|
|
|
—
|
|
|||||||
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
|
|
|
2016
|
|
2015
|
|
2014
|
||||||
Cash flows from operating activities:
|
|
|
|
|
|
||||||
Net income
|
$
|
111
|
|
|
$
|
249
|
|
|
$
|
961
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
||||||
Depreciation and amortization
(1)
|
910
|
|
|
757
|
|
|
649
|
|
|||
Debt extinguishment costs
|
20
|
|
|
6
|
|
|
36
|
|
|||
Deferred income taxes
|
43
|
|
|
(87
|
)
|
|
5
|
|
|||
Impairment losses
|
13
|
|
|
—
|
|
|
123
|
|
|||
(Gain) on sale of assets, net
|
(157
|
)
|
|
—
|
|
|
(753
|
)
|
|||
Mark-to-market activity, net
|
(1
|
)
|
|
110
|
|
|
(353
|
)
|
|||
(Income) from unconsolidated subsidiaries
|
(24
|
)
|
|
(24
|
)
|
|
(25
|
)
|
|||
Return on investments from unconsolidated subsidiaries
|
21
|
|
|
25
|
|
|
13
|
|
|||
Stock-based compensation expense
|
31
|
|
|
26
|
|
|
36
|
|
|||
Other
|
8
|
|
|
7
|
|
|
(4
|
)
|
|||
Change in operating assets and liabilities, net of effects of acquisitions:
|
|
|
|
|
|
||||||
Accounts receivable
|
(128
|
)
|
|
169
|
|
|
(87
|
)
|
|||
Derivative instruments, net
|
(82
|
)
|
|
(183
|
)
|
|
(63
|
)
|
|||
Other assets
|
150
|
|
|
(120
|
)
|
|
151
|
|
|||
Accounts payable and accrued expenses
|
(6
|
)
|
|
(208
|
)
|
|
201
|
|
|||
Other liabilities
|
121
|
|
|
149
|
|
|
(20
|
)
|
|||
Net cash provided by operating activities
|
1,030
|
|
|
876
|
|
|
870
|
|
|||
Cash flows from investing activities:
|
|
|
|
|
|
||||||
Purchases of property, plant and equipment
|
(489
|
)
|
|
(565
|
)
|
|
(492
|
)
|
|||
Proceeds from sale of power plants and other
(2)
|
179
|
|
|
—
|
|
|
1,573
|
|
|||
Purchase of Granite Ridge, Fore River and Guadalupe Energy Centers
|
(526
|
)
|
|
—
|
|
|
(1,197
|
)
|
|||
Purchases of Calpine Solutions and Champion Energy, net of cash acquired
(3)
|
(1,150
|
)
|
|
(296
|
)
|
|
—
|
|
|||
Decrease in restricted cash
|
40
|
|
|
18
|
|
|
28
|
|
|||
Other
|
27
|
|
|
2
|
|
|
4
|
|
|||
Net cash used in investing activities
|
(1,919
|
)
|
|
(841
|
)
|
|
(84
|
)
|
|||
Cash flows from financing activities:
|
|
|
|
|
|
||||||
Borrowings under CCFC Term Loans and First Lien Term Loans
|
1,101
|
|
|
2,137
|
|
|
420
|
|
|||
Repayments of CCFC Term Loans and First Lien Term Loans
|
(1,231
|
)
|
|
(1,635
|
)
|
|
(45
|
)
|
|||
Borrowings under Senior Unsecured Notes
|
—
|
|
|
650
|
|
|
2,800
|
|
|||
Borrowings under First Lien Notes
|
625
|
|
|
—
|
|
|
—
|
|
|||
Repurchases of First Lien Notes
|
(120
|
)
|
|
(267
|
)
|
|
(2,920
|
)
|
|||
Borrowings from project financing, notes payable and other
|
458
|
|
|
79
|
|
|
79
|
|
|||
Repayments of project financing, notes payable and other
|
(364
|
)
|
|
(232
|
)
|
|
(178
|
)
|
|||
Distribution to noncontrolling interest holder
|
(9
|
)
|
|
(10
|
)
|
|
(15
|
)
|
|||
Financing costs
|
(58
|
)
|
|
(34
|
)
|
|
(56
|
)
|
|||
Stock repurchases
|
—
|
|
|
(529
|
)
|
|
(1,100
|
)
|
|||
Proceeds from exercises of stock options
|
1
|
|
|
8
|
|
|
20
|
|
|||
Shares repurchased for tax withholding on stock-based awards
|
(6
|
)
|
|
(12
|
)
|
|
(15
|
)
|
|||
Other
|
4
|
|
|
(1
|
)
|
|
—
|
|
|||
Net cash provided by (used in) financing activities
|
401
|
|
|
154
|
|
|
(1,010
|
)
|
|||
Net (decrease) increase in cash and cash equivalents
|
(488
|
)
|
|
189
|
|
|
(224
|
)
|
|||
Cash and cash equivalents, beginning of period
|
906
|
|
|
717
|
|
|
941
|
|
|||
Cash and cash equivalents, end of period
|
$
|
418
|
|
|
$
|
906
|
|
|
$
|
717
|
|
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS — (Continued)
(in millions)
|
|||||||||||
|
|
|
|
|
|
||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Cash paid during the period for:
|
|
|
|
|
|
||||||
Interest, net of amounts capitalized
|
$
|
584
|
|
|
$
|
620
|
|
|
$
|
610
|
|
Income taxes
|
$
|
12
|
|
|
$
|
21
|
|
|
$
|
23
|
|
|
|
|
|
|
|
||||||
Supplemental disclosure of non-cash investing and financing activities:
|
|
|
|
|
|
||||||
Change in capital expenditures included in accounts payable
|
$
|
(37
|
)
|
|
$
|
13
|
|
|
$
|
3
|
|
Additions to property, plant and equipment through capital leases
|
$
|
—
|
|
|
$
|
9
|
|
|
$
|
19
|
|
Reduction of debt due to sale of Mankato Power Plant
(2)
|
$
|
243
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Retirement of shares held in treasury
|
$
|
—
|
|
|
$
|
2,885
|
|
|
$
|
—
|
|
(1)
|
Includes amortization included in Commodity revenue and Commodity expense associated with intangible assets and amortization recorded in interest expense associated with debt issuance costs and discounts.
|
(2)
|
On October 26, 2016, we completed the sale of Mankato Power Plant for
$407 million
, including working capital and other adjustments. We received net proceeds of
$164 million
after the non-cash reduction of Steamboat project debt of
$243 million
as the funds were provided directly to the lender in conjunction with the sale of the power plant.
|
(3)
|
On December 1, 2016, we completed the purchase of Calpine Solutions, formerly Noble Solutions, along with a swap contract for approximately
$800 million
plus approximately
$350 million
of net working capital at closing. We recovered approximately
$250 million
in cash subsequent to closing and prior to year end December 31, 2016.
|
1.
|
Organization and Operations
|
2.
|
Summary of Significant Accounting Policies
|
As of December 31, 2016
|
|
Ownership Interest
|
|
Property, Plant & Equipment
|
|
Accumulated Depreciation
|
|
Construction in Progress
|
|||||||
(in millions, except percentages)
|
|||||||||||||||
Freestone Energy Center
|
|
75.0
|
%
|
|
$
|
382
|
|
|
$
|
(150
|
)
|
|
$
|
—
|
|
Hidalgo Energy Center
|
|
78.5
|
%
|
|
$
|
255
|
|
|
$
|
(115
|
)
|
|
$
|
—
|
|
•
|
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.
|
|
2016
|
|
2015
|
||||||||||||||||||||
|
Current
|
|
Non-Current
|
|
Total
|
|
Current
|
|
Non-Current
|
|
Total
|
||||||||||||
Debt service
|
$
|
11
|
|
|
$
|
8
|
|
|
$
|
19
|
|
|
$
|
28
|
|
|
$
|
8
|
|
|
$
|
36
|
|
Construction/major maintenance
|
45
|
|
|
6
|
|
|
51
|
|
|
50
|
|
|
2
|
|
|
52
|
|
||||||
Security/project/insurance
|
114
|
|
|
—
|
|
|
114
|
|
|
136
|
|
|
—
|
|
|
136
|
|
||||||
Other
|
3
|
|
|
1
|
|
|
4
|
|
|
2
|
|
|
2
|
|
|
4
|
|
||||||
Total
|
$
|
173
|
|
|
$
|
15
|
|
|
$
|
188
|
|
|
$
|
216
|
|
|
$
|
12
|
|
|
$
|
228
|
|
|
2016
|
|
2015
|
|
Lives
|
||||
Acquired contracts
|
$
|
531
|
|
|
$
|
521
|
|
|
0 – 9 Years
|
Customer relationships
|
420
|
|
|
69
|
|
|
7 – 14 Years
|
||
Trademark and trade name
|
40
|
|
|
41
|
|
|
15 Years
|
||
Other
|
88
|
|
|
88
|
|
|
17 – 23 Years
|
||
|
1,079
|
|
|
719
|
|
|
|
||
Less: Accumulated amortization
|
429
|
|
|
211
|
|
|
|
||
Intangible assets, net
|
$
|
650
|
|
|
$
|
508
|
|
|
|
2017
|
$
|
155
|
|
2018
|
$
|
90
|
|
2019
|
$
|
63
|
|
2020
|
$
|
44
|
|
2021
|
$
|
39
|
|
•
|
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
|
•
|
other service revenues.
|
2017
|
$
|
397
|
|
2018
|
360
|
|
|
2019
|
320
|
|
|
2020
|
261
|
|
|
2021
|
257
|
|
|
Thereafter
|
604
|
|
|
Total
|
$
|
2,199
|
|
3.
|
Acquisitions and Divestitures
|
(1)
|
Consists of acquired customer and wholesale contracts which will be substantially amortized over the next
5
years.
|
(2)
|
Consists primarily of customer relationships that are being amortized over
14
years. See Note 2 for a further description of our intangible assets.
|
|
2016
|
|
2015
|
||||
|
(Unaudited)
|
||||||
Operating revenues
|
$
|
8,324
|
|
|
$
|
8,308
|
|
Net income attributable to Calpine
|
$
|
105
|
|
|
$
|
132
|
|
Net income per share attributable to Calpine - basic
|
$
|
0.30
|
|
|
$
|
0.36
|
|
Net income per share attributable to Calpine - diluted
|
$
|
0.29
|
|
|
$
|
0.36
|
|
Plant Name
|
|
Plant Capacity
|
|
Location
|
||
Oneta Energy Center
|
|
1,134
|
|
MW
|
|
Coweta, OK
|
Carville Energy Center
(1)
|
|
501
|
|
MW
|
|
St. Gabriel, LA
|
Decatur Energy Center
|
|
795
|
|
MW
|
|
Decatur, AL
|
Hog Bayou Energy Center
|
|
237
|
|
MW
|
|
Mobile, AL
|
Santa Rosa Energy Center
|
|
225
|
|
MW
|
|
Pace, FL
|
Columbia Energy Center
(1)
|
|
606
|
|
MW
|
|
Calhoun County, SC
|
Total
|
|
3,498
|
|
MW
|
|
|
(1)
|
Indicates combined-cycle cogeneration power plant.
|
4.
|
Property, Plant and Equipment, Net
|
|
2016
|
|
2015
|
|
Depreciable Lives
|
||||
Buildings, machinery and equipment
|
$
|
16,468
|
|
|
$
|
16,294
|
|
|
3 – 46 Years
|
Geothermal properties
|
1,377
|
|
|
1,319
|
|
|
13 – 58 Years
|
||
Other
|
259
|
|
|
208
|
|
|
3 – 46 Years
|
||
|
18,104
|
|
|
17,821
|
|
|
|
||
Less: Accumulated depreciation
|
5,865
|
|
|
5,377
|
|
|
|
||
|
12,239
|
|
|
12,444
|
|
|
|
||
Land
|
116
|
|
|
120
|
|
|
|
||
Construction in progress
|
658
|
|
|
448
|
|
|
|
||
Property, plant and equipment, net
|
$
|
13,013
|
|
|
$
|
13,012
|
|
|
|
5.
|
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 that the holders of the equity investment at risk, as a group, lose the power from voting rights or similar rights of those investments to direct the activities of a VIE that most significantly affect the VIE’s economic performance or when there are other changes in the powers held by individual variable interest holders.
|
|
Ownership Interest as of December 31, 2016
|
|
2016
|
|
2015
|
||||
Greenfield LP
|
50%
|
|
$
|
73
|
|
|
$
|
65
|
|
Whitby
|
50%
|
|
16
|
|
|
14
|
|
||
Calpine Receivables
|
100%
|
|
10
|
|
|
—
|
|
||
Total investments in unconsolidated subsidiaries
|
|
|
$
|
99
|
|
|
$
|
79
|
|
|
(Income) from
Unconsolidated Subsidiaries
|
|
Distributions
|
||||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2016
|
|
2015
|
|
2014
|
||||||||||||
Greenfield LP
|
$
|
(10
|
)
|
|
$
|
(12
|
)
|
|
$
|
(10
|
)
|
|
$
|
8
|
|
|
$
|
12
|
|
|
$
|
—
|
|
Whitby
|
(14
|
)
|
|
(12
|
)
|
|
(15
|
)
|
|
13
|
|
|
13
|
|
|
13
|
|
||||||
Total
|
$
|
(24
|
)
|
|
$
|
(24
|
)
|
|
$
|
(25
|
)
|
|
$
|
21
|
|
|
$
|
25
|
|
|
$
|
13
|
|
6.
|
Debt
|
|
2016
|
|
2015
|
||||
Senior Unsecured Notes
|
$
|
3,412
|
|
|
$
|
3,406
|
|
First Lien Term Loans
|
3,165
|
|
|
3,277
|
|
||
First Lien Notes
|
2,290
|
|
|
1,789
|
|
||
Project financing, notes payable and other
|
1,597
|
|
|
1,715
|
|
||
CCFC Term Loans
|
1,553
|
|
|
1,565
|
|
||
Capital lease obligations
|
162
|
|
|
185
|
|
||
Subtotal
|
12,179
|
|
|
11,937
|
|
||
Less: Current maturities
|
748
|
|
|
221
|
|
||
Total long-term debt
|
$
|
11,431
|
|
|
$
|
11,716
|
|
2017
|
$
|
762
|
|
2018
|
225
|
|
|
2019
|
498
|
|
|
2020
|
1,050
|
|
|
2021
|
217
|
|
|
Thereafter
|
9,617
|
|
|
Subtotal
|
12,369
|
|
|
Less: Debt issuance costs
|
154
|
|
|
Less: Discount
|
36
|
|
|
Total debt
|
$
|
12,179
|
|
|
Outstanding at December 31,
|
|
Weighted Average
Effective Interest Rates (1) |
||||||||||
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||
2023 Senior Unsecured Notes
|
$
|
1,237
|
|
|
$
|
1,235
|
|
|
5.5
|
%
|
|
5.6
|
%
|
2024 Senior Unsecured Notes
|
643
|
|
|
641
|
|
|
5.6
|
|
|
5.7
|
|
||
2025 Senior Unsecured Notes
|
1,532
|
|
|
1,530
|
|
|
5.9
|
|
|
6.0
|
|
||
Total Senior Unsecured Notes
|
$
|
3,412
|
|
|
$
|
3,406
|
|
|
|
|
|
(1)
|
Our weighted average interest rate calculation includes the amortization of debt issuance costs.
|
•
|
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)
|
||||||||||
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||
2017 First Lien Term Loan
|
$
|
537
|
|
|
$
|
—
|
|
|
5.0
|
%
|
|
—
|
%
|
2019 First Lien Term Loan
|
—
|
|
|
795
|
|
|
—
|
|
|
4.6
|
|
||
2020 First Lien Term Loan
|
—
|
|
|
378
|
|
|
—
|
|
|
4.4
|
|
||
2023 First Lien Term Loan
(2)
|
528
|
|
|
533
|
|
|
4.7
|
|
|
4.7
|
|
||
New 2023 First Lien Term Loan
(2)
|
543
|
|
|
—
|
|
|
4.3
|
|
|
—
|
|
||
2024 First Lien Term Loan
(2)
|
1,557
|
|
|
1,571
|
|
|
3.8
|
|
|
3.8
|
|
||
Total First Lien Term Loans
|
$
|
3,165
|
|
|
$
|
3,277
|
|
|
|
|
|
(1)
|
Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount.
|
(2)
|
On December 21, 2016, we repriced our 2023 First Lien Term Loans by lowering the margin over LIBOR by
0.25%
to
2.75%
and extended the maturity of our 2024 First Lien Term Loan From May 2022 to January 2024.
|
|
Outstanding at December 31,
|
|
Weighted Average
Effective Interest Rates (1) |
||||||||||
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||
2022 First Lien Notes
|
$
|
739
|
|
|
$
|
737
|
|
|
6.4
|
%
|
|
6.4
|
%
|
2023 First Lien Notes
(2)(3)
|
450
|
|
|
568
|
|
|
8.1
|
|
|
8.1
|
|
||
2024 First Lien Notes
|
485
|
|
|
484
|
|
|
6.1
|
|
|
6.1
|
|
||
2026 First Lien Notes
|
616
|
|
|
—
|
|
|
5.4
|
|
|
—
|
|
||
Total First Lien Notes
|
$
|
2,290
|
|
|
$
|
1,789
|
|
|
|
|
|
(1)
|
Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount.
|
(2)
|
In December 2016, we used cash on hand to redeem
10%
of the original aggregate principal amount of our 2023 First Lien Notes, plus accrued and unpaid interest. During the fourth quarter of 2016, we recorded approximately
$5 million
in debt extinguishment costs related to the partial repurchase of our 2023 First Lien Notes.
|
(3)
|
On February 3, 2017, we issued a notice of redemption to repay the remaining
$453 million
of our outstanding 2023 First Lien Notes using cash on hand along with the proceeds from the New 2019 First Lien Term Loan which contains a substantially lower variable rate of LIBOR plus
1.75%
per annum.
|
•
|
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)
|
||||||||||
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||
Russell City due 2023
(2)
|
$
|
462
|
|
|
$
|
522
|
|
|
6.5
|
%
|
|
6.4
|
%
|
Steamboat due 2025
(3)
|
444
|
|
|
448
|
|
|
5.4
|
|
|
6.8
|
|
||
OMEC due 2019
|
303
|
|
|
313
|
|
|
7.2
|
|
|
7.1
|
|
||
Los Esteros due 2023
|
217
|
|
|
242
|
|
|
3.7
|
|
|
3.1
|
|
||
Pasadena
(4)
|
91
|
|
|
107
|
|
|
8.9
|
|
|
8.9
|
|
||
Bethpage Energy Center 3 due 2020-2025
(5)
|
66
|
|
|
73
|
|
|
7.2
|
|
|
7.2
|
|
||
Other
|
14
|
|
|
10
|
|
|
—
|
|
|
—
|
|
||
Total
|
$
|
1,597
|
|
|
$
|
1,715
|
|
|
|
|
|
(1)
|
Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount.
|
(2)
|
We refinanced our Russell City project debt during the fourth quarter of 2016 which lowered the interest rate.
|
(3)
|
We refinanced and upsized our Steamboat project debt during the fourth quarter of 2016 which extended the maturity to November 14, 2025.
|
(4)
|
Represents a failed sale-leaseback transaction that is accounted for as financing transaction under U.S. GAAP.
|
(5)
|
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)
|
||||||||||
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||
CCFC Term Loans
|
$
|
1,553
|
|
|
$
|
1,565
|
|
|
3.5
|
%
|
|
3.5
|
%
|
(1)
|
Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount.
|
|
Sale-Leaseback Transactions
(1)
|
|
Capital Lease
|
|
Total
|
||||||
2017
|
$
|
17
|
|
|
$
|
40
|
|
|
$
|
57
|
|
2018
|
21
|
|
|
40
|
|
|
61
|
|
|||
2019
|
21
|
|
|
21
|
|
|
42
|
|
|||
2020
|
21
|
|
|
19
|
|
|
40
|
|
|||
2021
|
21
|
|
|
19
|
|
|
40
|
|
|||
Thereafter
|
42
|
|
|
117
|
|
|
159
|
|
|||
Total minimum lease payments
|
143
|
|
|
256
|
|
|
399
|
|
|||
Less: Amount representing interest
|
52
|
|
|
94
|
|
|
146
|
|
|||
Present value of net minimum lease payments
|
$
|
91
|
|
|
$
|
162
|
|
|
$
|
253
|
|
(1)
|
Amounts are accounted for as financing transactions under U.S. GAAP and are included in our project financing, notes payable and other amounts above.
|
|
2016
|
|
2015
|
||||
Corporate Revolving Facility
|
$
|
535
|
|
|
$
|
316
|
|
CDHI
|
250
|
|
|
241
|
|
||
Various project financing facilities
|
206
|
|
|
198
|
|
||
Total
|
$
|
991
|
|
|
$
|
755
|
|
|
2016
|
|
2015
|
||||||||||||
|
Fair Value
|
|
Carrying
Value |
|
Fair Value
|
|
Carrying
Value
|
||||||||
Senior Unsecured Notes
|
$
|
3,343
|
|
|
$
|
3,412
|
|
|
$
|
3,063
|
|
|
$
|
3,406
|
|
First Lien Term Loans
|
3,244
|
|
|
3,165
|
|
|
3,197
|
|
|
3,277
|
|
||||
First Lien Notes
|
2,349
|
|
|
2,290
|
|
|
1,885
|
|
|
1,789
|
|
||||
Project financing, notes payable and other
(1)
|
1,543
|
|
|
1,506
|
|
|
1,653
|
|
|
1,608
|
|
||||
CCFC Term Loans
|
1,567
|
|
|
1,553
|
|
|
1,494
|
|
|
1,565
|
|
||||
Total
|
$
|
12,046
|
|
|
$
|
11,926
|
|
|
$
|
11,292
|
|
|
$
|
11,645
|
|
(1)
|
Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP.
|
7.
|
Assets and Liabilities with Recurring Fair Value Measurements
|
|
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2016
|
||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
|
(in millions)
|
||||||||||||||
Assets:
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents
(1)
|
$
|
606
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
606
|
|
Margin deposits
|
350
|
|
|
—
|
|
|
—
|
|
|
350
|
|
||||
Commodity instruments:
|
|
|
|
|
|
|
|
||||||||
Commodity exchange traded futures and swaps contracts
|
1,542
|
|
|
—
|
|
|
—
|
|
|
1,542
|
|
||||
Commodity forward contracts
(2)
|
—
|
|
|
231
|
|
|
466
|
|
|
697
|
|
||||
Interest rate hedging instruments
|
—
|
|
|
29
|
|
|
—
|
|
|
29
|
|
||||
Total assets
|
$
|
2,498
|
|
|
$
|
260
|
|
|
$
|
466
|
|
|
$
|
3,224
|
|
Liabilities:
|
|
|
|
|
|
|
|
||||||||
Margin deposits posted with us by our counterparties
|
$
|
16
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
16
|
|
Commodity instruments:
|
|
|
|
|
|
|
|
||||||||
Commodity exchange traded futures and swaps contracts
|
1,570
|
|
|
—
|
|
|
—
|
|
|
1,570
|
|
||||
Commodity forward contracts
(2)
|
—
|
|
|
411
|
|
|
67
|
|
|
478
|
|
||||
Interest rate hedging instruments
|
—
|
|
|
58
|
|
|
—
|
|
|
58
|
|
||||
Total liabilities
|
$
|
1,586
|
|
|
$
|
469
|
|
|
$
|
67
|
|
|
$
|
2,122
|
|
|
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2015
|
||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
|
(in millions)
|
||||||||||||||
Assets:
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents
(1)
|
$
|
1,134
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,134
|
|
Margin deposits
|
89
|
|
|
—
|
|
|
—
|
|
|
89
|
|
||||
Commodity instruments:
|
|
|
|
|
|
|
|
||||||||
Commodity exchange traded futures and swaps contracts
|
1,736
|
|
|
—
|
|
|
—
|
|
|
1,736
|
|
||||
Commodity forward contracts
(2)
|
—
|
|
|
220
|
|
|
54
|
|
|
274
|
|
||||
Interest rate hedging instruments
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
||||
Total assets
|
$
|
2,959
|
|
|
$
|
221
|
|
|
$
|
54
|
|
|
$
|
3,234
|
|
Liabilities:
|
|
|
|
|
|
|
|
||||||||
Margin deposits posted with us by our counterparties
|
$
|
35
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
35
|
|
Commodity instruments:
|
|
|
|
|
|
|
|
||||||||
Commodity exchange traded futures and swaps contracts
|
1,604
|
|
|
—
|
|
|
—
|
|
|
1,604
|
|
||||
Commodity forward contracts
(2)
|
—
|
|
|
413
|
|
|
100
|
|
|
513
|
|
||||
Interest rate hedging instruments
|
—
|
|
|
90
|
|
|
—
|
|
|
90
|
|
||||
Total liabilities
|
$
|
1,639
|
|
|
$
|
503
|
|
|
$
|
100
|
|
|
$
|
2,242
|
|
(1)
|
As of
December 31, 2016
and
2015
, we had cash and cash equivalents of
$418 million
and
$906 million
included in cash and cash equivalents and
$188 million
and
$228 million
included in restricted cash, respectively.
|
(2)
|
Includes OTC swaps and options.
|
|
|
Quantitative Information about Level 3 Fair Value Measurements
|
||||||||
|
|
December 31, 2016
|
||||||||
|
|
Fair Value, Net Asset
|
|
|
|
Significant Unobservable
|
|
|
||
|
|
(Liability)
|
|
Valuation Technique
|
|
Input
|
|
Range
|
||
|
|
(in millions)
|
|
|
|
|
|
|
||
Power Contracts
|
|
$
|
360
|
|
|
Discounted cash flow
|
|
Market price (per MWh)
|
|
$9.60 — $86.34/MWh
|
Power Congestion Products
|
|
$
|
12
|
|
|
Discounted cash flow
|
|
Market price (per MWh)
|
|
$(7.52) — $13.62/MWh
|
Natural Gas Contracts
|
|
$
|
17
|
|
|
Discounted cash flow
|
|
Market price (per MMBtu)
|
|
$1.95 — $5.66/MMBtu
|
|
|
Quantitative Information about Level 3 Fair Value Measurements
|
||||||||
|
|
December 31, 2015
|
||||||||
|
|
Fair Value, Net Asset
|
|
|
|
Significant Unobservable
|
|
|
||
|
|
(Liability)
|
|
Valuation Technique
|
|
Input
|
|
Range
|
||
|
|
(in millions)
|
|
|
|
|
|
|
||
Power Contracts
|
|
$
|
(54
|
)
|
|
Discounted cash flow
|
|
Market price (per MWh)
|
|
$6.72 — $83.25/MWh
|
Power Congestion Products
|
|
$
|
8
|
|
|
Discounted cash flow
|
|
Market price (per MWh)
|
|
$(11.47) — $12.19/MWh
|
|
2016
|
|
2015
|
|
2014
|
||||||
Balance, beginning of period
|
$
|
(46
|
)
|
|
$
|
85
|
|
|
$
|
14
|
|
Realized and mark-to-market gains (losses):
|
|
|
|
|
|
||||||
Included in net income:
|
|
|
|
|
|
||||||
Included in operating revenues
(1)
|
(46
|
)
|
|
218
|
|
|
70
|
|
|||
Included in fuel and purchased energy expense
(2)
|
7
|
|
|
(7
|
)
|
|
5
|
|
|||
Purchases and settlements:
|
|
|
|
|
|
||||||
Purchases
(3)
|
426
|
|
|
(70
|
)
|
|
6
|
|
|||
Settlements
|
(21
|
)
|
|
(29
|
)
|
|
(10
|
)
|
|||
Transfers in and/or out of level 3
(4)
:
|
|
|
|
|
|
||||||
Transfers into level 3
(5)
|
4
|
|
|
—
|
|
|
—
|
|
|||
Transfers out of level 3
(6)
|
75
|
|
|
(243
|
)
|
|
—
|
|
|||
Balance, end of period
|
$
|
399
|
|
|
$
|
(46
|
)
|
|
$
|
85
|
|
Change in unrealized gains (losses) relating to instruments still held at end of period
|
$
|
(39
|
)
|
|
$
|
211
|
|
|
$
|
75
|
|
(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, 2016
,
2015
and
2014
.
|
(5)
|
We had
$4 million
in gains transfers out of level 2 into level 3 for the year ended
December 31, 2016
. There were
no
transfers out of level 2 into level 3 for the years ended
December 31, 2015
and
2014
.
|
(6)
|
We had
$(75) million
in losses and
$4 million
in gains transferred out of level 3 into level 2 during the years ended
December 31, 2016
and
2015
, respectively, due to changes in market liquidity in various power markets and
$239 million
in gains transferred out of level 3 during the year ended
December 31, 2015
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. There were
no
transfers out of level 3 for the year ended
December 31, 2014
.
|
8.
|
Derivative Instruments
|
Derivative Instruments
|
|
Notional Amounts
|
||||||
|
2016
|
|
2015
|
|||||
Power (MWh)
|
|
(13
|
)
|
|
(41
|
)
|
||
Natural gas (MMBtu)
|
|
613
|
|
|
996
|
|
||
Environmental credits (Tonnes)
|
|
16
|
|
|
8
|
|
||
Interest rate hedging instruments
|
|
$
|
3,721
|
|
(1)
|
$
|
1,320
|
|
(1)
|
We entered into interest rate hedging instruments during the second quarter of 2016 to hedge approximately
$2.5 billion
of variable rate corporate debt for 2017 through 2019 which effectively places a ceiling on LIBOR at rates varying from
1.44%
to
1.8125%
for hedged interest payments. See Note 6 for a further discussion of our First Lien Term Loans.
|
|
December 31, 2016
|
||||||||||
|
Commodity
Instruments
|
|
Interest Rate
Hedging Instruments
|
|
Total
Derivative
Instruments
|
||||||
Balance Sheet Presentation
|
|
|
|
|
|
||||||
Current derivative assets
|
$
|
1,724
|
|
|
$
|
1
|
|
|
$
|
1,725
|
|
Long-term derivative assets
|
515
|
|
|
28
|
|
|
543
|
|
|||
Total derivative assets
|
$
|
2,239
|
|
|
$
|
29
|
|
|
$
|
2,268
|
|
|
|
|
|
|
|
||||||
Current derivative liabilities
|
$
|
1,602
|
|
|
$
|
28
|
|
|
$
|
1,630
|
|
Long-term derivative liabilities
|
446
|
|
|
30
|
|
|
476
|
|
|||
Total derivative liabilities
|
$
|
2,048
|
|
|
$
|
58
|
|
|
$
|
2,106
|
|
Net derivative assets (liabilities)
|
$
|
191
|
|
|
$
|
(29
|
)
|
|
$
|
162
|
|
|
December 31, 2015
|
||||||||||
|
Commodity
Instruments
|
|
Interest Rate
Hedging Instruments |
|
Total
Derivative
Instruments
|
||||||
Balance Sheet Presentation
|
|
|
|
|
|
||||||
Current derivative assets
|
$
|
1,698
|
|
|
$
|
—
|
|
|
$
|
1,698
|
|
Long-term derivative assets
|
312
|
|
|
1
|
|
|
313
|
|
|||
Total derivative assets
|
$
|
2,010
|
|
|
$
|
1
|
|
|
$
|
2,011
|
|
|
|
|
|
|
|
||||||
Current derivative liabilities
|
$
|
1,697
|
|
|
$
|
37
|
|
|
$
|
1,734
|
|
Long-term derivative liabilities
|
420
|
|
|
53
|
|
|
473
|
|
|||
Total derivative liabilities
|
$
|
2,117
|
|
|
$
|
90
|
|
|
$
|
2,207
|
|
Net derivative assets (liabilities)
|
$
|
(107
|
)
|
|
$
|
(89
|
)
|
|
$
|
(196
|
)
|
|
December 31, 2016
|
|
December 31, 2015
|
||||||||||||
|
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
|
$
|
29
|
|
|
$
|
58
|
|
|
$
|
1
|
|
|
$
|
90
|
|
Total derivatives designated as cash flow hedging instruments
|
$
|
29
|
|
|
$
|
58
|
|
|
$
|
1
|
|
|
$
|
90
|
|
|
|
|
|
|
|
|
|
||||||||
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
||||||||
Commodity instruments
|
$
|
2,239
|
|
|
$
|
2,048
|
|
|
$
|
2,010
|
|
|
$
|
2,117
|
|
Total derivatives not designated as hedging instruments
|
$
|
2,239
|
|
|
$
|
2,048
|
|
|
$
|
2,010
|
|
|
$
|
2,117
|
|
Total derivatives
|
$
|
2,268
|
|
|
$
|
2,106
|
|
|
$
|
2,011
|
|
|
$
|
2,207
|
|
|
|
December 31, 2016
|
||||||||||||||
|
|
Gross Amounts Not Offset on the Consolidated Balance Sheets
|
||||||||||||||
|
|
Gross Amounts Presented on our Consolidated Balance Sheets
|
|
Derivative Asset (Liability) not Offset on the Consolidated Balance Sheets
|
|
Margin/Cash (Received) Posted
(1)
|
|
Net Amount
|
||||||||
Derivative assets:
|
|
|
|
|
|
|
|
|
||||||||
Commodity exchange traded futures and swaps contracts
|
|
$
|
1,542
|
|
|
$
|
(1,521
|
)
|
|
$
|
(21
|
)
|
|
$
|
—
|
|
Commodity forward contracts
|
|
697
|
|
|
(165
|
)
|
|
(11
|
)
|
|
521
|
|
||||
Interest rate hedging instruments
|
|
29
|
|
|
—
|
|
|
—
|
|
|
29
|
|
||||
Total derivative assets
|
|
$
|
2,268
|
|
|
$
|
(1,686
|
)
|
|
$
|
(32
|
)
|
|
$
|
550
|
|
Derivative (liabilities):
|
|
|
|
|
|
|
|
|
||||||||
Commodity exchange traded futures and swaps contracts
|
|
$
|
(1,570
|
)
|
|
$
|
1,521
|
|
|
$
|
49
|
|
|
$
|
—
|
|
Commodity forward contracts
|
|
(478
|
)
|
|
165
|
|
|
55
|
|
|
(258
|
)
|
||||
Interest rate hedging instruments
|
|
(58
|
)
|
|
—
|
|
|
—
|
|
|
(58
|
)
|
||||
Total derivative (liabilities)
|
|
$
|
(2,106
|
)
|
|
$
|
1,686
|
|
|
$
|
104
|
|
|
$
|
(316
|
)
|
Net derivative assets (liabilities)
|
|
$
|
162
|
|
|
$
|
—
|
|
|
$
|
72
|
|
|
$
|
234
|
|
|
|
December 31, 2015
|
||||||||||||||
|
|
Gross Amounts Not Offset on the Consolidated Balance Sheets
|
||||||||||||||
|
|
Gross Amounts Presented on our Consolidated Balance Sheets
|
|
Derivative Asset (Liability) not Offset on the Consolidated Balance Sheets
|
|
Margin/Cash (Received) Posted
(1)
|
|
Net Amount
|
||||||||
Derivative assets:
|
|
|
|
|
|
|
|
|
||||||||
Commodity exchange traded futures and swaps contracts
|
|
$
|
1,736
|
|
|
$
|
(1,602
|
)
|
|
$
|
(134
|
)
|
|
$
|
—
|
|
Commodity forward contracts
|
|
274
|
|
|
(202
|
)
|
|
(3
|
)
|
|
69
|
|
||||
Interest rate hedging instruments
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
||||
Total derivative assets
|
|
$
|
2,011
|
|
|
$
|
(1,804
|
)
|
|
$
|
(137
|
)
|
|
$
|
70
|
|
Derivative (liabilities):
|
|
|
|
|
|
|
|
|
||||||||
Commodity exchange traded futures and swaps contracts
|
|
$
|
(1,604
|
)
|
|
$
|
1,602
|
|
|
$
|
2
|
|
|
$
|
—
|
|
Commodity forward contracts
|
|
(513
|
)
|
|
202
|
|
|
3
|
|
|
(308
|
)
|
||||
Interest rate hedging instruments
|
|
(90
|
)
|
|
—
|
|
|
—
|
|
|
(90
|
)
|
||||
Total derivative (liabilities)
|
|
$
|
(2,207
|
)
|
|
$
|
1,804
|
|
|
$
|
5
|
|
|
$
|
(398
|
)
|
Net derivative assets (liabilities)
|
|
$
|
(196
|
)
|
|
$
|
—
|
|
|
$
|
(132
|
)
|
|
$
|
(328
|
)
|
(1)
|
Negative balances represent margin deposits posted with us by our counterparties related to our derivative activities that are subject to a master netting arrangement. Positive balances reflect margin deposits and natural gas and power prepayments posted by us with our counterparties related to our derivative activities that are subject to a master netting arrangement. See Note 9 for a further discussion of our collateral.
|
|
2016
|
|
2015
|
|
2014
|
||||||
Realized gain (loss)
(1)(2)
|
|
|
|
|
|
||||||
Commodity derivative instruments
|
$
|
235
|
|
|
$
|
450
|
|
|
$
|
110
|
|
Total realized gain (loss)
|
$
|
235
|
|
|
$
|
450
|
|
|
$
|
110
|
|
|
|
|
|
|
|
||||||
Mark-to-market gain (loss)
(3)
|
|
|
|
|
|
||||||
Commodity derivative instruments
|
$
|
(1
|
)
|
|
$
|
(113
|
)
|
|
$
|
342
|
|
Interest rate hedging instruments
|
2
|
|
|
3
|
|
|
11
|
|
|||
Total mark-to-market gain (loss)
|
$
|
1
|
|
|
$
|
(110
|
)
|
|
$
|
353
|
|
Total activity, net
|
$
|
236
|
|
|
$
|
340
|
|
|
$
|
463
|
|
(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 and Calpine Solutions, formerly Noble Solutions.
|
(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.
|
|
2016
|
|
2015
|
|
2014
|
||||||
Realized and mark-to-market gain (loss)
(1)
|
|
|
|
|
|
||||||
Derivatives contracts included in operating revenues
(2)(3)
|
$
|
109
|
|
|
$
|
528
|
|
|
$
|
384
|
|
Derivatives contracts included in fuel and purchased energy expense
(2)(3)
|
125
|
|
|
(191
|
)
|
|
68
|
|
|||
Interest rate hedging instruments included in interest expense
(4)
|
2
|
|
|
3
|
|
|
11
|
|
|||
Total activity, net
|
$
|
236
|
|
|
$
|
340
|
|
|
$
|
463
|
|
(1)
|
In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes adjustments to reflect changes in credit default risk exposure.
|
(2)
|
Does not include the realized value associated with derivative instruments that settle through physical delivery.
|
(3)
|
Includes amortization of acquisition date fair value of financial derivative activity related to the acquisition of Champion Energy and Calpine Solutions, formerly Noble Solutions.
|
(4)
|
In addition to changes in market value on interest rate hedging instruments not designated as hedges, changes in mark-to-market gain (loss) also includes hedge ineffectiveness.
|
|
Gains (Loss) Recognized in
OCI (Effective Portion)
|
|
Gain (Loss) Reclassified from
AOCI into Income (Effective
Portion)
(3)(4)
|
||||||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2016
|
|
2015
|
|
2014
|
|
Affected Line Item on the Consolidated Statements of Operations
|
||||||||||||
Interest rate hedging instruments
(1)(2)
|
$
|
41
|
|
|
$
|
23
|
|
|
$
|
(2
|
)
|
|
$
|
(43
|
)
|
|
$
|
(47
|
)
|
|
$
|
(46
|
)
|
|
Interest expense
|
(1)
|
We did not record any material gain (loss) on hedge ineffectiveness related to our interest rate hedging instruments designated as cash flow hedges during the years ended
December 31, 2016
,
2015
and
2014
.
|
(2)
|
We recorded income tax expense of
$1 million
,
nil
and
nil
for the years ended
December 31, 2016
,
2015
and
2014
, 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
$90 million
,
$127 million
and
$149 million
at
December 31, 2016
,
2015
and
2014
, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were
$8 million
, $
11 million
and $
12 million
at
December 31, 2016
,
2015
and
2014
, respectively.
|
(4)
|
Includes losses of
$3 million
,
nil
and
$10 million
that were reclassified from AOCI to interest expense for the years ended
December 31, 2016
,
2015
and
2014
, respectively, where the hedged transactions became probable of not occurring.
|
9.
|
Use of Collateral
|
|
2016
|
|
2015
|
||||
Margin deposits
(1)
|
$
|
350
|
|
|
$
|
89
|
|
Natural gas and power prepayments
|
25
|
|
|
34
|
|
||
Total margin deposits and natural gas and power prepayments with our counterparties
(2)
|
$
|
375
|
|
|
$
|
123
|
|
|
|
|
|
||||
Letters of credit issued
|
$
|
798
|
|
|
$
|
600
|
|
First priority liens under power and natural gas agreements
(3)
|
206
|
|
|
382
|
|
||
First priority liens under interest rate hedging instruments
|
55
|
|
|
92
|
|
||
Total letters of credit and first priority liens with our counterparties
|
$
|
1,059
|
|
|
$
|
1,074
|
|
|
|
|
|
||||
Margin deposits posted with us by our counterparties
(1)(4)
|
$
|
16
|
|
|
$
|
35
|
|
Letters of credit posted with us by our counterparties
|
43
|
|
|
24
|
|
||
Total margin deposits and letters of credit posted with us by our counterparties
|
$
|
59
|
|
|
$
|
59
|
|
(1)
|
Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated Balance Sheets. We do not offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation, and we do not offset amounts recognized for the right to reclaim, or the obligation to return, cash collateral with corresponding derivative instrument fair values. See Note 8 for further discussion of our derivative instruments subject to master netting arrangements.
|
(2)
|
At
December 31, 2016
and
2015
,
$366 million
and
$101 million
, respectively, were included in margin deposits and other prepaid expense and
$9 million
and
$22 million
, respectively, were included in other assets on our Consolidated Balance Sheets.
|
(3)
|
Includes
$185 million
and
$345 million
related to first priority liens under power supply contracts associated with our retail hedging activities at
December 31, 2016
and
2015
, respectively.
|
(4)
|
Included in other current liabilities on our Consolidated Balance Sheets.
|
10.
|
Income Taxes
|
|
2016
|
|
2015
|
|
2014
|
||||||
U.S.
|
$
|
116
|
|
|
$
|
133
|
|
|
$
|
942
|
|
International
|
24
|
|
|
26
|
|
|
26
|
|
|||
Total
|
$
|
140
|
|
|
$
|
159
|
|
|
$
|
968
|
|
|
2016
|
|
2015
|
|
2014
|
||||||
Current:
|
|
|
|
|
|
||||||
Federal
|
$
|
(10
|
)
|
|
$
|
(1
|
)
|
|
$
|
(1
|
)
|
State
|
14
|
|
|
10
|
|
|
19
|
|
|||
Foreign
|
1
|
|
|
2
|
|
|
(1
|
)
|
|||
Total current
|
5
|
|
|
11
|
|
|
17
|
|
|||
Deferred:
|
|
|
|
|
|
||||||
Federal
|
10
|
|
|
(21
|
)
|
|
—
|
|
|||
State
|
27
|
|
|
1
|
|
|
(1
|
)
|
|||
Foreign
|
6
|
|
|
(67
|
)
|
|
6
|
|
|||
Total deferred
|
43
|
|
|
(87
|
)
|
|
5
|
|
|||
Total income tax expense (benefit)
|
$
|
48
|
|
|
$
|
(76
|
)
|
|
$
|
22
|
|
|
2016
|
|
2015
|
|
2014
|
|||
Federal statutory tax expense (benefit) rate
|
35.0
|
%
|
|
35.0
|
%
|
|
35.0
|
%
|
State tax expense, net of federal benefit
|
19.4
|
|
|
5.1
|
|
|
1.9
|
|
Valuation allowances against future tax benefits
|
(25.0
|
)
|
|
(46.0
|
)
|
|
(35.8
|
)
|
Valuation allowance related to foreign taxes
|
(0.1
|
)
|
|
(49.4
|
)
|
|
—
|
|
Distributions from foreign affiliates and foreign taxes
|
(0.6
|
)
|
|
3.1
|
|
|
1.2
|
|
Change in unrecognized tax benefits
|
(0.1
|
)
|
|
1.2
|
|
|
(0.4
|
)
|
Disallowed compensation
|
0.9
|
|
|
3.1
|
|
|
0.1
|
|
Stock-based compensation
|
2.2
|
|
|
0.6
|
|
|
0.1
|
|
Equity earnings
|
2.0
|
|
|
(0.5
|
)
|
|
—
|
|
Other differences
|
0.6
|
|
|
—
|
|
|
0.2
|
|
Effective income tax expense (benefit) rate
|
34.3
|
%
|
|
(47.8
|
)%
|
|
2.3
|
%
|
|
2016
|
|
2015
|
||||
Deferred tax assets:
|
|
|
|
||||
NOL and credit carryforwards
|
$
|
2,728
|
|
|
$
|
2,842
|
|
Taxes related to risk management activities and derivatives
|
38
|
|
|
53
|
|
||
Reorganization items and impairments
|
222
|
|
|
212
|
|
||
Deferred tax assets before valuation allowance
|
2,988
|
|
|
3,107
|
|
||
Valuation allowance
|
(1,581
|
)
|
|
(1,637
|
)
|
||
Total deferred tax assets
|
1,407
|
|
|
1,470
|
|
||
Deferred tax liabilities:
|
|
|
|
||||
Property, plant and equipment
|
(1,266
|
)
|
|
(1,377
|
)
|
||
Other differences
|
(93
|
)
|
|
(3
|
)
|
||
Total deferred tax liabilities
|
(1,359
|
)
|
|
(1,380
|
)
|
||
Net deferred tax asset
|
48
|
|
|
90
|
|
||
Less: Non-current deferred tax liability
|
(14
|
)
|
|
—
|
|
||
Deferred income tax asset, non-current
|
$
|
62
|
|
|
$
|
90
|
|
|
2016
|
|
2015
|
|
2014
|
||||||
Balance, beginning of period
|
$
|
(58
|
)
|
|
$
|
(56
|
)
|
|
$
|
(68
|
)
|
Increases related to prior year tax positions
|
—
|
|
|
—
|
|
|
(4
|
)
|
|||
Decreases related to prior year tax positions
|
1
|
|
|
3
|
|
|
8
|
|
|||
Increases related to current year tax positions
|
(2
|
)
|
|
(5
|
)
|
|
—
|
|
|||
Decreases related to settlements
|
—
|
|
|
—
|
|
|
8
|
|
|||
Balance, end of period
|
$
|
(59
|
)
|
|
$
|
(58
|
)
|
|
$
|
(56
|
)
|
11.
|
Earnings per Share
|
|
2016
|
|
2015
|
|
2014
|
|||
Share-based awards
|
1,659
|
|
|
5,340
|
|
|
2,859
|
|
12.
|
Stock-Based Compensation
|
|
Number of
Shares
|
|
Weighted Average
Exercise Price
|
|
Weighted
Average
Remaining
Term
(in years)
|
|
Aggregate
Intrinsic Value
(in millions)
|
|||||
Outstanding — December 31, 2015
|
3,055,172
|
|
|
$
|
13.62
|
|
|
3.9
|
|
$
|
5
|
|
Exercised
|
156,758
|
|
|
$
|
11.64
|
|
|
|
|
|
||
Expired
|
201,278
|
|
|
$
|
15.62
|
|
|
|
|
|
||
Outstanding — December 31, 2016
|
2,697,136
|
|
|
$
|
13.59
|
|
|
3.0
|
|
$
|
2
|
|
Exercisable — December 31, 2016
|
2,697,136
|
|
|
$
|
13.59
|
|
|
3.0
|
|
$
|
2
|
|
Vested and expected to vest – December 31, 2016
|
2,697,136
|
|
|
$
|
13.59
|
|
|
3.0
|
|
$
|
2
|
|
|
Number of
Restricted
Stock Awards
|
|
Weighted
Average
Grant-Date
Fair Value
|
|||
Nonvested — December 31, 2015
|
3,528,270
|
|
|
$
|
19.91
|
|
Granted
|
2,994,292
|
|
|
$
|
12.39
|
|
Forfeited
|
248,282
|
|
|
$
|
16.12
|
|
Vested
|
1,404,632
|
|
|
$
|
18.70
|
|
Nonvested — December 31, 2016
|
4,869,648
|
|
|
$
|
15.83
|
|
|
Number of
Performance Share Units
|
|
Weighted
Average
Grant-Date
Fair Value
|
|||
Nonvested — December 31, 2015
|
517,906
|
|
|
$
|
23.36
|
|
Granted
|
657,807
|
|
|
$
|
14.81
|
|
Vested
|
285,126
|
|
|
$
|
20.70
|
|
Nonvested — December 31, 2016
|
890,587
|
|
|
$
|
17.90
|
|
13.
|
Defined Contribution and Defined Benefit Plans
|
14.
|
Capital Structure
|
|
Shares
Issued
|
|
Shares
Held in
Treasury
|
|
Shares
Outstanding
|
|||
Balance, December 31, 2013
|
497,841,056
|
|
|
(68,802,068
|
)
|
|
429,038,988
|
|
Shares issued under Calpine Equity Incentive Plans
|
4,445,966
|
|
|
(1,879,167
|
)
|
|
2,566,799
|
|
Share repurchase program
|
—
|
|
|
(49,684,523
|
)
|
|
(49,684,523
|
)
|
Balance, December 31, 2014
|
502,287,022
|
|
|
(120,365,758
|
)
|
|
381,921,264
|
|
Shares issued under Calpine Equity Incentive Plans
|
2,431,236
|
|
|
(1,089,328
|
)
|
|
1,341,908
|
|
Share repurchase program
|
—
|
|
|
(26,601,168
|
)
|
|
(26,601,168
|
)
|
Retirement of shares held in treasury
|
(147,962,511
|
)
|
|
147,962,511
|
|
|
—
|
|
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
|
|
15.
|
Commitments and Contingencies
|
|
Initial
Year
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
Thereafter
|
|
Total
|
||||||||||||||
Land and other operating leases
|
various
|
|
$
|
13
|
|
|
$
|
13
|
|
|
$
|
13
|
|
|
$
|
12
|
|
|
$
|
12
|
|
|
$
|
176
|
|
|
$
|
239
|
|
Power plant operating lease
|
2000
|
|
22
|
|
|
22
|
|
|
30
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
74
|
|
|||||||
Total leases
|
|
|
$
|
35
|
|
|
$
|
35
|
|
|
$
|
43
|
|
|
$
|
12
|
|
|
$
|
12
|
|
|
$
|
176
|
|
|
$
|
313
|
|
2017
|
$
|
13
|
|
2018
|
13
|
|
|
2019
|
12
|
|
|
2020
|
12
|
|
|
2021
|
1
|
|
|
Thereafter
|
—
|
|
|
Total
|
$
|
51
|
|
2017
|
$
|
285
|
|
2018
|
201
|
|
|
2019
|
118
|
|
|
2020
|
89
|
|
|
2021
|
70
|
|
|
Thereafter
|
539
|
|
|
Total
|
$
|
1,302
|
|
Guarantee Commitments
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
Thereafter
|
|
Total
|
||||||||||||||
Guarantee of subsidiary debt
(1)
|
|
$
|
26
|
|
|
$
|
31
|
|
|
$
|
30
|
|
|
$
|
30
|
|
|
$
|
29
|
|
|
$
|
90
|
|
|
$
|
236
|
|
Standby letters of credit
(2)(3)(4)
|
|
855
|
|
|
98
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
38
|
|
|
991
|
|
|||||||
Surety bonds
(4)(5)(6)
|
|
15
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11
|
|
|
26
|
|
|||||||
Guarantee under Accounts Receivable Sales Program
(7)
|
|
211
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
211
|
|
|||||||
Total
|
|
$
|
1,107
|
|
|
$
|
129
|
|
|
$
|
30
|
|
|
$
|
30
|
|
|
$
|
29
|
|
|
$
|
139
|
|
|
$
|
1,464
|
|
(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 6.
|
(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, 2016
,
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
December 1, 2017
.
|
16.
|
Segment and Significant Customer Information
|
|
Year Ended December 31, 2016
|
||||||||||||||||||
|
West
|
|
Texas
|
|
East
|
|
Consolidation
and
Elimination
|
|
Total
|
||||||||||
Revenues from external customers
|
$
|
1,562
|
|
|
$
|
2,801
|
|
|
$
|
2,353
|
|
|
$
|
—
|
|
|
$
|
6,716
|
|
Intersegment revenues
|
7
|
|
|
14
|
|
|
11
|
|
|
(32
|
)
|
|
—
|
|
|||||
Total operating revenues
|
$
|
1,569
|
|
|
$
|
2,815
|
|
|
$
|
2,364
|
|
|
$
|
(32
|
)
|
|
$
|
6,716
|
|
Commodity Margin
|
$
|
991
|
|
|
$
|
655
|
|
|
$
|
958
|
|
|
$
|
—
|
|
|
$
|
2,604
|
|
Add: Mark-to-market commodity activity, net and other
(1)
|
(3
|
)
|
|
(23
|
)
|
|
(20
|
)
|
|
(29
|
)
|
|
(75
|
)
|
|||||
Less:
|
|
|
|
|
|
|
|
|
|
||||||||||
Plant operating expense
|
357
|
|
|
317
|
|
|
332
|
|
|
(29
|
)
|
|
977
|
|
|||||
Depreciation and amortization expense
|
225
|
|
|
213
|
|
|
224
|
|
|
—
|
|
|
662
|
|
|||||
Sales, general and other administrative expense
|
39
|
|
|
56
|
|
|
45
|
|
|
—
|
|
|
140
|
|
|||||
Other operating expenses
|
32
|
|
|
9
|
|
|
38
|
|
|
—
|
|
|
79
|
|
|||||
Impairment losses
|
13
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
13
|
|
|||||
(Gain) on sale of assets, net
|
—
|
|
|
—
|
|
|
(157
|
)
|
|
—
|
|
|
(157
|
)
|
|||||
(Income) from unconsolidated subsidiaries
|
—
|
|
|
—
|
|
|
(24
|
)
|
|
—
|
|
|
(24
|
)
|
|||||
Income from operations
|
322
|
|
|
37
|
|
|
480
|
|
|
—
|
|
|
839
|
|
|||||
Interest expense
|
|
|
|
|
|
|
|
|
631
|
|
|||||||||
Debt modification and extinguishment costs and other (income) expense, net
|
|
|
|
|
|
|
|
|
49
|
|
|||||||||
Income before income taxes
|
|
|
|
|
|
|
|
|
$
|
159
|
|
|
Year Ended December 31, 2015
|
||||||||||||||||||
|
West
|
|
Texas
|
|
East
|
|
Consolidation
and
Elimination
|
|
Total
|
||||||||||
Revenues from external customers
|
$
|
2,089
|
|
|
$
|
2,344
|
|
|
$
|
2,039
|
|
|
$
|
—
|
|
|
$
|
6,472
|
|
Intersegment revenues
|
5
|
|
|
15
|
|
|
8
|
|
|
(28
|
)
|
|
—
|
|
|||||
Total operating revenues
|
$
|
2,094
|
|
|
$
|
2,359
|
|
|
$
|
2,047
|
|
|
$
|
(28
|
)
|
|
$
|
6,472
|
|
Commodity Margin
|
$
|
1,106
|
|
|
$
|
736
|
|
|
$
|
944
|
|
|
$
|
—
|
|
|
$
|
2,786
|
|
Add: Mark-to-market commodity activity, net and other
(1)
|
160
|
|
|
(120
|
)
|
|
(92
|
)
|
|
(29
|
)
|
|
(81
|
)
|
|||||
Less:
|
|
|
|
|
|
|
|
|
|
||||||||||
Plant operating expense
|
416
|
|
|
338
|
|
|
292
|
|
|
(28
|
)
|
|
1,018
|
|
|||||
Depreciation and amortization expense
|
250
|
|
|
204
|
|
|
184
|
|
|
—
|
|
|
638
|
|
|||||
Sales, general and other administrative expense
|
35
|
|
|
63
|
|
|
40
|
|
|
—
|
|
|
138
|
|
|||||
Other operating expenses
|
37
|
|
|
9
|
|
|
36
|
|
|
(2
|
)
|
|
80
|
|
|||||
(Income) from unconsolidated subsidiaries
|
—
|
|
|
—
|
|
|
(24
|
)
|
|
—
|
|
|
(24
|
)
|
|||||
Income from operations
|
528
|
|
|
2
|
|
|
324
|
|
|
1
|
|
|
855
|
|
|||||
Interest expense
|
|
|
|
|
|
|
|
|
628
|
|
|||||||||
Debt modification and extinguishment costs and other (income) expense, net
|
|
|
|
|
|
|
|
|
54
|
|
|||||||||
Income before income taxes
|
|
|
|
|
|
|
|
|
$
|
173
|
|
|
Year Ended December 31, 2014
|
||||||||||||||||||
|
West
|
|
Texas
|
|
East
|
|
Consolidation
and
Elimination
|
|
Total
|
||||||||||
Revenues from external customers
|
$
|
2,352
|
|
|
$
|
3,229
|
|
|
$
|
2,449
|
|
|
$
|
—
|
|
|
$
|
8,030
|
|
Intersegment revenues
|
6
|
|
|
23
|
|
|
47
|
|
|
(76
|
)
|
|
—
|
|
|||||
Total operating revenues
|
$
|
2,358
|
|
|
$
|
3,252
|
|
|
$
|
2,496
|
|
|
$
|
(76
|
)
|
|
$
|
8,030
|
|
Commodity Margin
(2)
|
$
|
1,050
|
|
|
$
|
760
|
|
|
$
|
949
|
|
|
$
|
—
|
|
|
$
|
2,759
|
|
Add: Mark-to-market commodity activity, net and other
(1)
|
220
|
|
|
142
|
|
|
48
|
|
|
(31
|
)
|
|
379
|
|
|||||
Less:
|
|
|
|
|
|
|
|
|
|
||||||||||
Plant operating expense
|
385
|
|
|
313
|
|
|
302
|
|
|
(31
|
)
|
|
969
|
|
|||||
Depreciation and amortization expense
|
245
|
|
|
191
|
|
|
168
|
|
|
(1
|
)
|
|
603
|
|
|||||
Sales, general and other administrative expense
|
41
|
|
|
64
|
|
|
39
|
|
|
—
|
|
|
144
|
|
|||||
Other operating expenses
|
50
|
|
|
5
|
|
|
32
|
|
|
1
|
|
|
88
|
|
|||||
Impairment losses
|
—
|
|
|
—
|
|
|
123
|
|
|
—
|
|
|
123
|
|
|||||
(Gain) on sale of assets, net
|
—
|
|
|
—
|
|
|
(753
|
)
|
|
—
|
|
|
(753
|
)
|
|||||
(Income) from unconsolidated subsidiaries
|
—
|
|
|
—
|
|
|
(25
|
)
|
|
—
|
|
|
(25
|
)
|
|||||
Income from operations
|
549
|
|
|
329
|
|
|
1,111
|
|
|
—
|
|
|
1,989
|
|
|||||
Interest expense
|
|
|
|
|
|
|
|
|
645
|
|
|||||||||
Debt extinguishment costs and other (income) expense, net
|
|
|
|
|
|
|
|
|
361
|
|
|||||||||
Income before income taxes
|
|
|
|
|
|
|
|
|
$
|
983
|
|
(1)
|
Includes
$(2) million
,
$(2) million
and
$(5) million
of lease levelization and
$122 million
,
$20 million
and
$14 million
of amortization expense for the years ended
December 31, 2016
,
2015
and
2014
, respectively.
|
(2)
|
Our East segment includes Commodity Margin of $
81 million
for the year ended
December 31, 2014
related to the
six
power plants in our East segment that were sold in July 2014.
|
17.
|
Quarterly Consolidated Financial Data (unaudited)
|
|
Quarter Ended
|
||||||||||||||
|
December 31
|
|
September 30
|
|
June 30
|
|
March 31
|
||||||||
|
(in millions, except per share amounts)
|
||||||||||||||
2016
|
|
|
|
|
|
|
|
||||||||
Operating revenues
|
$
|
1,582
|
|
|
$
|
2,355
|
|
|
$
|
1,164
|
|
|
$
|
1,615
|
|
Income from operations
(1)
|
$
|
234
|
|
|
$
|
462
|
|
|
$
|
140
|
|
|
$
|
3
|
|
Net income (loss) attributable to Calpine
|
$
|
24
|
|
|
$
|
295
|
|
|
$
|
(29
|
)
|
|
$
|
(198
|
)
|
Net income (loss) per common share attributable to Calpine — Basic
|
$
|
0.07
|
|
|
$
|
0.83
|
|
|
$
|
(0.08
|
)
|
|
$
|
(0.56
|
)
|
Net income (loss) per common share attributable to Calpine — Diluted
|
$
|
0.07
|
|
|
$
|
0.83
|
|
|
$
|
(0.08
|
)
|
|
$
|
(0.56
|
)
|
|
|
|
|
|
|
|
|
||||||||
2015
|
|
|
|
|
|
|
|
||||||||
Operating revenues
|
$
|
1,436
|
|
|
$
|
1,948
|
|
|
$
|
1,442
|
|
|
$
|
1,646
|
|
Income from operations
|
$
|
22
|
|
|
$
|
466
|
|
|
$
|
201
|
|
|
$
|
166
|
|
Net income (loss) attributable to Calpine
|
$
|
(47
|
)
|
|
$
|
273
|
|
|
$
|
19
|
|
|
$
|
(10
|
)
|
Net income (loss) per common share attributable to Calpine — Basic
|
$
|
(0.13
|
)
|
|
$
|
0.77
|
|
|
$
|
0.05
|
|
|
$
|
(0.03
|
)
|
Net income (loss) per common share attributable to Calpine — Diluted
|
$
|
(0.13
|
)
|
|
$
|
0.76
|
|
|
$
|
0.05
|
|
|
$
|
(0.03
|
)
|
(1)
|
We recorded a gain on sale of assets, net of
$(157) million
in connection with the sale of the Mankato Power Plant which is included in income from operations on our Consolidated Statement of Operations for the year ended
December 31, 2016
.
|
Description
|
Balance at
Beginning
of Year
|
|
Charged to
Expense
|
|
Charged to Other Accounts
|
|
Deductions
|
|
Balance at
End of Year
|
||||||||||
|
(in millions)
|
||||||||||||||||||
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
||||||||||
Allowance for doubtful accounts
|
$
|
2
|
|
|
$
|
4
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
6
|
|
Deferred tax asset valuation allowance
|
1,637
|
|
|
(56
|
)
|
|
—
|
|
|
—
|
|
|
1,581
|
|
|||||
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
||||||||||
Allowance for doubtful accounts
|
$
|
4
|
|
|
$
|
(2
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2
|
|
Deferred tax asset valuation allowance
|
1,836
|
|
|
(199
|
)
|
|
—
|
|
|
—
|
|
|
1,637
|
|
|||||
Year Ended December 31, 2014
|
|
|
|
|
|
|
|
|
|
||||||||||
Allowance for doubtful accounts
|
$
|
5
|
|
|
$
|
(1
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4
|
|
Deferred tax asset valuation allowance
|
2,246
|
|
|
(410
|
)
|
|
—
|
|
|
—
|
|
|
1,836
|
|
|
CALPINE CORPORATION
|
|
|
|
|
|
By:
|
/s/ ZAMIR RAUF
|
|
|
Name: Zamir Rauf
Title: Executive Vice President and Chief Financial Officer |
|
THE GUARANTORS SET FORTH ON
|
|
|
ANNEX I & II TO THIS SIGNATURE
|
|
|
PAGE
|
|
|
|
|
|
By:
|
/s/ ZAMIR RAUF
|
|
|
Name: Zamir Rauf
Title: Executive Vice President and Chief Financial Officer |
|
THE GUARANTORS SET FORTH ON
|
|
|
ANNEX III & IV TO THIS SIGNATURE
|
|
|
PAGE
|
|
|
|
|
|
By:
|
/s/ HETHER BENJAMIN BROWN
|
|
|
Name: Hether Benjamin-Brown
Title: Vice President |
Name of Guarantor
|
Anacapa Land Company, LLC
|
Anderson Springs Energy Company
|
Aviation Funding Corp.
|
Baytown Energy Center, LLC
|
CalGen Expansion Company, LLC
|
CalGen Project Equipment Finance Company Three, LLC
|
Calpine Administrative Services Company, Inc.
|
Calpine Auburndale Holdings, LLC
|
Calpine Bethlehem, LLC
|
Calpine c*Power, Inc.
|
Calpine CalGen Holdings, Inc.
|
Calpine Calistoga Holdings, LLC
|
Calpine Central Texas GP, Inc.
|
Calpine Central, Inc.
|
Calpine Central-Texas, Inc.
|
Calpine Cogeneration Corporation
|
Calpine Eastern Corporation
|
Calpine Edinburg, Inc.
|
Calpine Energy Services GP, LLC
|
Calpine Energy Services LP, LLC
|
Calpine Energy Services, L.P.
|
Calpine Fuels Corporation
|
Calpine Generating Company, LLC
|
Calpine Geysers Company, L.P.
|
Calpine Gilroy 1, Inc.
|
Calpine Gilroy 2, Inc.
|
Calpine Global Services Company, Inc.
|
Calpine Hidalgo Energy Center, L.P.
|
Calpine Hidalgo Holdings, Inc.
|
Calpine Hidalgo, Inc.
|
Calpine Kennedy Operators, Inc.
|
Calpine KIA, Inc.
|
Calpine King City, Inc.
|
Name of Guarantor
|
Calpine King City, LLC
|
Calpine Leasing Inc.
|
Calpine Long Island, Inc.
|
Calpine Magic Valley Pipeline, LLC
|
Calpine Mid-Atlantic Energy, LLC
|
Calpine Mid-Atlantic Generation, LLC
|
Calpine Mid-Atlantic Marketing, LLC
|
Calpine MVP, LLC
|
Calpine Newark, LLC
|
Calpine New Jersey Generation, LLC
|
Calpine Northbrook Holdings Corporation
|
Calpine Northbrook Investors, LLC
|
Calpine Northbrook Project Holdings, LLC
|
Calpine Operations Management Company, Inc.
|
Calpine Power Company
|
Calpine Power Management, LLC
|
Calpine Power, Inc.
|
Calpine PowerAmerica, LLC
|
Calpine PowerAmerica-CA, LLC
|
Calpine PowerAmerica-ME, LLC
|
Calpine Project Holdings, Inc.
|
Calpine Solar, LLC
|
Calpine Stony Brook Operators, Inc.
|
Calpine Stony Brook, Inc.
|
Calpine TCCL Holdings, Inc.
|
Calpine Texas Pipeline GP, Inc.
|
Calpine Texas Pipeline LP, Inc.
|
Calpine Texas Pipeline, L.P.
|
Calpine University Power, Inc.
|
Calpine Vineland Solar, LLC
|
CES Marketing IX, LLC
|
CES Marketing X, LLC
|
Channel Energy Center, LLC
|
Corpus Christi Cogeneration, LLC
|
CPN 3
rd
Turbine, Inc.
|
Name of Guarantor
|
CPN Acadia, Inc.
|
CPN Cascade, Inc.
|
CPN Clear Lake, Inc.
|
CPN Pipeline Company
|
CPN Pryor Funding Corporation
|
CPN Telephone Flat, Inc.
|
Delta Energy Center, LLC
|
Freestone Power Generation, LLC
|
GEC Bethpage Inc.
|
Geysers Power Company, LLC
|
Geysers Power I Company
|
Hillabee Energy Center, LLC
|
Idlewild Fuel Management Corp.
|
JMC Bethpage, Inc.
|
Los Medanos Energy Center LLC
|
Magic Valley Pipeline, L.P.
|
Modoc Power, Inc.
|
New Development Holdings, LLC
|
NTC Five, Inc.
|
Pastoria Energy Center, LLC
|
Pastoria Energy Facility L.L.C.
|
Pine Bluff Energy, LLC
|
RockGen Energy LLC
|
South Point Energy Center, LLC
|
South Point Holdings, LLC
|
Stony Brook Cogeneration, Inc.
|
Stony Brook Fuel Management Corp.
|
Sutter Dryers, Inc.
|
Texas City Cogeneration, LLC
|
Texas Cogeneration Five, Inc.
|
Texas Cogeneration One Company
|
Thermal Power Company
|
Zion Energy LLC
|
Name of Guarantor
|
Deer Park Energy Center LLC
|
Deer Park Holdings, LLC
|
Metcalf Energy Center, LLC
|
Metcalf Holdings, LLC
|
Name of Guarantor
|
Calpine Construction Management Company, Inc.
|
Calpine Mid-Atlantic Operating, LLC
|
Name of Guarantor
|
Calpine Operating Services Company, Inc.
|
|
CREDIT SUISSE AG, CAYMAN
|
|
|
ISLANDS BRANCH, as initial New Lender
|
|
|
|
|
|
By:
|
/s/ MIKHAIL FAYBUSOVICH
|
|
|
Name: Mikhail Faybusovich
Title: Authorized Signatory |
|
|
|
|
By:
|
/s/ WARREN VAN HEYST
|
|
|
Name: Warren Van Heyst
Title: Authorized Signatory |
|
MORGAN STANLEY SENIOR FUNDING, INC.
|
|
|
as Administrative Agent
|
|
|
|
|
|
By:
|
/s/ CODY GUNSCH
|
|
|
Name: Cody Gunsch
Title: Vice President |
¨
|
Consent
:
The undersigned Lender (including any New Lender) hereby irrevocably and unconditionally approves of and consents to the Amendment with respect to all Term Loans held by such Lender.
|
¨
|
Decline
:
The undersigned Lender declines to participate and elects to have all of the outstanding principal amount of the Term Loans held by such Lender be assigned on the Amendment No. 1 Effective Date to a New Lender and is hereby deemed to execute the Assignment Agreement.
|
Name of Lender
:
____________________________________________________
by
____________________________________________________
Name:
Title:
|
For any Institution requiring a second signature line:
by
____________________________________________________
Name:
Title:
|
|
CALPINE CORPORATION
|
|
|
|
|
|
By:
|
/s/ ZAMIR RAUF
|
|
|
Name: Zamir Rauf
Title: Executive Vice President and Chief Financial Officer |
|
THE GUARANTORS SET FORTH ON
|
|
|
ANNEX I & II TO THIS SIGNATURE
|
|
|
PAGE
|
|
|
|
|
|
By:
|
/s/ ZAMIR RAUF
|
|
|
Name: Zamir Rauf
Title: Executive Vice President and Chief Financial Officer |
|
THE GUARANTORS SET FORTH ON
|
|
|
ANNEX III & IV TO THIS SIGNATURE
|
|
|
PAGE
|
|
|
|
|
|
By:
|
/s/ HETHER BENJAMIN BROWN
|
|
|
Name: Hether Benjamin-Brown
Title: Vice President |
Name of Guarantor
|
Anacapa Land Company, LLC
|
Anderson Springs Energy Company
|
Aviation Funding Corp.
|
Baytown Energy Center, LLC
|
CalGen Expansion Company, LLC
|
CalGen Project Equipment Finance Company Three, LLC
|
Calpine Administrative Services Company, Inc.
|
Calpine Auburndale Holdings, LLC
|
Calpine Bethlehem, LLC
|
Calpine c*Power, Inc.
|
Calpine CalGen Holdings, Inc.
|
Calpine Calistoga Holdings, LLC
|
Calpine Central Texas GP, Inc.
|
Calpine Central, Inc.
|
Calpine Central-Texas, Inc.
|
Calpine Cogeneration Corporation
|
Calpine Eastern Corporation
|
Calpine Edinburg, Inc.
|
Calpine Energy Services GP, LLC
|
Calpine Energy Services LP, LLC
|
Calpine Energy Services, L.P.
|
Calpine Fuels Corporation
|
Calpine Generating Company, LLC
|
Calpine Geysers Company, L.P.
|
Calpine Gilroy 1, Inc.
|
Calpine Gilroy 2, Inc.
|
Calpine Global Services Company, Inc.
|
Calpine Hidalgo Energy Center, L.P.
|
Calpine Hidalgo Holdings, Inc.
|
Calpine Hidalgo, Inc.
|
Calpine Kennedy Operators, Inc.
|
Calpine KIA, Inc.
|
Calpine King City, Inc.
|
Calpine King City, LLC
|
Calpine Leasing Inc.
|
Calpine Long Island, Inc.
|
Calpine Magic Valley Pipeline, LLC
|
Name of Guarantor
|
Calpine Mid-Atlantic Energy, LLC
|
Calpine Mid-Atlantic Generation, LLC
|
Calpine Mid-Atlantic Marketing, LLC
|
Calpine MVP, LLC
|
Calpine Newark, LLC
|
Calpine New Jersey Generation, LLC
|
Calpine Northbrook Holdings Corporation
|
Calpine Northbrook Investors, LLC
|
Calpine Northbrook Project Holdings, LLC
|
Calpine Operations Management Company, Inc.
|
Calpine Power Company
|
Calpine Power Management, LLC
|
Calpine Power, Inc.
|
Calpine PowerAmerica, LLC
|
Calpine PowerAmerica-CA, LLC
|
Calpine PowerAmerica-ME, LLC
|
Calpine Project Holdings, Inc.
|
Calpine Solar, LLC
|
Calpine Stony Brook Operators, Inc.
|
Calpine Stony Brook, Inc.
|
Calpine TCCL Holdings, Inc.
|
Calpine Texas Pipeline GP, Inc.
|
Calpine Texas Pipeline LP, Inc.
|
Calpine Texas Pipeline, L.P.
|
Calpine University Power, Inc.
|
Calpine Vineland Solar, LLC
|
CES Marketing IX, LLC
|
CES Marketing X, LLC
|
Channel Energy Center, LLC
|
Corpus Christi Cogeneration, LLC
|
CPN 3
rd
Turbine, Inc.
|
CPN Acadia, Inc.
|
CPN Cascade, Inc.
|
CPN Clear Lake, Inc.
|
CPN Pipeline Company
|
CPN Pryor Funding Corporation
|
CPN Telephone Flat, Inc.
|
Delta Energy Center, LLC
|
Freestone Power Generation, LLC
|
GEC Bethpage Inc.
|
Name of Guarantor
|
Geysers Power Company, LLC
|
Geysers Power I Company
|
Hillabee Energy Center, LLC
|
Idlewild Fuel Management Corp.
|
JMC Bethpage, Inc.
|
Los Medanos Energy Center LLC
|
Magic Valley Pipeline, L.P.
|
Modoc Power, Inc.
|
New Development Holdings, LLC
|
NTC Five, Inc.
|
Pastoria Energy Center, LLC
|
Pastoria Energy Facility L.L.C.
|
Pine Bluff Energy, LLC
|
RockGen Energy LLC
|
South Point Energy Center, LLC
|
South Point Holdings, LLC
|
Stony Brook Cogeneration, Inc.
|
Stony Brook Fuel Management Corp.
|
Sutter Dryers, Inc.
|
Texas City Cogeneration, LLC
|
Texas Cogeneration Five, Inc.
|
Texas Cogeneration One Company
|
Thermal Power Company
|
Zion Energy LLC
|
Name of Guarantor
|
Deer Park Energy Center LLC
|
Deer Park Holdings, LLC
|
Metcalf Energy Center, LLC
|
Metcalf Holdings, LLC
|
Name of Guarantor
|
Calpine Construction Management Company, Inc.
|
Calpine Mid-Atlantic Operating, LLC
|
Name of Guarantor
|
Calpine Operating Services Company, Inc.
|
|
CREDIT SUISSE AG, CAYMAN
|
|
|
ISLANDS BRANCH, as initial New Lender
|
|
|
|
|
|
By:
|
/s/ MIKHAIL FAYBUSOVICH
|
|
|
Name: Mikhail Faybusovich
Title: Authorized Signatory |
|
|
|
|
By:
|
/s/ WARREN VAN HEYST
|
|
|
Name: Warren Van Heyst
Title: Authorized Signatory |
|
MORGAN STANLEY SENIOR FUNDING, INC.
|
|
|
as Administrative Agent
|
|
|
|
|
|
By:
|
/s/ CODY GUNSCH
|
|
|
Name: Cody Gunsch
Title: Vice President |
¨
|
Consent
:
The undersigned Lender (including any New Lender) hereby irrevocably and unconditionally approves of and consents to the Amendment with respect to all Term Loans held by such Lender.
|
¨
|
Decline
:
The undersigned Lender declines to participate and elects to have all of the outstanding principal amount of the Term Loans held by such Lender be assigned on the Amendment No. 1 Effective Date to a New Lender and is hereby deemed to execute the Assignment Agreement.
|
Name of Lender
:
____________________________________________________
by
____________________________________________________
Name:
Title:
|
For any Institution requiring a second signature line:
by
____________________________________________________
Name:
Title:
|
|
CALPINE CORPORATION
|
|
|
|
|
|
By:
|
/s/ ZAMIR RAUF
|
|
|
Name: Zamir Rauf
Title: Executive Vice President and Chief Financial Officer |
|
THE GUARANTORS SET FORTH ON
|
|
|
ANNEX I & II TO THIS SIGNATURE
|
|
|
PAGE
|
|
|
|
|
|
By:
|
/s/ ZAMIR RAUF
|
|
|
Name: Zamir Rauf
Title: Executive Vice President and Chief Financial Officer |
|
THE GUARANTORS SET FORTH ON
|
|
|
ANNEX III & IV TO THIS SIGNATURE
|
|
|
PAGE
|
|
|
|
|
|
By:
|
/s/ HETHER BENJAMIN BROWN
|
|
|
Name: Hether Benjamin-Brown
Title: Vice President |
Name of Guarantor
|
Anacapa Land Company, LLC
|
Anderson Springs Energy Company
|
Aviation Funding Corp.
|
Baytown Energy Center, LLC
|
CalGen Expansion Company, LLC
|
CalGen Project Equipment Finance Company Three, LLC
|
Calpine Administrative Services Company, Inc.
|
Calpine Auburndale Holdings, LLC
|
Calpine Bethlehem, LLC
|
Calpine c*Power, Inc.
|
Calpine CalGen Holdings, Inc.
|
Calpine Calistoga Holdings, LLC
|
Calpine Central Texas GP, Inc.
|
Calpine Central, Inc.
|
Calpine Central-Texas, Inc.
|
Calpine Cogeneration Corporation
|
Calpine Eastern Corporation
|
Calpine Edinburg, Inc.
|
Calpine Energy Services GP, LLC
|
Calpine Energy Services LP, LLC
|
Calpine Energy Services, L.P.
|
Calpine Fuels Corporation
|
Calpine Generating Company, LLC
|
Calpine Geysers Company, L.P.
|
Calpine Gilroy 1, Inc.
|
Calpine Gilroy 2, Inc.
|
Calpine Global Services Company, Inc.
|
Calpine Hidalgo Energy Center, L.P.
|
Calpine Hidalgo Holdings, Inc.
|
Calpine Hidalgo, Inc.
|
Calpine Kennedy Operators, Inc.
|
Calpine KIA, Inc.
|
Calpine King City, Inc.
|
Calpine King City, LLC
|
Calpine Leasing Inc.
|
Calpine Long Island, Inc.
|
Calpine Magic Valley Pipeline, LLC
|
Name of Guarantor
|
Calpine Mid-Atlantic Energy, LLC
|
Calpine Mid-Atlantic Generation, LLC
|
Calpine Mid-Atlantic Marketing, LLC
|
Calpine MVP, LLC
|
Calpine Newark, LLC
|
Calpine New Jersey Generation, LLC
|
Calpine Northbrook Holdings Corporation
|
Calpine Northbrook Investors, LLC
|
Calpine Northbrook Project Holdings, LLC
|
Calpine Operations Management Company, Inc.
|
Calpine Power Company
|
Calpine Power Management, LLC
|
Calpine Power, Inc.
|
Calpine PowerAmerica, LLC
|
Calpine PowerAmerica-CA, LLC
|
Calpine PowerAmerica-ME, LLC
|
Calpine Project Holdings, Inc.
|
Calpine Solar, LLC
|
Calpine Stony Brook Operators, Inc.
|
Calpine Stony Brook, Inc.
|
Calpine TCCL Holdings, Inc.
|
Calpine Texas Pipeline GP, Inc.
|
Calpine Texas Pipeline LP, Inc.
|
Calpine Texas Pipeline, L.P.
|
Calpine University Power, Inc.
|
Calpine Vineland Solar, LLC
|
CES Marketing IX, LLC
|
CES Marketing X, LLC
|
Channel Energy Center, LLC
|
Corpus Christi Cogeneration, LLC
|
CPN 3
rd
Turbine, Inc.
|
CPN Acadia, Inc.
|
CPN Cascade, Inc.
|
CPN Clear Lake, Inc.
|
CPN Pipeline Company
|
CPN Pryor Funding Corporation
|
CPN Telephone Flat, Inc.
|
Delta Energy Center, LLC
|
Freestone Power Generation, LLC
|
GEC Bethpage Inc.
|
Name of Guarantor
|
Geysers Power Company, LLC
|
Geysers Power I Company
|
Hillabee Energy Center, LLC
|
Idlewild Fuel Management Corp.
|
JMC Bethpage, Inc.
|
Los Medanos Energy Center LLC
|
Magic Valley Pipeline, L.P.
|
Modoc Power, Inc.
|
New Development Holdings, LLC
|
NTC Five, Inc.
|
Pastoria Energy Center, LLC
|
Pastoria Energy Facility L.L.C.
|
Pine Bluff Energy, LLC
|
RockGen Energy LLC
|
South Point Energy Center, LLC
|
South Point Holdings, LLC
|
Stony Brook Cogeneration, Inc.
|
Stony Brook Fuel Management Corp.
|
Sutter Dryers, Inc.
|
Texas City Cogeneration, LLC
|
Texas Cogeneration Five, Inc.
|
Texas Cogeneration One Company
|
Thermal Power Company
|
Zion Energy LLC
|
Name of Guarantor
|
Deer Park Energy Center LLC
|
Deer Park Holdings, LLC
|
Metcalf Energy Center, LLC
|
Metcalf Holdings, LLC
|
Name of Guarantor
|
Calpine Construction Management Company, Inc.
|
Calpine Mid-Atlantic Operating, LLC
|
Name of Guarantor
|
Calpine Operating Services Company, Inc.
|
|
CREDIT SUISSE AG, CAYMAN
|
|
|
ISLANDS BRANCH, as initial New Lender
|
|
|
|
|
|
By:
|
/s/ MIKHAIL FAYBUSOVICH
|
|
|
Name: Mikhail Faybusovich
Title: Authorized Signatory |
|
|
|
|
By:
|
/s/ WARREN VAN HEYST
|
|
|
Name: Warren Van Heyst
Title: Authorized Signatory |
|
CITIBANK, N.A.,
|
|
|
as Administrative Agent
|
|
|
|
|
|
By:
|
/s/ KIRKWOOD ROLAND
|
|
|
Name: Kirkwood Roland
Title: Managing Director & Vice President |
¨
|
Consent
:
The undersigned Lender (including any New Lender) hereby irrevocably and unconditionally approves of and consents to the Amendment with respect to all Term Loans held by such Lender.
|
¨
|
Decline
:
The undersigned Lender declines to participate and elects to have all of the outstanding principal amount of the Term Loans held by such Lender be assigned on the Amendment No. 1 Effective Date to a New Lender and is hereby deemed to execute the Assignment Agreement.
|
Name of Lender
:
____________________________________________________
by
____________________________________________________
Name:
Title:
|
For any Institution requiring a second signature line:
by
____________________________________________________
Name:
Title:
|
Participant:
|
[
l
]
|
Corporation:
|
Calpine Corporation
|
Notice:
|
You have been granted the following Performance Share Units in accordance with the terms of this notice, the Performance Share Unit Award Agreement attached hereto as
Attachment A
(such notice and agreement, collectively, this “
Agreement
”) and the Plan identified below.
|
Type of Award:
|
Performance-based Restricted Stock Units, referred to herein as “
Performance Share Units
”. A Performance Share Unit is an unfunded and unsecured obligation of the Corporation to pay the cash equivalent of up to two (2) shares of Common Stock, as determined in accordance with this Agreement and subject to the terms and conditions of this Agreement and those of the Plan.
|
Plan:
|
Amended and Restated Calpine Corporation 2008 Equity Incentive Plan.
|
Grant:
|
Grant Date
:
[
l
]
|
and Agreement:
|
The undersigned Participant acknowledges receipt of, and understands and agrees to, the terms and conditions of this Agreement and the Plan.
|
|
CALPINE CORPORATION
|
|
PARTICIPANT
|
|
|
|
|
Name:
|
|
Name:
|
|
Title:
|
|
|
|
TSR Percentile Ranking
|
|
Earned Percentage
|
90
th
percentile
|
|
200%
|
80
th
percentile
|
|
175%
|
70
th
percentile
|
|
150%
|
60
th
percentile
|
|
125%
|
50
th
percentile
|
|
100%
|
40
th
percentile
|
|
75%
|
30
th
percentile
|
|
50%
|
Less than 30
th
percentile
|
|
0%
|
IPP Sector TSR Ranking
|
|
Maximum Earned Percentage
|
|
Minimum Earned Percentage
|
#1
|
|
200%
|
|
50%
|
#2
|
|
200%
|
|
25%
|
#3
|
|
175%
|
|
0%
|
Participant:
|
W. Thaddeus Miller
|
Corporation:
|
Calpine Corporation
|
Notice:
|
You have been granted the following Performance Share Units in accordance with the terms of this notice, the Performance Share Unit Award Agreement attached hereto as
Attachment A
(such notice and agreement, collectively, this “
Agreement
”) and the Plan identified below.
|
Type of Award:
|
Performance-based Restricted Stock Units, referred to herein as “
Performance Share Units
”. A Performance Share Unit is an unfunded and unsecured obligation of the Corporation to pay the cash equivalent of up to two (2) shares of Common Stock, as determined in accordance with this Agreement and subject to the terms and conditions of this Agreement and those of the Plan.
|
Plan:
|
Amended and Restated Calpine Corporation 2008 Equity Incentive Plan.
|
Grant:
|
Grant Date
:
[
l
]
|
and Agreement:
|
The undersigned Participant acknowledges receipt of, and understands and agrees to, the terms and conditions of this Agreement and the Plan.
|
|
CALPINE CORPORATION
|
|
PARTICIPANT
|
|
|
|
|
Name:
|
|
Name:
|
|
Title:
|
|
|
|
TSR Percentile Ranking
|
|
Earned Percentage
|
90
th
percentile
|
|
200%
|
80
th
percentile
|
|
175%
|
70
th
percentile
|
|
150%
|
60
th
percentile
|
|
125%
|
50
th
percentile
|
|
100%
|
40
th
percentile
|
|
75%
|
30
th
percentile
|
|
50%
|
Less than 30
th
percentile
|
|
0%
|
IPP Sector TSR Ranking
|
|
Maximum Earned Percentage
|
|
Minimum Earned Percentage
|
#1
|
|
200%
|
|
50%
|
#2
|
|
200%
|
|
25%
|
#3
|
|
175%
|
|
0%
|
|
|
CALPINE CORPORATION
|
|
|
|
By:
|
/s/ JACK A. FUSCO
|
|
|
|
|
|
|
Printed Name:
|
JACK A. FUSCO
|
|
|
|
|
|
|
Title
|
CEO
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
||||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
Earnings
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Income before income taxes
|
|
$
|
159
|
|
|
$
|
173
|
|
|
$
|
983
|
|
|
$
|
20
|
|
|
$
|
218
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Income from unconsolidated investments in power plants
|
|
(24
|
)
|
|
(24
|
)
|
|
(25
|
)
|
|
(30
|
)
|
|
(28
|
)
|
|||||
Interest capitalized
|
|
(21
|
)
|
|
(15
|
)
|
|
(19
|
)
|
|
(38
|
)
|
|
(38
|
)
|
|||||
Preferred securities dividend requirements of subsidiaries
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
(1
|
)
|
|||||
Add:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed charges
|
|
662
|
|
|
654
|
|
|
678
|
|
|
749
|
|
|
791
|
|
|||||
Amortization of capitalized interest
|
|
28
|
|
|
27
|
|
|
29
|
|
|
30
|
|
|
30
|
|
|||||
Distributions from equity method investments
|
|
21
|
|
|
25
|
|
|
13
|
|
|
27
|
|
|
29
|
|
|||||
Total Earnings:
|
|
$
|
825
|
|
|
$
|
840
|
|
|
$
|
1,659
|
|
|
$
|
757
|
|
|
$
|
1,001
|
|
Fixed Charges
(1)
:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense
|
|
$
|
631
|
|
|
$
|
628
|
|
|
$
|
645
|
|
|
$
|
696
|
|
|
$
|
736
|
|
Interest capitalized
|
|
21
|
|
|
15
|
|
|
19
|
|
|
38
|
|
|
38
|
|
|||||
Approximation of interest in rental expense
|
|
10
|
|
|
11
|
|
|
14
|
|
|
15
|
|
|
17
|
|
|||||
Total Fixed Charges:
|
|
$
|
662
|
|
|
$
|
654
|
|
|
$
|
678
|
|
|
$
|
749
|
|
|
$
|
791
|
|
Ratio of Earnings to Fixed Charges:
|
|
1.25
|
|
|
1.28
|
|
|
2.45
|
|
|
1.01
|
|
|
1.27
|
|
(1)
|
Fixed charges include the portion of rental expense that management believes is representative of the interest component.
|
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
|
|
Brazos Valley Energy LLC
|
|
Delaware
|
|
Buffalo Springs Wind, LLC
|
|
Delaware
|
|
Butter Creek Energy Center, LLC
|
|
Delaware
|
|
Byron Highway Energy Center, LLC
|
|
Delaware
|
|
CalGen Expansion Company, LLC
|
|
Delaware
|
|
CalGen Project Equipment Finance Company Three, LLC
|
|
Delaware
|
|
Callahan Energy, 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
|
|
Subsidiaries of the Company
|
|
|
|
|
|
|
|
Entity
|
|
Jurisdiction
|
|
Calpine Energy Services, L.P.
|
|
Delaware
|
|
Calpine Energy Solutions, LLC
|
|
California
|
|
Calpine Fore River Energy Center, LLC
|
|
Delaware
|
|
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, L.P.
|
|
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 1, LLC
|
|
Delaware
|
|
Calpine King City 2, LLC
|
|
Delaware
|
|
Calpine King City Cogen, LLC
|
|
Delaware
|
|
Calpine King City, Inc.
|
|
Delaware
|
|
Calpine King City, LLC
|
|
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
|
|
Subsidiaries of the Company
|
|
|
|
|
|
|
|
Entity
|
|
Jurisdiction
|
|
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
|
|
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 Riverside Holdings, LLC
|
|
Delaware
|
|
Calpine Russell City, LLC
|
|
Delaware
|
|
Calpine Securities Company, L.P.
|
|
Delaware
|
|
Calpine Siskiyou Geothermal Partners, L.P.
|
|
California
|
|
Calpine Solano Solar, 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
|
|
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
|
|
Subsidiaries of the Company
|
|
|
|
|
|
|
|
Entity
|
|
Jurisdiction
|
|
CPN Insurance Corporation
|
|
Hawaii
|
|
CPN Pipeline Company
|
|
Delaware
|
|
CPN Pryor Funding Corporation
|
|
Delaware
|
|
CPN Telephone Flat, Inc.
|
|
Delaware
|
|
CPN Wild Horse Geothermal LLC
|
|
Delaware
|
|
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 Power Company, LLC
|
|
Delaware
|
|
Geysers Power I Company
|
|
Delaware
|
|
Gilroy Energy Center, LLC
|
|
Delaware
|
|
Goose Haven Energy Center, 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
|
|
Hillabee Energy Center, LLC
|
|
Delaware
|
|
Horizon Hill Wind, LLC
|
|
Delaware
|
|
Idlewild Fuel Management Corp.
|
|
Delaware
|
|
JMC Bethpage, Inc.
|
|
Delaware
|
|
Johanna Energy Center, LLC
|
|
Delaware
|
|
Johanna Energy Storage, LLC
|
|
Delaware
|
|
KC Wind, LLC
|
|
Delaware
|
|
KIAC Partners
|
|
New York
|
|
King City Holdings, 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
|
|
Maple Grove Wind, 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
|
|
New Development Holdings, LLC
|
|
Delaware
|
|
New Steamboat Holdings, LLC
|
|
Delaware
|
|
Nissequogue Cogen Partners
|
|
New York
|
|
Subsidiaries of the Company
|
|
|
|
|
|
|
|
Entity
|
|
Jurisdiction
|
|
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
|
|
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
|
|
Southfork Wind, 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
|
|
Thermal Power Company
|
|
California
|
|
Washington Parish Energy Center One, 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
|
|
/s/ PricewaterhouseCoopers LLP
|
|
Houston, Texas
|
February 9, 2017
|
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
|
|