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EX-32.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER - CALPINE CORPcpn_exhibit321x03312017.htm
EX-31.2 - SECTION 302 CERTIFICATION OF CFO - CALPINE CORPcpn_exhibit312x03312017.htm
EX-31.1 - SECTION 302 CERTIFICATION OF CEO - CALPINE CORPcpn_exhibit311x03312017.htm
EX-10.6 - FORM OF NON-QUALIFIED OPTION AGREEMENT CHARLIE GATES - CALPINE CORPcalpine2017nqoptiongates.htm
EX-10.5 - FORM OF NON-QUALIFIED OPTION AGREEMENT SENIOR EMPLOYEES - CALPINE CORPcalpine2017nqoptionseniore.htm
EX-10.4 - FORM OF NON-QUALIFIED OPTION AGREEMENT THAD MILLER - CALPINE CORPcalpine2017nqoptionmiller.htm
EX-10.3 - FORM OF PERFORMANCE SHARE UNIT AWARD AGREEMENT SENIOR EMPLOYEES - CALPINE CORPcalpine2017psuawarddesigna.htm
EX-10.2 - FORM OF PERFORMANCE SHARE UNIT AWARD AGREEMENT THAD MILLER - CALPINE CORPcalpine2017psuawardmiller.htm


 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549 
____________________
Form 10-Q
(Mark One)
[X]
 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
 
 
OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
 
For the quarterly period ended March 31, 2017
 
 
 
 
Or
 
 
 
[    ]
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
 
 
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File No. 001-12079
______________________
cpnimage1a03.jpg
Calpine Corporation
(A Delaware Corporation)
I.R.S. Employer Identification No. 77-0212977
717 Texas Avenue, Suite 1000, Houston, Texas 77002
Telephone: (713) 830-2000
Not Applicable
(Former Address)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes [X]    No [    ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes [X]    No [    ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
[X]
 
Accelerated filer            
[    ]
Non-accelerated filer
[   ]
(Do not check if a smaller reporting company)
Smaller reporting company 
[    ]
Emerging growth company
[   ]
 
 
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes [    ]    No [X]
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: 360,793,424 shares of common stock, par value $0.001, were outstanding as of April 24, 2017.
 




CALPINE CORPORATION AND SUBSIDIARIES
REPORT ON FORM 10-Q
For the Quarter Ended March 31, 2017
INDEX
 
 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

i



DEFINITIONS
As used in this report for the quarter ended March 31, 2017 (this “Report”), the following abbreviations and terms have the meanings as listed below. Additionally, the terms “Calpine,” “we,” “us” and “our” refer to Calpine Corporation and its consolidated subsidiaries, unless the context clearly indicates otherwise. The term “Calpine Corporation” refers only to Calpine Corporation and not to any of its subsidiaries. Unless and as otherwise stated, any references in this Report to any agreement means such agreement and all schedules, exhibits and attachments in each case as amended, restated, supplemented or otherwise modified to the date of filing this Report.
ABBREVIATION
 
DEFINITION
2016 Form 10-K
 
Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2016, filed with the SEC on February 10, 2017
 
 
 
2017 First Lien Term Loan
 
The $550 million first lien senior secured term loan, dated December 1, 2016, among Calpine Corporation, as borrower, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent and MUFG Union Bank, N.A., as collateral agent, partially repaid on March 16, 2017
 
 
 
2019 First Lien Term Loan
 
The $400 million first lien senior secured term loan, dated February 3, 2017, among Calpine Corporation, as borrower, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent and MUFG Union Bank, N.A., as collateral agent
 
 
 
2022 First Lien Notes
 
The $750 million aggregate principal amount of 6.0% senior secured notes due 2022, issued October 31, 2013
 
 
 
2023 First Lien Notes
 
The $1.2 billion aggregate principal amount of 7.875% senior secured notes due 2023, issued January 14, 2011, repaid in series of transactions on November 7, 2012, December 2, 2013, December 4, 2014, February 3, 2015, December 7, 2015, December 19, 2016 and March 6, 2017
 
 
 
2023 First Lien Term Loan
 
The $550 million first lien senior secured term loan, dated December 15, 2015, among Calpine Corporation, as borrower, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent
 
 
 
2023 First Lien Term Loans
 
Collectively, the 2023 First Lien Term Loan and the New 2023 First Lien Term Loan
 
 
 
2023 Senior Unsecured Notes
 
The $1.25 billion aggregate principal amount of 5.375% senior unsecured notes due 2023, issued July 22, 2014
 
 
 
2024 First Lien Notes
 
The $490 million aggregate principal amount of 5.875% senior secured notes due 2024, issued October 31, 2013
 
 
 
2024 First Lien Term Loan
 
The $1.6 billion first lien senior secured term loan, dated May 28, 2015 (as amended December 21, 2016), among Calpine Corporation, as borrower, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent
 
 
 
2024 Senior Unsecured Notes
 
The $650 million aggregate principal amount of 5.5% senior unsecured notes due 2024, issued February 3, 2015
 
 
 
2025 Senior Unsecured Notes
 
The $1.55 billion aggregate principal amount of 5.75% senior unsecured notes due 2025, issued July 22, 2014
 
 
 
2026 First Lien Notes
 
The $625 million aggregate principal amount of 5.25% senior unsecured notes due 2026, issued May 31, 2016
 
 
 
AB 32
 
California Assembly Bill 32
 
 
 
Accounts Receivable Sales Program
 
Receivables purchase agreement between Calpine Solutions and Calpine Receivables and the purchase and sale agreement between Calpine Receivables and an unaffiliated financial institution, both which allows for the revolving sale of up to $250 million in certain trade accounts receivables to third parties
 
 
 

ii



ABBREVIATION
 
DEFINITION
Adjusted EBITDA
 
EBITDA as adjusted for the effects of (a) impairment charges, (b) major maintenance expense, (c) operating lease expense, (d) gains or losses on commodity derivative mark-to-market activity, (e) adjustments to reflect only the Adjusted EBITDA from our unconsolidated investments, (f) adjustments to exclude the Adjusted EBITDA related to the noncontrolling interest, (g) stock-based compensation expense, (h) gains or losses on sales, dispositions or retirements of assets, (i) non-cash gains and losses from foreign currency translations, (j) gains or losses on the repurchase, modification or extinguishment of debt, (k) non-cash GAAP-related adjustments to levelize revenues from tolling agreements and (l) other unusual or non-recurring items
 
 
 
AOCI
 
Accumulated Other Comprehensive Income
 
 
 
Average availability
 
Represents the total hours during the period that our plants were in-service or available for service as a percentage of the total hours in the period
 
 
 
Average capacity factor, excluding peakers
 
A measure of total actual power generation as a percent of total potential power generation. It is calculated by dividing (a) total MWh generated by our power plants, excluding peakers, by (b) the product of multiplying (i) the average total MW in operation, excluding peakers, during the period by (ii) the total hours in the period
 
 
 
Btu
 
British thermal unit(s), a measure of heat content
 
 
 
CAISO
 
California Independent System Operator which is an entity that manages the power grid and operates the competitive power market in California
 
 
 
Calpine Equity Incentive Plans
 
Collectively, the Director Plan and the Equity Plan, which provide for grants of equity awards to Calpine non-union employees and non-employee members of Calpine’s Board of Directors
 
 
 
Calpine Receivables
 
Calpine Receivables, LLC, formerly Noble Americas Treasury Solutions LLC, an indirect, wholly-owned subsidiary of Calpine, which was established as a bankruptcy remote, special purpose subsidiary and is responsible for administering the Accounts Receivable Sales Program
 
 
 
Calpine Solutions
 
Calpine Energy Solutions, LLC, formerly Noble Solutions, an indirect, wholly-owned subsidiary of Calpine, which is the third largest supplier of power to commercial and industrial retail customers in the United States with customers in 19 states, including presence in California, Texas, the Mid-Atlantic and the Northeast
 
 
 
Cap-and-Trade
 
A government imposed emissions reduction program that would place a cap on the amount of emissions that can be emitted from certain sources, such as power plants. In its simplest form, the cap amount is set as a reduction from the total emissions during a base year and for each year over a period of years the cap amount would be reduced to achieve the targeted overall reduction by the end of the period. Allowances or credits for emissions in an amount equal to the cap would be issued or auctioned to companies with facilities, permitting them to emit up to a certain amount of emissions during each applicable period. After allowances have been distributed or auctioned, they can be transferred or traded
 
 
 
CCFC
 
Calpine Construction Finance Company, L.P., an indirect, wholly-owned subsidiary of Calpine
 
 
 
CCFC Term Loans
 
Collectively, the $900 million first lien senior secured term loan and the $300 million first lien senior secured term loan entered into on May 3, 2013, and the $425 million first lien senior secured term loan entered into on February 26, 2014, between CCFC, as borrower, and Goldman Sachs Lending Partners, LLC, as administrative agent and as collateral agent, and the lenders party thereto
 
 
 
CDHI
 
Calpine Development Holdings, Inc., an indirect, wholly-owned subsidiary of Calpine
 
 
 
CFTC
 
Commodities Futures Trading Commission
 
 
 
Champion Energy
 
Champion Energy Marketing, LLC, which owns a retail electric provider that serves residential, governmental, commercial and industrial customers in deregulated electricity markets in Texas, Illinois, Pennsylvania, Ohio, New Jersey, Maryland, Massachusetts, New York, Delaware, Maine, Connecticut, California and the District of Columbia
 
 
 

iii



ABBREVIATION
 
DEFINITION
CO2
 
Carbon dioxide
 
 
 
COD
 
Commercial operations date
 
 
 
Cogeneration
 
Using a portion or all of the steam generated in the power generating process to supply a customer with steam for use in the customer’s operations
 
 
 
Commodity expense
 
The sum of our expenses from fuel and purchased energy expense, fuel transportation expense, transmission expense, environmental compliance expense and realized settlements from our marketing, hedging and optimization activities including natural gas and fuel oil transactions hedging future power sales, but excludes our mark-to-market activity
 
 
 
Commodity Margin
 
Non-GAAP financial measure that includes power and steam revenues, sales of purchased power and physical natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, environmental compliance expense, and realized settlements from our marketing, hedging, optimization and trading activities, but excludes our mark-to-market activity and other revenues
 
 
 
Commodity revenue
 
The sum of our revenues from power and steam sales, sales of purchased power and physical natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue and realized settlements from our marketing, hedging, optimization and trading activities, but excludes our mark-to-market activity
 
 
 
Company
 
Calpine Corporation, a Delaware corporation, and its subsidiaries
 
 
 
Corporate Revolving Facility
 
The $1.8 billion aggregate amount revolving credit facility credit agreement, dated as of December 10, 2010, as amended on June 27, 2013, July 30, 2014, February 8, 2016 and December 1, 2016 among Calpine Corporation, the Bank of Tokyo-Mitsubishi UFJ, Ltd., as successor administrative agent, MUFG Union Bank, N.A., as successor collateral agent, the lenders party thereto and the other parties thereto
 
 
 
CPUC
 
California Public Utilities Commission
 
 
 
Director Plan
 
The Amended and Restated Calpine Corporation 2008 Director Incentive Plan
 
 
 
EBITDA
 
Net income (loss) attributable to Calpine before net (income) loss attributable to the noncontrolling interest, interest, taxes, depreciation and amortization
 
 
 
Equity Plan
 
The Amended and Restated Calpine Corporation 2008 Equity Incentive Plan
 
 
 
ERCOT
 
Electric Reliability Council of Texas which is an entity that manages the flow of electric power to Texas customers representing approximately 90 percent of the state’s electric load
 
 
 
Exchange Act
 
U.S. Securities Exchange Act of 1934, as amended
 
 
 
FASB
 
Financial Accounting Standards Board
 
 
 
FDIC
 
U.S. Federal Deposit Insurance Corporation
 
 
 
FERC
 
U.S. Federal Energy Regulatory Commission
 
 
 
First Lien Notes
 
Collectively, the 2022 First Lien Notes, the 2023 First Lien Notes, the 2024 First Lien Notes and the 2026 First Lien Notes
 
 
 
First Lien Term Loans
 
Collectively, the 2017 First Lien Term Loan, the 2019 First Lien Term Loan, the 2023 First Lien Term Loans and the 2024 First Lien Term Loan
 
 
 
Geysers Assets
 
Our geothermal power plant assets, including our steam extraction and gathering assets, located in northern California consisting of 13 operating power plants
 
 
 

iv



ABBREVIATION
 
DEFINITION
GHG(s)
 
Greenhouse gas(es), primarily carbon dioxide (CO2), and including methane (CH4), nitrous oxide (N2O), sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs) and perfluorocarbons (PFCs)
 
 
 
Greenfield LP
 
Greenfield Energy Centre LP, a 50% partnership interest between certain of our subsidiaries and a third party which operates the Greenfield Energy Centre, a 1,038 MW natural gas-fired, combined-cycle power plant in Ontario, Canada
 
 
 
Heat Rate(s)
 
A measure of the amount of fuel required to produce a unit of power
 
 
 
IESO
 
Independent Electricity System Operator which is a RTO that coordinates the supply and demand for electricity in the Canadian province of Ontario
 
 
 
IRS
 
U.S. Internal Revenue Service
 
 
 
ISO(s)
 
Independent System Operator which is an entity that coordinates, controls and monitors the operation of an electric power system
 
 
 
ISO-NE
 
ISO New England Inc., an independent, nonprofit RTO serving states in the New England area, including Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont
 
 
 
KWh
 
Kilowatt hour(s), a measure of power produced, purchased or sold
 
 
 
LIBOR
 
London Inter-Bank Offered Rate
 
 
 
Market Heat Rate(s)
 
The regional power price divided by the corresponding regional natural gas price
 
 
 
MMBtu
 
Million Btu
 
 
 
MW
 
Megawatt(s), a measure of plant capacity
 
 
 
MWh
 
Megawatt hour(s), a measure of power produced, purchased or sold
 
 
 
New 2023 First Lien Term Loan
 
The $562 million first lien senior secured term loan, dated May 31, 2016, among Calpine Corporation, as borrower, the lenders party thereto, Citibank, N.A., as administrative agent and MUFG Union Bank, N.A., as collateral agent
 
 
 
Noble Solutions
 
Noble Americas Energy Solutions LLC, which was legally renamed Calpine Energy Solutions, LLC on December 1, 2016 following the completion of its acquisition by an indirect, wholly-owned subsidiary of Calpine Corporation
 
 
 
NOL(s)
 
Net operating loss(es)
 
 
 
North American Power
 
North American Power & Gas, LLC, an indirect, wholly-owned subsidiary of Calpine, which was acquired on January 17, 2017 and is a growing retail energy supplier for homes and small businesses primarily concentrated in the Northeast U.S.
 
 
 
NYISO
 
New York ISO which operates competitive wholesale markets to manage the flow of electricity across New York
 
 
 
NYMEX
 
New York Mercantile Exchange
 
 
 
OCI
 
Other Comprehensive Income
 
 
 
OTC
 
Over-the-Counter
 
 
 
PJM
 
PJM Interconnection is a RTO that coordinates the movement of wholesale electricity in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia
 
 
 

v



ABBREVIATION
 
DEFINITION
PPA(s)
 
Any term power purchase agreement or other contract for a physically settled sale (as distinguished from a financially settled future, option or other derivative or hedge transaction) of any power product, including power, capacity and/or ancillary services, in the form of a bilateral agreement or a written or oral confirmation of a transaction between two parties to a master agreement, including sales related to a tolling transaction in which the purchaser provides the fuel required by us to generate such power and we receive a variable payment to convert the fuel into power and steam
 
 
 
PUCT
 
Public Utility Commission of Texas
 
 
 
REC(s)
 
Renewable energy credit(s)
 
 
 
Risk Management Policy
 
Calpine’s policy applicable to all employees, contractors, representatives and agents, which defines the risk management framework and corporate governance structure for commodity risk, interest rate risk, currency risk and other risks
 
 
 
RTO(s)
 
Regional Transmission Organization which is an entity that coordinates, controls and monitors the operation of an electric power system and administers the transmission grid on a regional basis
 
 
 
SEC
 
U.S. Securities and Exchange Commission
 
 
 
Securities Act
 
U.S. Securities Act of 1933, as amended
 
 
 
Senior Unsecured Notes
 
Collectively, the 2023 Senior Unsecured Notes, the 2024 Senior Unsecured Notes and the 2025 Senior Unsecured Notes
 
 
 
Spark Spread(s)
 
The difference between the sales price of power per MWh and the cost of natural gas to produce it
 
 
 
Steam Adjusted Heat Rate
 
The adjusted Heat Rate for our natural gas-fired power plants, excluding peakers, calculated by dividing (a) the fuel consumed in Btu reduced by the net equivalent Btu in steam exported to a third party by (b) the KWh generated. Steam Adjusted Heat Rate is a measure of fuel efficiency, so the lower our Steam Adjusted Heat Rate, the lower our cost of generation
 
 
 
U.S. GAAP
 
Generally accepted accounting principles in the U.S.
 
 
 
VAR
 
Value-at-risk
 
 
 
VIE(s)
 
Variable interest entity(ies)
 
 
 
Whitby
 
Whitby Cogeneration Limited Partnership, a 50% partnership interest between certain of our subsidiaries and a third party, which operates Whitby, a 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada

vi



Forward-Looking Statements

This Report contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act, and Section 21E of the Exchange Act. Forward-looking statements may appear throughout this Report, including without limitation, the “Management’s Discussion and Analysis” section. We use words such as “believe,” “intend,” “expect,” “anticipate,” “plan,” “may,” “will,” “should,” “estimate,” “potential,” “project” and similar expressions to identify forward-looking statements. Such statements include, among others, those concerning our expected financial performance and strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. We believe that the forward-looking statements are based upon reasonable assumptions and expectations. However, you are cautioned that any such forward-looking statements are not guarantees of future performance and that a number of risks and uncertainties could cause actual results to differ materially from those anticipated in the forward-looking statements. Such risks and uncertainties include, but are not limited to:
Financial results that may be volatile and may not reflect historical trends due to, among other things, seasonality of demand, fluctuations in prices for commodities such as natural gas and power, changes in U.S. macroeconomic conditions, fluctuations in liquidity and volatility in the energy commodities markets and our ability and extent to which we hedge risks;
Laws, regulations and market rules in the markets in which we participate and our ability to effectively respond to changes in laws, regulations or market rules or the interpretation thereof including those related to the environment, derivative transactions and market design in the regions in which we operate;
Our ability to manage our liquidity needs, access the capital markets when necessary and comply with covenants under our Senior Unsecured Notes, First Lien Notes, First Lien Term Loans, Corporate Revolving Facility, CCFC Term Loans and other existing financing obligations;
Risks associated with the operation, construction and development of power plants, including unscheduled outages or delays and plant efficiencies;
Risks related to our geothermal resources, including the adequacy of our steam reserves, unusual or unexpected steam field well and pipeline maintenance requirements, variables associated with the injection of water to the steam reservoir and potential regulations or other requirements related to seismicity concerns that may delay or increase the cost of developing or operating geothermal resources;
Competition, including from renewable sources of power, interference by states in competitive power markets through subsidies or similar support for new or existing power plants, and other risks associated with marketing and selling power in the evolving energy markets;
Structural changes in the supply and demand of power, resulting from the development of new fuels or technologies and demand-side management tools (such as distributed generation, power storage and other technologies);
The expiration or early termination of our PPAs and the related results on revenues;
Future capacity revenue may not occur at expected levels;
Natural disasters, such as hurricanes, earthquakes, droughts, wildfires and floods, acts of terrorism or cyber attacks that may affect our power plants or the markets our power plants or retail operations serve and our corporate headquarters;
Disruptions in or limitations on the transportation of natural gas or fuel oil and the transmission of power;
Our ability to manage our counterparty and customer exposure and credit risk, including our commodity positions;
Our ability to attract, motivate and retain key employees;
Present and possible future claims, litigation and enforcement actions that may arise from noncompliance with market rules promulgated by the SEC, CFTC, FERC and other regulatory bodies; and
Other risks identified in this Report, in our 2016 Form 10-K and in other reports filed by us with the SEC.

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

vii



Where You Can Find Other Information
Our website is www.calpine.com. Information contained on our website is not part of this Report. Information that we furnish or file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to, or exhibits included in, these reports are available for download, free of charge, on our website as soon as reasonably practicable after such materials are filed with or furnished to the SEC. Our SEC filings, including exhibits filed therewith, are also available on the SEC’s website at www.sec.gov. You may obtain and copy any document we furnish or file with the SEC at the SEC’s public reference room at 100 F Street, NE, Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the SEC’s public reference facilities by calling the SEC at 1-800-SEC-0330. You may request copies of these documents, upon payment of a duplicating fee, by writing to the SEC at its principal office at 100 F Street, NE, Room 1580, Washington, D.C. 20549.

viii



PART I — FINANCIAL INFORMATION
Item 1.
Financial Statements

CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
(Unaudited)
 
Three Months Ended March 31,
 
2017
 
2016
 
(in millions, except share and per share amounts)
Operating revenues:
 
 
 
Commodity revenue
$
2,063

 
$
1,585

Mark-to-market gain
214

 
25

Other revenue
4

 
5

Operating revenues
2,281

 
1,615

Operating expenses:
 
 
 
Fuel and purchased energy expense:
 
 
 
Commodity expense
1,533

 
1,006

Mark-to-market loss
159

 
120

Fuel and purchased energy expense
1,692

 
1,126

Plant operating expense
282

 
255

Depreciation and amortization expense
206

 
180

Sales, general and other administrative expense
40

 
38

Other operating expenses
20

 
20

Total operating expenses
2,240

 
1,619

(Gain) on sale of assets, net
(27
)
 

(Income) from unconsolidated subsidiaries
(4
)
 
(7
)
Income from operations
72

 
3

Interest expense
159

 
157

Debt extinguishment costs
24

 

Other (income) expense, net
2

 
5

Loss before income taxes
(113
)
 
(159
)
Income tax expense (benefit)
(61
)
 
35

Net loss
(52
)
 
(194
)
Net income attributable to the noncontrolling interest
(4
)
 
(4
)
Net loss attributable to Calpine
$
(56
)
 
$
(198
)
 
 
 
 
Basic and diluted loss per common share attributable to Calpine:
 
 
 
Weighted average shares of common stock outstanding (in thousands)
354,682

 
353,501

Net loss per common share attributable to Calpine — basic and diluted
$
(0.16
)
 
$
(0.56
)

The accompanying notes are an integral part of these Consolidated Condensed Financial Statements.

1



CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE LOSS
(Unaudited)

 
Three Months Ended March 31,
 
 
2017
 
2016
 
 
(in millions)
Net loss
$
(52
)
 
$
(194
)
 
Cash flow hedging activities:
 
 
 
 
Loss on cash flow hedges before reclassification adjustment for cash flow hedges realized in net loss
(15
)
 
(23
)
 
Reclassification adjustment for loss on cash flow hedges realized in net loss
11

 
11

 
Foreign currency translation gain
2

 
12

 
Income tax expense

 

 
Other comprehensive loss
(2
)
 

 
Comprehensive loss
(54
)
 
(194
)
 
Comprehensive (income) attributable to the noncontrolling interest
(4
)
 
(2
)
 
Comprehensive loss attributable to Calpine
$
(58
)
 
$
(196
)
 

The accompanying notes are an integral part of these Consolidated Condensed Financial Statements.


2



CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited)

 
 
March 31,
 
December 31,
 
 
2017
 
2016
 
 
(in millions, except share and per share amounts)
ASSETS
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents ($63 and $79 attributable to VIEs)
 
$
243

 
$
418

Accounts receivable, net of allowance of $8 and $6
 
765

 
839

Inventories
 
535

 
581

Margin deposits and other prepaid expense
 
364

 
441

Restricted cash, current ($99 and $109 attributable to VIEs)
 
162

 
173

Derivative assets, current
 
1,387

 
1,725

Current assets held for sale (nil and $134 attributable to VIEs)
 

 
210

Other current assets
 
65

 
45

Total current assets
 
3,521

 
4,432

Property, plant and equipment, net ($4,164 and $3,979 attributable to VIEs)
 
13,009

 
13,013

Restricted cash, net of current portion ($15 and $14 attributable to VIEs)
 
15

 
15

Investments in unconsolidated subsidiaries
 
92

 
99

Long-term derivative assets
 
670

 
543

Goodwill
 
233

 
187

Intangible assets, net
 
635

 
650

Other assets ($60 and $63 attributable to VIEs)
 
401

 
378

Total assets
 
$
18,576

 
$
19,317

LIABILITIES & STOCKHOLDERS’ EQUITY
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable
 
$
655

 
$
671

Accrued interest payable
 
125

 
125

Debt, current portion ($176 and $176 attributable to VIEs)
 
608

 
748

Derivative liabilities, current
 
1,273

 
1,630

Other current liabilities
 
459

 
528

Total current liabilities
 
3,120

 
3,702

Debt, net of current portion ($2,900 and $2,944 attributable to VIEs)
 
11,344

 
11,431

Long-term derivative liabilities
 
550

 
476

Other long-term liabilities
 
280

 
369

Total liabilities
 
15,294

 
15,978

 
 
 
 
 
Commitments and contingencies (see Note 11)
 

 

Stockholders’ equity:
 
 
 
 
Preferred stock, $0.001 par value per share; authorized 100,000,000 shares, none issued and outstanding
 

 

Common stock, $0.001 par value per share; authorized 1,400,000,000 shares, 361,833,256 and 359,627,113 shares issued, respectively, and 360,797,377 and 359,061,764 shares outstanding, respectively
 

 

Treasury stock, at cost, 1,035,879 and 565,349 shares, respectively
 
(13
)
 
(7
)
Additional paid-in capital
 
9,633

 
9,625

Accumulated deficit
 
(6,269
)
 
(6,213
)
Accumulated other comprehensive loss
 
(139
)
 
(137
)
Total Calpine stockholders’ equity
 
3,212

 
3,268

Noncontrolling interest
 
70

 
71

Total stockholders’ equity
 
3,282

 
3,339

Total liabilities and stockholders’ equity
 
$
18,576

 
$
19,317


The accompanying notes are an integral part of these Consolidated Condensed Financial Statements.

3



CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)

 
 
Three Months Ended March 31,
 
 
2017
 
2016
 
 
(in millions)
Cash flows from operating activities:
 
 
 
 
Net loss
 
$
(52
)
 
$
(194
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 

 

Depreciation and amortization(1)
 
265

 
226

Debt extinguishment costs
 
6

 

Income tax expense (benefit)
 
(61
)
 
35

Gain on sale of assets, net
 
(27
)
 

Mark-to-market activity, net
 
(55
)
 
94

(Income) from unconsolidated subsidiaries
 
(4
)
 
(7
)
Return on investments from unconsolidated subsidiaries
 
13

 

Stock-based compensation expense
 
8

 
9

Other
 

 
(4
)
Change in operating assets and liabilities, net of effects of acquisitions:
 

 

Accounts receivable
 
82

 
87

Derivative instruments, net
 
(21
)
 
(12
)
Other assets
 
24

 
(19
)
Accounts payable and accrued expenses
 
(104
)
 
(202
)
Other liabilities
 
20

 
18

Net cash provided by operating activities
 
94

 
31

Cash flows from investing activities:
 
 
 
 
Purchases of property, plant and equipment
 
(91
)
 
(133
)
Proceeds from sale of Osprey Energy Center
 
162

 

Purchase of Granite Ridge Energy Center
 

 
(527
)
Purchase of North American Power, net of cash acquired
 
(111
)
 

Decrease in restricted cash
 
11

 
43

Other
 
16

 
6

Net cash used in investing activities
 
(13
)
 
(611
)
Cash flows from financing activities:
 
 
 
 
Borrowings under First Lien Term Loans
 
396

 

Repayment of CCFC Term Loans and First Lien Term Loans
 
(161
)
 
(13
)
Repurchase of First Lien Notes
 
(453
)
 

Borrowings under Corporate Revolving Facility
 
25

 

Repayments of project financing, notes payable and other
 
(44
)
 
(56
)
Distribution to noncontrolling interest holder
 
(6
)
 
(2
)
Financing costs
 
(8
)
 
(7
)
Shares repurchased for tax withholding on stock-based awards
 
(6
)
 
(5
)
Other
 
1

 
1

Net cash used in financing activities
 
(256
)
 
(82
)
Net decrease in cash and cash equivalents
 
(175
)
 
(662
)
Cash and cash equivalents, beginning of period
 
418

 
906

Cash and cash equivalents, end of period
 
$
243

 
$
244


The accompanying notes are an integral part of these Consolidated Condensed Financial Statements.


4



CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS — (CONTINUED)
(Unaudited)

 
 
Three Months Ended March 31,
 
 
2017
 
2016
 
 
(in millions)
Cash paid during the period for:
 
 
 
 
Interest, net of amounts capitalized
 
$
141

 
$
150

Income taxes
 
$
3

 
$
2

 
 
 
 
 
Supplemental disclosure of non-cash investing activities:
 
 
 
 
Change in capital expenditures included in accounts payable
 
$

 
$
15

____________
(1)
Includes amortization recorded in Commodity revenue and Commodity expense associated with intangible assets and amortization recorded in interest expense associated with debt issuance costs and discounts.
The accompanying notes are an integral part of these Consolidated Condensed Financial Statements.


5



CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
March 31, 2017
(Unaudited)
1.
Basis of Presentation and Summary of Significant Accounting Policies
We are a power generation company engaged in the ownership and operation of primarily natural gas-fired and geothermal power plants in North America. We have a significant presence in major competitive wholesale power markets in California (included in our West segment), Texas (included in our Texas segment) and the Northeast and Mid-Atlantic regions (included in our East segment) of the U.S. We sell power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities and other governmental entities, power marketers as well as retail commercial, industrial, governmental and residential customers. We continue to focus on getting closer to our customers through expansion of our retail platform which began with the acquisition of Champion Energy in 2015 and was followed by the acquisitions of Calpine Solutions in late 2016 and North American Power in early 2017. We purchase primarily natural gas and some fuel oil as fuel for our power plants and engage in related natural gas transportation and storage transactions. We also purchase power for sale to our customers and purchase electric transmission rights to deliver power to our customers. Additionally, consistent with our Risk Management Policy, we enter into natural gas, power, environmental product, fuel oil and other physical and financial commodity contracts to hedge certain business risks and optimize our portfolio of power plants.
Basis of Interim Presentation — The accompanying unaudited, interim Consolidated Condensed Financial Statements of Calpine Corporation, a Delaware corporation, and consolidated subsidiaries have been prepared pursuant to the rules and regulations of the SEC. In the opinion of management, the Consolidated Condensed Financial Statements include the normal, recurring adjustments necessary for a fair statement of the information required to be set forth therein. Certain information and note disclosures, normally included in financial statements prepared in accordance with U.S. GAAP, have been condensed or omitted from these statements pursuant to such rules and regulations and, accordingly, these financial statements should be read in conjunction with our audited Consolidated Financial Statements for the year ended December 31, 2016, included in our 2016 Form 10-K. The results for interim periods are not indicative of the results for the entire year primarily due to acquisitions and disposals of assets, seasonal fluctuations in our revenues and expenses, timing of major maintenance expense, variations resulting from the application of the method to calculate the provision for income tax for interim periods, volatility of commodity prices and mark-to-market gains and losses from commodity and interest rate derivative contracts.
Use of Estimates in Preparation of Financial Statements — The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures included in our Consolidated Condensed Financial Statements. Actual results could differ from those estimates.
Cash and Cash Equivalents — We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have cash and cash equivalents held in non-corporate accounts relating to certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts. These accounts have been pledged as security in favor of the lenders under such project finance facilities, and the use of certain cash balances on deposit in such accounts is limited, at least temporarily, to the operations of the respective projects.
Restricted Cash — Certain of our debt agreements, lease agreements or other operating agreements require us to establish and maintain segregated cash accounts, the use of which is restricted, making these cash funds unavailable for general use. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent and major maintenance or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Condensed Balance Sheets and Statements of Cash Flows.

6



The table below represents the components of our restricted cash as of March 31, 2017 and December 31, 2016 (in millions):
 
March 31, 2017
 
December 31, 2016
 
Current
 
Non-Current
 
Total
 
Current
 
Non-Current
 
Total
Debt service
$
12

 
$
7

 
$
19

 
$
11

 
$
8

 
$
19

Construction/major maintenance
48

 
6

 
54

 
45

 
6

 
51

Security/project/insurance
99

 

 
99

 
114

 

 
114

Other
3

 
2

 
5

 
3

 
1

 
4

Total
$
162

 
$
15

 
$
177

 
$
173

 
$
15

 
$
188

Property, Plant and Equipment, Net — At March 31, 2017 and December 31, 2016, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):
 
March 31, 2017
 
December 31, 2016
 
Depreciable Lives
Buildings, machinery and equipment
$
16,481

 
$
16,468

 
3
46
 Years
Geothermal properties
1,460

 
1,377

 
13
58
 Years
Other
237

 
259

 
3
46
 Years
 
18,178

 
18,104

 
 
 
 
 
Less: Accumulated depreciation
5,975

 
5,865

 
 
 
 
 
 
12,203

 
12,239

 
 
 
 
 
Land
116

 
116

 
 
 
 
 
Construction in progress
690

 
658

 
 
 
 
 
Property, plant and equipment, net
$
13,009

 
$
13,013

 
 
 
 
 
Capitalized Interest — The total amount of interest capitalized was $7 million and $4 million for the three months ended March 31, 2017 and 2016, respectively.
Goodwill — The change in goodwill during the three months ended March 31, 2017 was as follows (in millions):
 
West
 
Texas
 
East
 
Total
Goodwill at December 31, 2016
$
68

 
$
31

 
$
88

 
$
187

Acquisition of North American Power

 

 
49

 
49

Calpine Solutions purchase price allocation adjustment
(1
)
 

 
(2
)
 
(3
)
Goodwill at March 31, 2017
$
67

 
$
31

 
$
135

 
$
233

Related Party — Under the Accounts Receivables Sales Program, at March 31, 2017 and December 31, 2016, we had $179 million and $211 million, respectively, in trade accounts receivable outstanding that were sold to Calpine Receivables and $40 million and $32 million, respectively, in notes receivable from Calpine Receivables which were recorded on our Consolidated Condensed Balance Sheets. During the three months ended March 31, 2017, we sold an aggregate of $542 million in trade accounts receivable and recorded $546 million in proceeds. For a further discussion of the Accounts Receivable Sales Program and Calpine Receivables, see Notes 2 and 5 in our 2016 Form 10-K.
New Accounting Standards and Disclosure Requirements
Revenue Recognition — In May 2014, the FASB issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers.” The comprehensive new revenue recognition standard will supersede all existing revenue recognition guidance. The core principle of the standard is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard also requires expanded disclosures surrounding revenue recognition. The standard allows for either full retrospective or modified retrospective adoption. In August 2015, the FASB deferred the effective date of Accounting Standards Update 2014-09 for public entities by one year, such that the standard will become effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2017. The standard permits entities to adopt early, but only as of the original effective date. In March 2016, the FASB issued Accounting Standards Update 2016-08 “Principal versus Agent Considerations

7



(Reporting Revenue Gross versus Net)” which clarifies implementation guidance for principal versus agent considerations in the new revenue recognition standard. In May 2016, the FASB issued Accounting Standards Update 2016-12 “Narrow-Scope Improvements and Practical Expedients” which addresses assessing the collectability of a contract, the presentation of sales taxes and other taxes collected from customers, non-cash consideration and completed contracts and contract modifications at transition. We expect to adopt the standard in the first quarter of 2018 using the modified retrospective transition approach; however, our method of adoption may change as we complete our assessment of the standard. We are currently evaluating the effect the revenue recognition standards will have on our revenue contracts such as our PPAs and tolling agreements; however, we do not anticipate the adoption of this standard will have a material effect on our financial condition, results of operations or cash flows. Upon adoption, we intend to elect the practical expedient that would allow an entity to recognize revenue in the amount to which the entity has the right to invoice to the extent we determine that we have a right to consideration from the customer in an amount that corresponds directly with the value provided based on our performance completed to date.
Inventory In July 2015, the FASB issued Accounting Standards Update 2015-11, “Simplifying the Measurement of Inventory.” The standard changes the inventory valuation method from the lower of cost or market to the lower of cost or net realizable value for inventory valued under the first-in, first-out or average cost methods. This standard is effective for fiscal years beginning after December 15, 2016, including interim periods and requires prospective adoption with early adoption permitted. We adopted Accounting Standards Update 2015-11 in the first quarter of 2017 which did not have a material effect on our financial condition, results of operations or cash flows.
Leases — In February 2016, the FASB issued Accounting Standards Update 2016-02, “Leases.” The comprehensive new lease standard will supersede all existing lease guidance. The standard requires that a lessee should recognize a right-to-use asset and a lease liability for substantially all operating leases based on the present value of the minimum rental payments. Entities may make an accounting policy election to not recognize lease assets and liabilities for leases with a term of 12 months or less. For lessors, the accounting for leases remains substantially unchanged. The standard also requires expanded disclosures surrounding leases. The standard is effective for fiscal periods beginning after December 15, 2018, including interim periods within that reporting period and requires modified retrospective adoption with early adoption permitted. We expect to adopt the standard in the first quarter of 2019. We have completed our initial evaluation of the standard and believe that the key changes that will affect us relate to our accounting for operating leases that are currently off-balance sheet and tolling contracts which we currently account for as operating leases. Additionally, we are evaluating the potential effects of the removal of the real estate guidance currently applicable to lessors that will be abrogated under Accounting Standards Update 2014-09, “Revenue from Contracts with Customers.” We are also considering electing the practical expedient in our implementation of the standard; however, this may change as we complete our assessment of the standard.
Statement of Cash Flows — In August 2016, the FASB issued Accounting Standards Update 2016-15, “Classification of Certain Cash Receipts and Cash Payments.” The standard addresses several matters of diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows including the presentation of debt extinguishment costs and distributions received from equity method investments. The standard is effective for fiscal years beginning after December 15, 2017, including interim periods and allows for retrospective adoption with early adoption permitted. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard.
Restricted Cash — In November 2016, the FASB issued Accounting Standards Update 2016-18, “Restricted Cash.” The standard requires restricted cash to be included with cash and cash equivalents when reconciling the beginning and ending amounts in the statement of cash flows and also requires disclosures regarding the nature of restrictions on cash, cash equivalents and restricted cash. The standard is effective for fiscal years beginning after December 15, 2017, including interim periods and requires for retrospective adoption with early adoption permitted. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard.
Intangibles – Goodwill and Other — In January 2017, the FASB issued Accounting Standards Update 2017-04, “Simplifying the Test for Goodwill Impairment.” The standard eliminates the second step in the goodwill impairment test which requires an entity to determine the implied fair value of the reporting unit’s goodwill. Instead, an entity should recognize an impairment loss if the carrying value of the net assets assigned to the reporting unit exceeds the fair value of the reporting unit, with the impairment loss not to exceed the amount of goodwill allocated to the reporting unit. The standard is effective for annual and interim goodwill impairment tests conducted in fiscal years beginning after December 15, 2019, with early adoption permitted. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard.

8



2.
Acquisitions and Divestitures
Acquisition of North American Power
On January 17, 2017, we, through an indirect, wholly-owned subsidiary, completed the purchase of 100% of the outstanding limited liability company membership interests in North American Power for approximately $105 million, excluding working capital and other adjustments. North American Power is a 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 is enhanced by the addition of North American Power, which has been integrated into our Champion Energy retail platform. We funded the acquisition with cash on hand and the purchase price is allocated to the net assets of the business including intangible assets for the value of customer relationships and goodwill. The goodwill recorded associated with our acquisition of North American Power is deductible for tax purposes. The pro forma incremental effect of North American Power on our results of operations for each of the three months ended March 31, 2017 and 2016 is not material.
Acquisition of Calpine Solutions, formerly Noble Solutions
We did not record any material adjustments to the preliminary purchase price allocation during the three months ended March 31, 2017 associated with our acquisition of Calpine Solutions on December 1, 2016.
Acquisition of Granite Ridge Energy Center
On February 5, 2016, we, through our indirect, wholly-owned subsidiary Calpine Granite Holdings, LLC, completed the purchase of Granite Ridge Energy Center, a power plant with a nameplate capacity of 745 MW (summer peaking capacity of 695 MW), from Granite Ridge Holdings, LLC, for approximately $500 million, excluding working capital and other adjustments. The purchase price allocation was finalized during the first quarter of 2017 and did not result in any material adjustments or the recognition of goodwill.
Sale of Osprey Energy Center
On January 3, 2017, we completed the sale of the Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million, excluding working capital and other adjustments. This transaction supports our effort to divest non-core assets outside our strategic concentration. We recorded a gain on sale of assets, net of approximately $27 million during the three months ended March 31, 2017 associated with the sale of the Osprey Energy Center.
Sale of South Point Energy Center
As a result of the denial by the Nevada Public Utility Commission of the sale of South Point Energy Center to Nevada Power Company in February 2017, we terminated the corresponding asset sale agreement in the first quarter of 2017. We are currently assessing our options related to South Point Energy Center; however, we do not anticipate that the termination of the asset sale agreement will have a material effect on our financial condition, results of operations or cash flows. During the first quarter of 2017, we reclassified the assets of South Point Energy Center from current assets held for sale to held and used which are measured at fair value as a component of property, plant and equipment, net.
3.
Variable Interest Entities and Unconsolidated Investments
We consolidate all of our VIEs where we have determined that we are the primary beneficiary. There were no changes to our determination of whether we are the primary beneficiary of our VIEs for the three months ended March 31, 2017. See Note 5 in our 2016 Form 10-K for further information regarding our VIEs.
VIE Disclosures
Our consolidated VIEs include natural gas-fired power plants with an aggregate capacity of 8,988 MW and 9,491 MW at March 31, 2017 and December 31, 2016, respectively. For these VIEs, we may provide other operational and administrative support through various affiliate contractual arrangements among the VIEs, Calpine Corporation and its other wholly-owned subsidiaries whereby we support the VIE through the reimbursement of costs and/or the purchase and sale of energy. Other than amounts contractually required, we provided support to these VIEs in the form of cash and other contributions of nil during each of the three months ended March 31, 2017 and 2016.
Unconsolidated VIEs and Investments in Unconsolidated Subsidiaries
We have a 50% partnership interest in Greenfield LP and in Whitby. Greenfield LP and Whitby are VIEs; however, we do not have the power to direct the most significant activities of these entities and therefore do not consolidate them. Greenfield LP is a limited partnership between certain subsidiaries of ours and of Mitsui & Co., Ltd., which operates the Greenfield Energy

9



Centre, a 1,038 MW natural gas-fired, combined-cycle power plant located in Ontario, Canada. We and Mitsui & Co., Ltd. each hold a 50% interest in Greenfield LP. Whitby is a limited partnership between certain of our subsidiaries and Atlantic Packaging Ltd., which operates the Whitby facility, a 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada. We and Atlantic Packaging Ltd. each hold a 50% partnership interest in Whitby.
In December 2016, we acquired Calpine Receivables, a bankruptcy remote entity created for the special purpose of purchasing trade accounts receivable from Calpine Solutions under the Accounts Receivable Sales Program. Calpine Receivables is a VIE as we have determined that we do not have the power to direct the activities of the VIE that most significantly affect the VIE’s economic performance nor the obligation to absorb losses or receive benefits from the VIE. Accordingly, we have determined that we are not the primary beneficiary of Calpine Receivables as we do not have the power to affect its financial performance as the unaffiliated financial institutions that purchase the receivables from Calpine Receivables control the selection criteria of the receivables sold and appoint the servicer of the receivables which controls management of default. Thus, we do not consolidate Calpine Receivables in our Consolidated Financial Statements and use the equity method of accounting to record our net interest in Calpine Receivables.
We account for these entities under the equity method of accounting and include our net equity interest in investments in unconsolidated subsidiaries on our Consolidated Condensed Balance Sheets. At March 31, 2017 and December 31, 2016, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):
 
Ownership Interest as of
March 31, 2017
 
March 31, 2017
 
December 31, 2016
Greenfield LP
50%
 
$
78

 
$
73

Whitby
50%
 
4

 
16

Calpine Receivables
100%
 
10

 
10

Total investments in unconsolidated subsidiaries
 
 
$
92

 
$
99

Our risk of loss related to our investments in Greenfield LP, Whitby and Calpine Receivables is limited to our investment balance. Holders of the debt of our unconsolidated investments do not have recourse to Calpine Corporation and its other subsidiaries; therefore, the debt of our unconsolidated investments is not reflected on our Consolidated Condensed Balance Sheets. At March 31, 2017 and December 31, 2016, Greenfield LP’s debt was approximately $256 million and $259 million, respectively, and based on our pro rata share of our investment in Greenfield LP, our share of such debt would be approximately $128 million and $130 million at March 31, 2017 and December 31, 2016, respectively.
Our equity interest in the net income from our investments in unconsolidated subsidiaries for the three months ended March 31, 2017 and 2016, is recorded in (income) from unconsolidated subsidiaries. We did not have any income or receive any distributions from our investment in Calpine Receivables for the three months ended March 31, 2017. The following table sets forth details of our (income) from unconsolidated subsidiaries for the periods indicated (in millions):
 
 
Three Months Ended March 31,
 
 
 
2017
 
2016
 
Greenfield LP
 
$
(2
)
 
$
(4
)
 
Whitby
 
(2
)
 
(3
)
 
Total
 
$
(4
)
 
$
(7
)
 
Distributions from Greenfield LP were nil during each of the three months ended March 31, 2017 and 2016. Distributions from Whitby were $13 million and nil during the three months ended March 31, 2017 and 2016, respectively.

10



4.
Debt
Our debt at March 31, 2017 and December 31, 2016, was as follows (in millions):
 
March 31, 2017

December 31, 2016
Senior Unsecured Notes
$
3,413

 
$
3,412

First Lien Term Loans
3,405

 
3,165

First Lien Notes
1,841

 
2,290

Project financing, notes payable and other
1,561

 
1,597

CCFC Term Loans
1,550

 
1,553

Capital lease obligations
157

 
162

Corporate Revolving Facility
25

 

Subtotal
11,952

 
12,179

Less: Current maturities
608

 
748

Total long-term debt
$
11,344

 
$
11,431

Our effective interest rate on our consolidated debt, excluding the effects of capitalized interest and mark-to-market gains (losses) on interest rate hedging instruments, decreased to 5.4% for the three months ended March 31, 2017, from 5.5% for the same period in 2016. The issuance of our 2019 First Lien Term Loan in February 2017 and a portion of our 2023 First Lien Term Loans in May 2016 allowed us to reduce our overall cost of debt by replacing a portion of our First Lien Notes and First Lien Term Loans with debt carrying lower interest rates.
Senior Unsecured Notes
The amounts outstanding under our Senior Unsecured Notes are summarized in the table below (in millions):
 
March 31, 2017
 
December 31, 2016
2023 Senior Unsecured Notes
$
1,237

 
$
1,237

2024 Senior Unsecured Notes
643

 
643

2025 Senior Unsecured Notes
1,533

 
1,532

Total Senior Unsecured Notes
$
3,413

 
$
3,412

First Lien Term Loans
The amounts outstanding under our senior secured First Lien Term Loans are summarized in the table below (in millions):
 
March 31, 2017
 
December 31, 2016
2017 First Lien Term Loan(1)
$
393

 
$
537

2019 First Lien Term Loan
389

 

2023 First Lien Term Loans
1,070

 
1,071

2024 First Lien Term Loan
1,553

 
1,557

Total First Lien Term Loans
$
3,405

 
$
3,165

____________
(1)
On March 16, 2017, we used cash on hand to repay $150 million of our outstanding 2017 First Lien Term Loan. During the first quarter of 2017, we recorded approximately $3 million in debt extinguishment costs related to the partial repayment of our 2017 First Lien Term Loan.
On February 3, 2017, we entered into a $400 million first lien senior secured term loan which bears interest, at our option, at either (i) the Base Rate, equal to the highest of (a) the Federal Funds Effective Rate plus 0.5% per annum, (b) the Prime Rate or (c) the Eurodollar Rate for a one month interest period plus 1.0% (in each case, as such terms are defined in the 2019 First Lien Term Loan credit agreement), plus an applicable margin of 0.75%, or (ii) LIBOR plus 1.75% per annum (with no LIBOR floor) and matures on December 31, 2019. An aggregate amount equal to 0.25% of the aggregate principal amount of the 2019 First Lien Term Loans is payable at the end of each quarter (beginning with the quarter ending June 2017) with the remaining balance payable on the maturity date. We paid an upfront fee of an amount equal to 1.0% of the aggregate principal amount of the 2019 First Lien

11



Term Loan, which is structured as original issue discount and recorded approximately $8 million in debt issuance costs during the first quarter of 2017 related to the issuance of our 2019 First Lien Term Loan. The 2019 First Lien Term Loan contains substantially similar covenants, qualifications, exceptions and limitations as our First Lien Term Loans and First Lien Notes. We used the proceeds from the 2019 First Lien Term Loan, together with cash on hand, to redeem the remaining 2023 First Lien Notes.
First Lien Notes
The amounts outstanding under our senior secured First Lien Notes are summarized in the table below (in millions):
 
March 31, 2017
 
December 31, 2016
2022 First Lien Notes
$
739

 
$
739

2023 First Lien Notes(1)

 
450

2024 First Lien Notes
485

 
485

2026 First Lien Notes
617

 
616

Total First Lien Notes
$
1,841

 
$
2,290

____________
(1)
On March 6, 2017, we used cash on hand along with the proceeds from our 2019 First Lien Term Loan to redeem the remaining $453 million of our 2023 First Lien Notes, plus accrued and unpaid interest. During the first quarter of 2017, we recorded approximately $21 million in debt extinguishment costs related to the redemption of our 2023 First Lien Notes.
Corporate Revolving Facility and Other Letter of Credit Facilities
The table below represents amounts issued under our letter of credit facilities at March 31, 2017 and December 31, 2016 (in millions):
 
March 31, 2017
 
December 31, 2016
Corporate Revolving Facility(1)
$
471

 
$
535

CDHI
237

 
250

Various project financing facilities
183

 
206

Total
$
891

 
$
991

____________
(1)
The Corporate Revolving Facility represents our primary revolving facility.
Fair Value of Debt
We record our debt instruments based on contractual terms, net of any applicable premium or discount. The following table details the fair values and carrying values of our debt instruments at March 31, 2017 and December 31, 2016 (in millions):
 
March 31, 2017
 
December 31, 2016
 
Fair Value
 
Carrying Value
 
Fair Value
 
Carrying Value
Senior Unsecured Notes
$
3,435

 
$
3,413

 
$
3,343

 
$
3,412

First Lien Term Loans
3,480

 
3,405

 
3,244

 
3,165

First Lien Notes
1,931

 
1,841

 
2,349

 
2,290

Project financing, notes payable and other(1)
1,505

 
1,469

 
1,543

 
1,506

CCFC Term Loans
1,567

 
1,550

 
1,567

 
1,553

Corporate Revolving Facility
25

 
25

 

 

Total
$
11,943

 
$
11,703

 
$
12,046

 
$
11,926

____________
(1)
Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP.
We measure the fair value of our Senior Unsecured Notes, First Lien Term Loans, First Lien Notes and CCFC Term Loans using market information, including quoted market prices or dealer quotes for the identical liability when traded as an asset

12



(categorized as level 2). We measure the fair value of our project financing, notes payable and other debt instruments using discounted cash flow analyses based on our current borrowing rates for similar types of borrowing arrangements (categorized as level 3). We do not have any debt instruments with fair value measurements categorized as level 1 within the fair value hierarchy.
5.
Assets and Liabilities with Recurring Fair Value Measurements
Cash Equivalents — Highly liquid investments which meet the definition of cash equivalents, primarily investments in money market accounts and other interest-bearing accounts, are included in both our cash and cash equivalents and our restricted cash on our Consolidated Condensed Balance Sheets. Certain of our money market accounts invest in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities. We do not have any cash equivalents invested in institutional prime money market funds which require use of a floating net asset value and are subject to liquidity fees and redemption restrictions. Certain of our cash equivalents are classified within level 1 of the fair value hierarchy.
Derivatives — The primary factors affecting the fair value of our derivative instruments at any point in time are the volume of open derivative positions (MMBtu, MWh and $ notional amounts); changing commodity market prices, primarily for power and natural gas; our credit standing and that of our counterparties and customers for energy commodity derivatives; and prevailing interest rates for our interest rate hedging instruments. Prices for power and natural gas and interest rates are volatile, which can result in material changes in the fair value measurements reported in our financial statements in the future.
We utilize market data, such as pricing services and broker quotes, and assumptions that we believe market participants would use in pricing our assets or liabilities including assumptions about the risks inherent to the inputs in the valuation technique. These inputs can be either readily observable, market corroborated or generally unobservable. The market data obtained from broker pricing services is evaluated to determine the nature of the quotes obtained and, where accepted as a reliable quote, used to validate our assessment of fair value. We use other qualitative assessments to determine the level of activity in any given market. We primarily apply the market approach and income approach for recurring fair value measurements and utilize what we believe to be the best available information. We utilize valuation techniques that seek to maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the observability of those inputs.
The fair value of our derivatives includes consideration of our credit standing, the credit standing of our counterparties and customers and the effect of credit enhancements, if any. We have also recorded credit reserves in the determination of fair value based on our expectation of how market participants would determine fair value. Such valuation adjustments are generally based on market evidence, if available, or our best estimate.
Our level 1 fair value derivative instruments primarily consist of power and natural gas swaps, futures and options traded on the NYMEX or Intercontinental Exchange.
Our level 2 fair value derivative instruments primarily consist of interest rate hedging instruments and OTC power and natural gas forwards for which market-based pricing inputs in the principal or most advantageous market are representative of executable prices for market participants. These inputs are observable at commonly quoted intervals for substantially the full term of the instruments. In certain instances, our level 2 derivative instruments may utilize models to measure fair value. These models are industry-standard models that incorporate various assumptions, including quoted interest rates, correlation, volatility, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Our level 3 fair value derivative instruments may consist of OTC power and natural gas forwards and options where pricing inputs are unobservable, as well as other complex and structured transactions primarily for the sale and purchase of power and natural gas to both wholesale counterparties and retail customers. Complex or structured transactions are tailored to our customers’ needs and can introduce the need for internally-developed model inputs which might not be observable in or corroborated by the market. When such inputs have a significant effect on the measurement of fair value, the instrument is categorized in level 3. Our valuation models may incorporate historical correlation information and extrapolate available broker and other information to future periods. OTC options are valued using industry-standard models, including the Black-Scholes option-pricing model. At each balance sheet date, we perform an analysis of all instruments subject to fair value measurement and include in level 3 all of those whose fair value is based on significant unobservable inputs.

13



Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect our estimate of the fair value of our assets and liabilities and their placement within the fair value hierarchy levels. The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2017 and December 31, 2016, by level within the fair value hierarchy:
 
Assets and Liabilities with Recurring Fair Value Measures as of March 31, 2017
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
166

 
$

 
$

 
$
166

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
1,259

 

 

 
1,259

Commodity forward contracts(2)

 
359

 
402

 
761

Interest rate hedging instruments

 
37

 

 
37

Total assets
$
1,425

 
$
396

 
$
402

 
$
2,223

Liabilities:
 
 
 
 
 
 
 
Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
1,298

 

 

 
1,298

Commodity forward contracts(2)

 
410

 
60

 
470

Interest rate hedging instruments

 
55

 

 
55

Total liabilities
$
1,298

 
$
465

 
$
60

 
$
1,823

 
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2016
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
153

 
$

 
$

 
$
153

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
$
1,695

 
$
260

 
$
466

 
$
2,421

Liabilities:
 
 
 
 
 
 
 
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
$
1,570

 
$
469

 
$
67

 
$
2,106

___________
(1)
As of March 31, 2017 and December 31, 2016, we had cash equivalents of $36 million and $26 million included in cash and cash equivalents and $130 million and $127 million included in restricted cash, respectively.
(2)
Includes OTC swaps and options and retail contracts.

14



At March 31, 2017 and December 31, 2016, the derivative instruments classified as level 3 primarily included commodity contracts, which are classified as level 3 because the contract terms relate to a delivery location or tenor for which observable market rate information is not available. The fair value of the net derivative position classified as level 3 is predominantly driven by market commodity prices. The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at March 31, 2017 and December 31, 2016:
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
 
March 31, 2017
 
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
 
 
 
Power Contracts
 
$
324

 
Discounted cash flow
 
Market price (per MWh)
 
$
8.00

$92.00
/MWh
Power Congestion Products
 
$
11

 
Discounted cash flow
 
Market price (per MWh)
 
$
(7.52
)
$4.54
/MWh
Natural Gas Contracts
 
$
60

 
Discounted cash flow
 
Market price (per MMBtu)
 
$
1.79

$6.24
/MMBtu
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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
The following table sets forth a reconciliation of changes in the fair value of our net derivative assets (liabilities) classified as level 3 in the fair value hierarchy for the periods indicated (in millions):
 
 
Three Months Ended March 31,
 
 
2017
 
2016
Balance, beginning of period
 
$
399

 
$
(46
)
Realized and mark-to-market gains (losses):
 
 
 
 
Included in net income:
 
 
 
 
Included in operating revenues(1)
 
113

 
(22
)
Included in fuel and purchased energy expense(2)
 
13

 
(14
)
Purchases and settlements:
 
 
 
 
Purchases
 

 
2

Settlements
 
(26
)
 
(4
)
Transfers in and/or out of level 3(3):
 
 
 
 
Transfers into level 3(4)
 
(7
)
 

Transfers out of level 3(5)
 
(150
)
 
19

Balance, end of period
 
$
342

 
$
(65
)
Change in unrealized gains (losses) relating to instruments still held at end of period
 
$
126

 
$
(36
)
___________
(1)
For power contracts and other power-related products, included on our Consolidated Condensed Statements of Operations.
(2)
For natural gas and power contracts, swaps and options, included on our Consolidated Condensed Statements of Operations.
(3)
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 for each of the three months ended March 31, 2017 and 2016.

15



(4)
There were $7 million and nil in losses transferred out of level 2 into level 3 for the three months ended March 31, 2017 and 2016, respectively, due to changes in market liquidity in various power markets.
(5)
We had $150 million in gains and $(19) million in losses transferred out of level 3 into level 2 for the three months ended March 31, 2017 and 2016, respectively, due to changes in market liquidity in various power markets.
6.
Derivative Instruments
Types of Derivative Instruments and Volumetric Information
Commodity Instruments — We are exposed to changes in prices for the purchase and sale of power, natural gas, fuel oil, environmental products and other energy commodities. We use derivatives, which include physical commodity contracts and financial commodity instruments such as OTC and exchange traded swaps, futures, options, forward agreements and instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) or instruments that settle on power price relationships between delivery points for the purchase and sale of power and natural gas to attempt to maximize the risk-adjusted returns by economically hedging a portion of the commodity price risk associated with our assets. By entering into these transactions, we are able to economically hedge a portion of our Spark Spread at estimated generation and prevailing price levels.
We also engage in limited trading activities related to our commodity derivative portfolio as authorized by our Board of Directors and monitored by our Chief Risk Officer and Risk Management Committee of senior management. These transactions are executed primarily for the purpose of providing improved price and price volatility discovery, greater market access, and profiting from our market knowledge, all of which benefit our asset hedging activities. Our trading results were not material for each of the three months ended March 31, 2017 and 2016.
Interest Rate Hedging Instruments — A portion of our debt is indexed to base rates, primarily LIBOR. We have historically used interest rate hedging instruments to adjust the mix between fixed and variable rate debt to hedge our interest rate risk for potential adverse changes in interest rates. As of March 31, 2017, the maximum length of time over which we were hedging using interest rate hedging instruments designated as cash flow hedges was 9 years.
As of March 31, 2017 and December 31, 2016, the net forward notional buy (sell) position of our outstanding commodity derivative instruments that did not qualify or were not designated under the normal purchase normal sale exemption and our interest rate hedging instruments were as follows (in millions):
Derivative Instruments
 
Notional Amounts
 
March 31, 2017
 
December 31, 2016
Power (MWh)
 
(78
)
 
(86
)
Natural gas (MMBtu)
 
779

 
613

Environmental credits (Tonnes)
 
16

 
16

Interest rate hedging instruments
 
$
4,600

(1) 
$
3,721

___________
(1)
We entered into interest rate hedging instruments during the first quarter of 2017 to hedge approximately $1.0 billion of variable rate debt for 2018 through 2020 and approximately $500 million of variable rate debt for 2021 through 2022. We also extended the tenor of certain interest rate hedging instruments which effectively places a ceiling on LIBOR on $2.5 billion of variable rate corporate debt through 2020 and $1.25 billion of variable rate corporate debt in 2021.
Certain of our derivative instruments contain credit risk-related contingent provisions that require us to maintain collateral balances consistent with our credit ratings. If our credit rating were to be downgraded, it could require us to post additional collateral or could potentially allow our counterparty to request immediate, full settlement on certain derivative instruments in liability positions. The aggregate fair value of our derivative liabilities with credit risk-related contingent provisions as of March 31, 2017, was $24 million for which we have posted collateral of $2 million by posting margin deposits or granting additional first priority liens on the assets currently subject to first priority liens under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. However, if our credit rating were downgraded by one notch from its current level, we estimate that additional collateral of nil related to our derivative liabilities would be required and that no counterparty could request immediate, full settlement.
Accounting for Derivative Instruments
We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For

16



transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Condensed Statements of Operations until the period of delivery. Revenues and expenses derived from instruments that qualified for hedge accounting or represent an economic hedge are recorded in the same financial statement line item as the item being hedged. Hedge accounting requires us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting. We present the cash flows from our derivatives in the same category as the item being hedged (or economically hedged) within operating activities on our Consolidated Condensed Statements of Cash Flows unless they contain an other-than-insignificant financing element in which case their cash flows are classified within financing activities.
Cash Flow Hedges — We only apply hedge accounting to our interest rate hedging instruments. We report the effective portion of the mark-to-market gain or loss on our interest rate hedging instruments designated and qualifying as a cash flow hedging instrument as a component of OCI and reclassify such gains and losses into earnings in the same period during which the hedged forecasted transaction affects earnings. Gains and losses due to ineffectiveness on interest rate hedging instruments are recognized currently in earnings as a component of interest expense. If it is determined that the forecasted transaction is no longer probable of occurring, then hedge accounting will be discontinued prospectively and future changes in fair value are recorded in earnings. If the hedging instrument is terminated or de-designated prior to the occurrence of the hedged forecasted transaction, the net accumulated gain or loss associated with the changes in fair value of the hedge instrument remains deferred in AOCI until such time as the forecasted transaction affects earnings or until it is determined that the forecasted transaction is probable of not occurring.
Derivatives Not Designated as Hedging Instruments — We enter into power, natural gas, interest rate, environmental product and fuel oil transactions that primarily act as economic hedges to our asset and interest rate portfolio, but either do not qualify as hedges under the hedge accounting guidelines or qualify under the hedge accounting guidelines and the hedge accounting designation has not been elected. Changes in fair value of commodity derivatives not designated as hedging instruments are recognized currently in earnings and are separately stated on our Consolidated Condensed Statements of Operations in mark-to-market gain/loss as a component of operating revenues (for physical and financial power and Heat Rate and commodity option activity) and fuel and purchased energy expense (for physical and financial natural gas, power, environmental product and fuel oil activity). Changes in fair value of interest rate derivatives not designated as hedging instruments are recognized currently in earnings as interest expense.
Derivatives Included on Our Consolidated Condensed Balance Sheets
The following tables present the fair values of our derivative instruments recorded on our Consolidated Condensed Balance Sheets by location and hedge type at March 31, 2017 and December 31, 2016 (in millions):
 
March 31, 2017
  
Commodity
Instruments
 
Interest Rate
Hedging Instruments
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
1,386

 
$
1

 
$
1,387

Long-term derivative assets
634

 
36

 
670

Total derivative assets
$
2,020

 
$
37

 
$
2,057

 
 
 
 
 
 
Current derivative liabilities
$
1,246

 
$
27

 
$
1,273

Long-term derivative liabilities
522

 
28

 
550

Total derivative liabilities
$
1,768

 
$
55

 
$
1,823

Net derivative assets (liabilities)
$
252

 
$
(18
)
 
$
234


17



 
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

 
March 31, 2017
 
December 31, 2016
 
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
$
37

 
$
55

 
$
29

 
$
58

Total derivatives designated as cash flow hedging instruments
$
37

 
$
55

 
$
29

 
$
58

 
 
 
 
 
 
 
 
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity instruments
$
2,020

 
$
1,768

 
$
2,239

 
$
2,048

Total derivatives not designated as hedging instruments
$
2,020

 
$
1,768

 
$
2,239

 
$
2,048

Total derivatives
$
2,057

 
$
1,823

 
$
2,268

 
$
2,106

We elected not to offset fair value amounts recognized as derivative instruments on our Consolidated Condensed Balance Sheets that are executed with the same counterparty under master netting arrangements or other contractual netting provisions negotiated with the counterparty. Our netting arrangements include a right to set off or net together purchases and sales of similar products in the margining or settlement process. In some instances, we have also negotiated cross commodity netting rights which allow for the net presentation of activity with a given counterparty regardless of product purchased or sold. We also post cash collateral in support of our derivative instruments which may also be subject to a master netting arrangement with the same counterparty.

18



The tables below set forth our net exposure to derivative instruments after offsetting amounts subject to a master netting arrangement with the same counterparty at March 31, 2017 and December 31, 2016 (in millions):
 
 
March 31, 2017
 
 
Gross Amounts Not Offset on the Consolidated Condensed Balance Sheets
 
 
Gross Amounts Presented on our Consolidated Condensed Balance Sheets
 
Derivative Asset (Liability) not Offset on the Consolidated Condensed Balance Sheets
 
Margin/Cash (Received) Posted (1)
 
Net Amount
Derivative assets:
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
1,259

 
$
(1,253
)
 
$
(6
)
 
$

Commodity forward contracts
 
761

 
(172
)
 
(11
)
 
578

Interest rate hedging instruments
 
37

 
(5
)
 

 
32

Total derivative assets
 
$
2,057

 
$
(1,430
)
 
$
(17
)
 
$
610

Derivative (liabilities):
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
(1,298
)
 
$
1,253

 
$
45

 
$

Commodity forward contracts
 
(470
)
 
172

 
52

 
(246
)
Interest rate hedging instruments
 
(55
)
 
5

 

 
(50
)
Total derivative (liabilities)
 
$
(1,823
)
 
$
1,430

 
$
97

 
$
(296
)
Net derivative assets (liabilities)
 
$
234

 
$

 
$
80

 
$
314

 
 
December 31, 2016
 
 
Gross Amounts Not Offset on the Consolidated Condensed Balance Sheets
 
 
Gross Amounts Presented on our Consolidated Condensed Balance Sheets
 
Derivative Asset (Liability) not Offset on the Consolidated Condensed 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

____________
(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 7 for a further discussion of our collateral.
Derivatives Included on Our Consolidated Condensed Statements of Operations
Changes in the fair values of our derivative instruments (both assets and liabilities) are reflected either in cash for option premiums paid or collected, in OCI, net of tax, for the effective portion of derivative instruments which qualify for and we have elected cash flow hedge accounting treatment, or on our Consolidated Condensed Statements of Operations as a component of mark-to-market activity within our earnings.

19



The following tables detail the components of our total activity for both the net realized gain (loss) and the net mark-to-market gain (loss) recognized from our derivative instruments in earnings and where these components were recorded on our Consolidated Condensed Statements of Operations for the periods indicated (in millions):
 
Three Months Ended March 31,
 
2017
 
2016
Realized gain (loss)(1)(2)
 
 
 
Commodity derivative instruments
$
29

 
$
118

Total realized gain (loss)
$
29

 
$
118

 
 
 
 
Mark-to-market gain (loss)(3)
 
 
 
Commodity derivative instruments
$
55

 
$
(95
)
Interest rate hedging instruments

 
1

Total mark-to-market gain (loss)
$
55

 
$
(94
)
Total activity, net
$
84

 
$
24

___________
(1)
Does not include the realized value associated with derivative instruments that settle through physical delivery.
(2)
Includes amortization of acquisition date fair value of financial derivative activity related to the acquisition of Champion Energy, Calpine Solutions and North American Power.
(3)
In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.
 
Three Months Ended March 31,
 
2017
 
2016
Realized and mark-to-market gain (loss)(1)
 
 
 
Derivatives contracts included in operating revenues(2)(3)
$
223

 
$
204

Derivatives contracts included in fuel and purchased energy expense(2)(3)
(139
)
 
(181
)
Interest rate hedging instruments included in interest expense(4)

 
1

Total activity, net
$
84

 
$
24

___________
(1)
In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes adjustments to reflect changes in credit default risk exposure.
(2)
Does not include the realized value associated with derivative instruments that settle through physical delivery.
(3)
Includes amortization of acquisition date fair value of financial derivative activity related to the acquisition of Champion Energy, Calpine Solutions and North American Power.
(4)
In addition to changes in market value on interest rate hedging instruments not designated as hedges, changes in mark-to-market gain (loss) also includes hedge ineffectiveness.
Derivatives Included in OCI and AOCI
The following table details the effect of our net derivative instruments that qualified for hedge accounting treatment and are included in OCI and AOCI for the periods indicated (in millions):
 
Three Months Ended March 31,
 
Three Months Ended March 31,
 
Gain (Loss) Recognized in
OCI (Effective Portion)
 
Gain (Loss) Reclassified from
AOCI into Income (Effective Portion)(3)
 
2017
 
2016
 
2017
 
2016
 
Affected Line Item on the Consolidated Condensed Statements of Operations
Interest rate hedging instruments(1)(2)
$
(4
)
 
$
(12
)
 
$
(11
)
 
$
(11
)
 
Interest expense

20



____________
(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 three months ended March 31, 2017 and 2016.
(2)
We recorded an income tax expense of nil for each of the three months ended March 31, 2017 and 2016, 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 $94 million and $90 million at March 31, 2017 and December 31, 2016, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $8 million and $8 million at March 31, 2017 and December 31, 2016, respectively.
We estimate that pre-tax net losses of $38 million would be reclassified from AOCI into interest expense during the next 12 months as the hedged transactions settle; however, the actual amounts that will be reclassified will likely vary based on changes in interest rates. Therefore, we are unable to predict what the actual reclassification from AOCI into earnings (positive or negative) will be for the next 12 months.
7.
Use of Collateral
We use margin deposits, prepayments and letters of credit as credit support with and from our counterparties for commodity procurement and risk management activities. In addition, we have granted additional first priority liens on the assets currently subject to first priority liens under various debt agreements as collateral under certain of our power and natural gas agreements and certain of our interest rate hedging instruments in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to the counterparties under such agreements. The counterparties under such agreements share the benefits of the collateral subject to such first priority liens pro rata with the lenders under our various debt agreements.
The table below summarizes the balances outstanding under margin deposits, natural gas and power prepayments, and exposure under letters of credit and first priority liens for commodity procurement and risk management activities as of March 31, 2017 and December 31, 2016 (in millions):
 
March 31, 2017
 
December 31, 2016
Margin deposits(1)
$
284

 
$
350

Natural gas and power prepayments
24

 
25

Total margin deposits and natural gas and power prepayments with our counterparties(2)
$
308

 
$
375

 
 
 
 
Letters of credit issued
$
738

 
$
798

First priority liens under power and natural gas agreements
217

 
206

First priority liens under interest rate hedging instruments
53

 
55

Total letters of credit and first priority liens with our counterparties
$
1,008

 
$
1,059

 
 
 
 
Margin deposits posted with us by our counterparties(1)(3)
$
9

 
$
16

Letters of credit posted with us by our counterparties
37

 
43

Total margin deposits and letters of credit posted with us by our counterparties
$
46

 
$
59

___________
(1)
Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated Condensed 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 6 for further discussion of our derivative instruments subject to master netting arrangements.
(2)
At March 31, 2017 and December 31, 2016, $298 million and $366 million, respectively, were included in margin deposits and other prepaid expense and $10 million and $9 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets.
(3)
Included in other current liabilities on our Consolidated Condensed Balance Sheets.

21



Future collateral requirements for cash, first priority liens and letters of credit may increase or decrease based on the extent of our involvement in hedging and optimization contracts, movements in commodity prices, and also based on our credit ratings and general perception of creditworthiness in our market.
8.
Income Taxes
Income Tax Expense (Benefit)

The table below shows our consolidated income tax expense (benefit) from continuing operations (excluding noncontrolling interest) and our effective tax rates for the periods indicated (in millions):
 
Three Months Ended March 31,
 
2017
 
2016
Income tax expense (benefit)
$
(61
)
 
$
35

Effective tax rate
52
%
 
(21
)%
Our income tax rates do not bear a customary relationship to statutory income tax rates primarily as a result of the effect of our NOLs, changes in unrecognized tax benefits and valuation allowances. For the three months ended March 31, 2017 and 2016, our income tax expense (benefit) is largely comprised of discrete tax items and estimated state and foreign income taxes in jurisdictions where we do not have NOLs or valuation allowances. During the three months ended March 31, 2017, we recorded an income tax benefit of $17 million associated with a favorable adjustment to our reserve for uncertain tax positions. See Note 10 in our 2016 Form 10-K for further information regarding our NOLs.   
Income Tax Audits — We remain subject to periodic audits and reviews by taxing authorities; however, we do not expect these audits will have a material effect on our tax provision. Any NOLs we claim in future years to reduce taxable income could be subject to IRS examination regardless of when the NOLs occurred. Any adjustment of state or federal returns would likely result in a reduction of deferred tax assets rather than a cash payment of income taxes in tax jurisdictions where we have NOLs. We are currently subject to U.S. federal income tax examination for the year ended December 31, 2015.
Valuation Allowance — U.S. GAAP requires that we consider all available evidence, both positive and negative, and tax planning strategies to determine whether, based on the weight of that evidence, a valuation allowance is needed to reduce the value of deferred tax assets. Future realization of the tax benefit of an existing deductible temporary difference or carryforward ultimately depends on the existence of sufficient taxable income of the appropriate character within the carryback or carryforward periods available under the tax law. Due to our history of losses, we were unable to assume future profits; however, we are able to consider available tax planning strategies.
Unrecognized Tax Benefits — At March 31, 2017, we had unrecognized tax benefits of $48 million. If recognized, $10 million of our unrecognized tax benefits could affect the annual effective tax rate and $38 million, related to deferred tax assets, could be offset against the recorded valuation allowance resulting in no effect on our effective tax rate. We had accrued interest and penalties of $3 million for income tax matters at March 31, 2017. We recognize interest and penalties related to unrecognized tax benefits in income tax expense (benefit) on our Consolidated Condensed Statements of Operations. We believe that it is reasonably possible that a decrease within the range of nil and $7 million in unrecognized tax benefits could occur within the next twelve months primarily related to foreign tax issues.
9.
Loss per Share
We include restricted stock units for which no future service is required as a condition to the delivery of the underlying common stock in our calculation of weighted average shares outstanding. As we incurred a net loss for the three months ended March 31, 2017 and 2016, diluted loss per share for each period is computed on the same basis as basic loss per share, as the inclusion of any other potential shares outstanding would be anti-dilutive. We excluded the following items from diluted earnings per common share for the three months ended March 31, 2017 and 2016, because they were anti-dilutive (shares in thousands):
 
Three Months Ended March 31,
 
 
2017
 
2016
 
Share-based awards
4,743

 
4,468

 

22



10.
Stock-Based Compensation
Calpine Equity Incentive Plans
The Calpine Equity Incentive Plans provide for the issuance of equity awards to all non-union employees as well as the non-employee members of our Board of Directors. The equity awards may include incentive or non-qualified stock options, restricted stock, restricted stock units, stock appreciation rights, performance compensation awards and other share-based awards. The equity awards granted under the Calpine Equity Incentive Plans include both graded and cliff vesting awards which vest over periods between one and five years, contain contractual terms between approximately five and ten years and are subject to forfeiture provisions under certain circumstances, including termination of employment prior to vesting. At March 31, 2017, 84,221 shares and 878,194 shares remain available for future grants under the Director Plan and the Equity Plan, respectively.
Equity Classified Share-Based Awards
Stock-based compensation expense recognized for our equity classified share-based awards was $8 million and $7 million for the three months ended March 31, 2017 and 2016, respectively. We did not record any significant tax benefits related to stock-based compensation expense in any period as we are not benefiting from a significant portion of our deferred tax assets, including deductions related to stock-based compensation expense. In addition, we did not capitalize any stock-based compensation expense as part of the cost of an asset for the three months ended March 31, 2017 and 2016. At March 31, 2017, there was unrecognized compensation cost of $40 million related to restricted stock and $6 million related to options which is expected to be recognized over a weighted average period of 2.0 years for restricted stock and 2.6 years for options. We issue new shares from our share reserves set aside for the Calpine Equity Incentive Plans when stock options are exercised and for other share-based awards.
A summary of all of our non-qualified stock option activity for the Equity Plan for the three months ended March 31, 2017, is as follows:
 
Number of
Shares
 
Weighted Average
Exercise Price
 
Weighted
Average
Remaining
Term
(in years)
 
Aggregate
Intrinsic Value
(in millions)
Outstanding — December 31, 2016
2,697,136

 
$
13.59

 
3.0
 
$
2

Granted
1,460,909

 
$
11.69

 
 
 
 
Forfeited
15,721

 
$
11.69

 
 
 
 
Expired
6,200

 
$
17.50

 
 
 
 
Outstanding — March 31, 2017
4,136,124

 
$
12.92

 
5.2
 
$
1

Exercisable — March 31, 2017
2,690,936

 
$
13.58

 
2.7
 
$
1

Vested and expected to vest – March 31, 2017
3,930,873

 
$
12.98

 
5.0
 
$
1

The fair value of options granted during the three months ended March 31, 2017, was determined on the grant date using the Black-Scholes option-pricing model. Certain assumptions were used in order to estimate fair value for options as noted in the following table:
 
2017
 
Expected term (in years)(1)
7.32

 
Risk-free interest rate(2)
2.25

%
Expected volatility(3)
40

%
Dividend yield(4)

 
Weighted average grant-date fair value (per option)
$
5.38

 
___________
(1)
Expected term calculated using historical exercise data.
(2)
Zero Coupon U.S. Treasury rate or equivalent based on expected term.
(3)
Volatility calculated using the implied volatility of our exchange traded stock options.
(4)
We have never paid cash dividends on our common stock and we do not anticipate any cash dividend payments on our common stock in the near future.

23



A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the three months ended March 31, 2017, is as follows:
 
Number of
Restricted
Stock Awards
 
Weighted
Average
Grant-Date
Fair Value
Nonvested — December 31, 2016
4,869,648

 
$
15.83

Granted
2,546,223

 
$
11.70

Forfeited
340,080

 
$
14.28

Vested
1,465,907

 
$
17.13

Nonvested — March 31, 2017
5,609,884

(1) 
$
13.71

___________
(1)
Includes 49,897 shares of restricted stock and restricted stock units outstanding under the Director Plan and 5,559,987 shares of restricted stock and restricted stock units outstanding under the Equity Plan.
The total fair value of our restricted stock and restricted stock units that vested during the three months ended March 31, 2017 and 2016 was approximately $17 million and $15 million, respectively.
Liability Classified Share-Based Awards
During the first quarter of 2017, our Board of Directors approved the award of performance share units to certain senior management employees. These performance share units will be settled in cash with payouts based on the relative performance of Calpine’s total shareholder return over the three-year performance period of January 1, 2017 through December 31, 2019. The performance share units vest on the last day of the performance period and will be settled in cash; thus, these awards are liability classified and are measured at fair value using a Monte Carlo simulation model at each reporting date until settlement. Stock-based compensation expense recognized related to our liability classified share-based awards was nil and $2 million for the three months ended March 31, 2017 and 2016, respectively.
A summary of our performance share unit activity for the three months ended March 31, 2017, is as follows:
 
Number of
Performance Share Units
 
Weighted
Average
Grant-Date
Fair Value
Nonvested — December 31, 2016
890,587

 
$
17.90

Granted
472,278

 
$
10.69

Forfeited
54,638

 
$
18.38

Vested(1)
5,810

 
$
14.81

Nonvested — March 31, 2017
1,302,417

 
$
15.28

___________
(1)
In accordance with the applicable performance share unit agreements, performance share units granted to employees who meet the retirement eligibility requirements stipulated in the Equity Plan are fully vested upon the later of the date on which the employee becomes eligible to retire or one-year anniversary of the grant date.
For a further discussion of the Calpine Equity Incentive Plans, see Note 12 in our 2016 Form 10-K.
11.
Commitments and Contingencies
Litigation
We are party to various litigation matters, including regulatory and administrative proceedings arising out of the normal course of business. At the present time, we do not expect that the outcome of any of these proceedings, individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.
On a quarterly basis, we review our litigation activities and determine if an unfavorable outcome to us is considered “remote,” “reasonably possible” or “probable” as defined by U.S. GAAP. Where we determine an unfavorable outcome is probable and is reasonably estimable, we accrue for potential litigation losses. The liability we may ultimately incur with respect to such litigation matters, in the event of a negative outcome, may be in excess of amounts currently accrued, if any; however, we do not expect that the reasonably possible outcome of these litigation matters would, individually or in the aggregate, have a material adverse effect on our financial condition, results of operations or cash flows. Where we determine an unfavorable outcome is not

24



probable or reasonably estimable, we do not accrue for any potential litigation loss. The ultimate outcome of these litigation matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated. As a result, we give no assurance that such litigation matters would, individually or in the aggregate, not have a material adverse effect on our financial condition, results of operations or cash flows.
Environmental Matters
We are subject to complex and stringent environmental laws and regulations related to the operation of our power plants. On occasion, we may incur environmental fees, penalties and fines associated with the operation of our power plants. At the present time, we do not have environmental violations or other matters that would have a material effect on our financial condition, results of operations or cash flows or that would significantly change our operations.
California Air Resources Board. On November 8, 2016, Russell City Energy Center, LLC received a notice of violation for exceeding CARB’s annual emission limits for Sulfur Hexafluoride (“SF6”) due to a leak of SF6 during 2015 from one of the high voltage circuit breakers located in the Russell City Energy Center switchyard. SF6 is a gas used as an electrical insulator in high voltage circuit breakers and is a GHG. A monetary penalty has not yet been imposed by CARB. The liability we may ultimately incur with respect to this matter has not been determined, but it is not expected to be material.
Guarantees and Indemnifications
Our potential exposure under guarantee and indemnification obligations can range from a specified amount to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. Our total maximum exposure under our guarantee and indemnification obligations is not estimable due to uncertainty as to whether claims will be made or how any potential claim will be resolved. As of March 31, 2017, there are no material outstanding claims related to our guarantee and indemnification obligations and we do not anticipate that we will be required to make any material payments under our guarantee and indemnification obligations. There have been no material changes to our guarantees and indemnifications from those disclosed in Note 15 of our 2016 Form 10-K.
12.
Segment Information
We assess our business on a regional basis due to the effect on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors affecting supply and demand. At March 31, 2017, our reportable segments were West (including geothermal), Texas and East (including Canada). The results of our retail subsidiaries are reflected in the segment which corresponds with the geographic area in which the retail sales occur. We continue to evaluate the optimal manner in which we assess our performance including our segments and future changes may result in changes to the composition of our geographic segments. Commodity Margin is a key operational measure reviewed by our chief operating decision maker to assess the performance of our segments. The tables below show our financial data for our segments for the periods indicated (in millions):

25



 
Three Months Ended March 31, 2017
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
712

 
$
799

 
$
770

 
$

 
$
2,281

Intersegment revenues
2

 
3

 
2

 
(7
)
 

Total operating revenues
$
714

 
$
802

 
$
772

 
$
(7
)
 
$
2,281

Commodity Margin
$
221

 
$
148

 
$
189

 
$

 
$
558

Add: Mark-to-market commodity activity, net and other(1)
77

 
(30
)
 
(8
)
 
(8
)
 
31

Less:
 
 
 
 
 
 
 
 
 
Plant operating expense
97

 
96

 
96

 
(7
)
 
282

Depreciation and amortization expense
91

 
62

 
53

 

 
206

Sales, general and other administrative expense
13

 
17

 
10

 

 
40

Other operating expenses
9

 
3

 
9

 
(1
)
 
20

(Gain) on sale of assets, net

 

 
(27
)
 

 
(27
)
(Income) from unconsolidated subsidiaries

 

 
(4
)
 

 
(4
)
Income (loss) from operations
88

 
(60
)
 
44

 

 
72

Interest expense
 
 
 
 
 
 
 
 
159

Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
26

Loss before income taxes
 
 
 
 
 
 
 
 
$
(113
)

 
Three Months Ended March 31, 2016
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
424

 
$
532

 
$
659

 
$

 
$
1,615

Intersegment revenues
2

 
3

 
3

 
(8
)
 

Total operating revenues
$
426

 
$
535

 
$
662

 
$
(8
)
 
$
1,615

Commodity Margin
$
197

 
$
153

 
$
230

 
$

 
$
580

Add: Mark-to-market commodity activity, net and other(1)
46

 
(110
)
 
(21
)
 
(6
)
 
(91
)
Less:
 
 
 
 
 
 
 
 
 
Plant operating expense
91

 
86

 
84

 
(6
)
 
255

Depreciation and amortization expense
69

 
53

 
58

 

 
180

Sales, general and other administrative expense
10

 
16

 
12

 

 
38

Other operating expenses
8

 
2

 
10

 

 
20

(Income) from unconsolidated subsidiaries

 

 
(7
)
 

 
(7
)
Income (loss) from operations
65

 
(114
)
 
52

 

 
3

Interest expense
 
 
 
 
 
 
 
 
157

Other (income) expense, net
 
 
 
 
 
 
 
 
5

Loss before income taxes
 
 
 
 
 
 
 
 
$
(159
)
_________
(1)
Includes $(22) million and $(22) million of lease levelization and $60 million and $27 million of amortization expense for the three months ended March 31, 2017 and 2016, respectively.


26



Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Forward-Looking Information
This Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our accompanying Consolidated Condensed Financial Statements and related Notes. See the cautionary statement regarding forward-looking statements at the beginning of this Report for a description of important factors that could cause actual results to differ from expected results.
Introduction and Overview
We are one of the largest power generators in the U.S. measured by power produced. We own and operate primarily natural gas-fired and geothermal power plants in North America and have a significant presence in major competitive wholesale power markets in California (included in our West segment), Texas (included in our Texas segment) and the Northeast and Mid-Atlantic regions (included in our East segment) of the U.S. We sell power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities and other governmental entities, power marketers as well as retail commercial, industrial, governmental and residential customers. We continue to focus on getting closer to our customers through expansion of our retail platform which began with the acquisition of Champion Energy in 2015 and was followed by the acquisitions of Calpine Solutions in late 2016 and North American Power in early 2017. We have invested in clean power generation to become a recognized leader in developing, constructing, owning and operating an environmentally responsible portfolio of flexible and reliable power plants.
In order to manage our various physical assets and contractual obligations, we execute commodity and commodity transportation agreements within the guidelines of our Risk Management Policy. We purchase primarily natural gas and some fuel oil as fuel for our power plants and engage in related natural gas transportation and storage transactions. We also purchase power for sale to our customers and purchase electric transmission rights to deliver power to our customers. Additionally, consistent with our Risk Management Policy, we enter into natural gas, power, environmental product, fuel oil and other physical and financial commodity contracts to hedge certain business risks and optimize our portfolio of power plants. Seasonality and weather can have a significant effect on our results of operations and are also considered in our hedging and optimization activities.
Our capital allocation philosophy seeks to maximize levered cash returns to equity while maintaining a strong balance sheet. We seek to enhance shareholder value through a diverse and balanced capital allocation approach that includes portfolio management, organic or acquisitive growth, returning capital to shareholders and debt reduction. The mix of this activity shifts over time given the external market environment and the opportunity set. In the current environment, we believe that paying down debt and strengthening our balance sheet is a high return investment for our shareholders. We also consider the repurchases of our own shares of common stock as an attractive investment opportunity, and we utilize the expected returns from this investment as the benchmark against which we evaluate all other capital allocation decisions. We believe this philosophy closely aligns our objectives with those of our shareholders.
Our goal is to be recognized as the premier competitive power company in the U.S. as viewed by our employees, shareholders, customers and policy-makers as well as the communities in which our facilities are located. We continue to make significant progress to deliver long-term shareholder value through operational excellence at our power plants and in our customer and commercial activity, as well as through our disciplined approach to capital allocation with the following achievements during 2017:
We produced approximately 21 million MWh of electricity during the three months ended March 31, 2017.
Our entire fleet achieved a starting reliability of 97.5% during the three months ended March 31, 2017.
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.
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 has been integrated into our Champion Energy retail platform.
As part of our stated goal to reduce debt and interest expense, on March 6, 2017, we redeemed the remaining $453 million of our outstanding 2023 First Lien Notes using cash on hand along with the proceeds from the 2019 First Lien Term Loan which contains a substantially lower variable rate of LIBOR plus 1.75% per annum. We intend to repay

27



the 2019 First Lien Term Loan in full by the end of 2018. This accelerates debt reduction and results in substantial annual interest savings of more than $20 million.
We repaid approximately $150 million in borrowings under our 2017 First Lien Term Loan using cash on hand during the first quarter of 2017.
We successfully originated a new ten-year PPA with a customer in our Texas segment, in lieu of constructing a 418 MW natural gas-fired peaking power plant.
We entered into an agreement with a third party to build an approximately 360 MW natural gas-fired peaking power plant located near Bogalusa, LA which will be sold to the third party for a fixed payment, including a fair market return, after commercial operation and subject to the power plant meeting certain performance objectives.
We assess our business on a regional basis due to the effect on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors affecting supply and demand. Our reportable segments are West (including geothermal), Texas and East (including Canada).
Our portfolio, including partnership interests, consists of 80 power plants, including one under construction, with an aggregate current generation capacity of 25,908 MW and 828 MW under construction. Our fleet, including projects under construction, consists of 65 natural gas-fired combustion turbine-based plants, one fuel oil-fired steam-based plant, 13 geothermal steam turbine-based plants and one photovoltaic solar plant. Our segments have an aggregate generation capacity of 7,425 MW in the West, 9,027 MW in Texas and 9,456 MW with an additional 828 MW under construction in the East. Inclusive of our power generation portfolio and our retail sales platforms, we serve customers in 25 states in the U.S. and in Canada and Mexico.
Legislative and Regulatory Update
We are subject to complex and stringent energy, environmental and other laws and regulations at the federal, state and local levels as well as rules within the ISO and RTO markets in which we participate. Federal and state legislative and regulatory actions, including those by ISO/RTOs, continue to change how our business is regulated. We are actively participating in these debates at the federal, regional, state and ISO/RTO levels. Significant updates are discussed below. For a further discussion of the environmental and other governmental regulations that affect us, see “— Governmental and Regulatory Matters” in Part I, Item 1 of our 2016 Form 10-K.
U.S. Department of Energy Study
U.S. Department of Energy (“DOE”) Secretary Rick Perry has directed his staff to undertake a study to analyze the effect of regulations, mandates, and subsidies on baseload generation resources and electric grid reliability. The request for the study is a result of concerns over the closures of baseload resources, which the Secretary deems as critical to a well-functioning electric grid. The DOE will undertake the study over a 60 day period starting from April 19, 2017 and will explore:
The evolution of wholesale electricity markets, including the extent to which federal policy interventions and the changing nature of the electricity fuel mix are challenging the original policy assumptions that shaped the creation of those markets;
Whether wholesale energy and capacity markets are adequately compensating attributes such as on-site fuel supply and other factors that strengthen grid resilience and, if not, the extent to which this could affect grid reliability and resilience in the future; and
The extent to which continued regulatory burdens, as well as mandates and tax and subsidy policies, are responsible for forcing the premature retirement of baseload power plants.
The results of the study will be used to develop policy recommendations and solutions to protect the reliability and resiliency of the electric grid, ensure electricity affordability, and assure fuel diversity. We plan to provide input to the DOE on this study. The effect on our business of this study is currently unknown.
CAISO
The CPUC and CAISO continue to evaluate capacity procurement policies and products for the California power market. With the expectation of significant increases in renewables, both entities are evaluating the need for operational flexibility, including the ability to start and ramp quickly as well as the ability to operate efficiently at low output levels or cycle off. We are an active participant in these discussions and support products and policies that would provide appropriate compensation for the required attributes. As these proceedings are ongoing, we cannot predict the ultimate effect on our financial condition, results of operations or cash flows, although we believe our fleet offers many features that can, and do, provide operational flexibility to the power markets.

28



The CAISO is increasingly concerned with the premature retirement of uneconomic generation resources. It is evaluating the viability of units it deems at risk of retirement in local, reliability constrained areas through its transmission planning process. It is also considering modifications to the review and approval of compensation for units threatened by economic retirement, but needed for reliability under the Reliability Must Run or Capacity Procurement Mechanism portions of its tariff.
As a result of the pending expiration of a PPA in December 2017, we informed the CAISO of our intent to suspend operations at four of our California peaking natural-gas fired power plants with capacity totaling 186 MW. CAISO has determined that two of these power plants, Yuba City and Feather River Energy Centers, are needed to continue reliable operation of the power grid. We are currently negotiating Reliability Must Run contracts for these two power plants. We do not anticipate the suspension of operations at our other two peaking power plants will have a material effect on our financial condition, results of operations or cash flows.
ERCOT
The PUCT is considering changes regarding its approach to resource adequacy, including price formation and scarcity pricing as operating reserves decline. ERCOT successfully launched the Operating Reserve Demand Curve (“ORDC”) functionality on June 1, 2014. This application produces a price “adder” to the clearing price of energy that increases as reserve capacity declines. The PUCT requested a review of the effectiveness of the ORDC and requested input from ERCOT and market participants, including any recommendations to improve the ORDC. The PUCT continues to consider the appropriate reliability standard that should be used to set ERCOT’s planning reserve margin. As these proceedings are ongoing and the timing of these changes is uncertain, we cannot predict the ultimate effect on our financial condition, results of operations or cash flows.
PJM
In Ohio, after FirstEnergy Corp. (“FE”) submitted various proposals to the Public Utility Commission of Ohio (“PUCO”) to enhance its generation company revenue, the PUCO approved a Distribution Modernization Rider (“DMR”) for the FE utilities that results in approximately $200 million per year for three years of ratepayer subsidized payments to FE. The PUCO’s order approving the DMR has been challenged by several parties. Appeals to the Ohio Supreme Court were dismissed as premature, and appeals to the PUCO remain pending. In a related move, the Ohio utilities, led by American Electric Power, Inc. and FE, have indicated their intentions to advocate for some form of re-regulation in this year’s legislative session which began on January 3, 2017. Re-regulation will require enabling legislation, and to date no proposal has been made public by the utilities. On April 6, 2017, at the behest of FE, a bill was introduced in the Ohio Senate to subsidize FE’s Ohio nuclear power plants. An identical bill was introduced in the Ohio House of Representatives on April 10, 2017. While we cannot predict the likelihood of this legislation passing, we believe the proposed subsidies would frustrate the operation of PJM’s wholesale market structure that is regulated by the FERC.
Over significant opposition, the Illinois legislature voted to approve an out-of-market nuclear subsidy scheme put forward by Exelon Corporation (“Exelon”). Zero Emission Credits (“ZECs”) are to be paid to Exelon’s nuclear units beginning with the planning year commencing June 1, 2017. We believe these subsidies will frustrate the operation of the wholesale market structure regulated by the FERC. In February 2017, Calpine, along with a group of generators and our trade association, the Electric Power Supply Association, filed a lawsuit in federal district court challenging the ZEC legislation on constitutional grounds. We cannot predict the outcome of this litigation.
In November 2016, PJM filed proposed tariff changes with the FERC that allow increased seasonal resource participation in the Capacity Performance auction, effective for the 2020/2021 base residual auction that will be held in May 2017. Because the FERC does not have a quorum of FERC commissioners to rule on the filing, the FERC staff accepted PJM’s filing, subject to refund. As a result, the 2020/2021 base residual auction will be conducted subject to refund and further FERC order. We support PJM’s proposal and believe the tariff changes preserve the competitiveness of the PJM power market; however, we cannot predict whether the FERC will approve PJM’s proposal or the ultimate effect on our financial condition, results of operations or cash flows.
Effective May 11, 2017, PJM will implement transient/scarcity pricing on a five minute basis as ordered by the FERC. This new pricing regime is likely to increase energy revenues in the real-time energy market as well as reserve revenues. 
ISO-NE
ISO-NE has requested that the FERC approve a revised Cost of New Entry (“Net CONE”) parameter beginning with the 2018 Forward Capacity Auction for the 2021/2022 delivery period which is lower than the previous Net CONE. The potential effect on our business is currently unknown.
On April 17, 2017, ISO-NE released a “White Paper” setting forth their proposal to gradually allow state-subsidized

29



renewable generation to enter the capacity market in a manner that minimizes the pricing effect on existing resources. ISO-NE expects to move this through committee and finalize associated details culminating in a FERC filing in the fourth quarter of 2017.
On March 27, 2017, the Massachusetts Department of Public Utilities approved the issuance of a Request for Proposals (“RFP”) for up to 2,800 MW of new “land-based” renewable resources. A separate RFP for offshore wind will be issued this summer. We believe the subsidies provided to these new renewable resources will adversely affect the power markets in ISO-NE by artificially suppressing prices.
Connecticut is considering legislation that would allow the Millstone nuclear power plant to bid into an RFP to potentially obtain a five-year power purchase agreement. It is unknown whether the legislation will pass, but if it does pass, we believe the subsidies provided through the legislation will adversely affect the power markets in ISO-NE by artificially suppressing prices.
NYISO
On August 1, 2016, the New York State Public Service Commission (“PSC”) approved the Clean Energy Standard which requires 50% of the state’s generation to be produced by renewable resources by 2030. In addition, the Clean Energy Standard provides for out-of-market financial subsidies for some of the state’s existing nuclear generation facilities. In October 2016, a group of generators and our trade association, the Electric Power Supply Association, filed a lawsuit in federal court challenging the PSC’s ruling on constitution grounds. We cannot predict the outcome of that litigation, but if left unchecked, we believe these subsidies will adversely affect the power markets in NYISO by artificially suppressing prices. As we do not have a substantial power generation presence in NYISO, the potential effect of the out-of-market financial subsidies are not expected to have a material effect on our financial condition, results of operations or cash flows. However, the subsidies could be meaningful to other power companies in the NYISO region.
FERC Technical Conference
In response to the significant state actions occurring in the New England, New York and PJM regions, the FERC staff has scheduled a technical conference to be held in May 2017 to discuss state interventions, and to explore whether there are ways to accommodate state policy preferences while preserving the benefits of regional markets and economic resource selection. Our President and Chief Executive Officer, Thad Hill, has been selected to participate in the technical conference.
IESO
Ontario implemented a new GHG law with an associated Cap-and-Trade program effective January 1, 2017. This program requires power generators to either acquire related CO2 allowances on their own behalf or, in most cases, the natural gas pipeline supplying the power generation facility will procure such allowances and bill the power generator in the form of a CO2 surcharge on its natural gas transportation invoice. Greenfield LP has a long-term Clean Energy Supply Contract with the IESO, successor to the Ontario Power Authority. We are negotiating with the IESO for the full pass-through of CO2 cost. On a related note, Whitby has a PPA with the Ontario Electricity Financial Corporation, successor to Ontario Hydro. Whitby is also seeking to recover related CO2 cost being applied to its natural gas transportation invoice. As this issue is ongoing, we cannot predict the ultimate effect on our financial condition, results of operations or cash flows.
Clean Power Plan
The Clean Power Plan requires a reduction in GHG emissions from existing power plants of 32% from 2005 levels by 2030. The U.S. Supreme Court issued a stay of the Clean Power Plan until the U.S. Court of Appeals for the District of Columbia Circuit (“D.C. Circuit”) issues a ruling on the merits and through final determination in any further appeal to the U.S. Supreme Court from the D.C. Circuit decision. The D.C. Circuit heard oral argument on September 27, 2016. On March 28, 2017, the President issued an Executive Order, “Promoting Energy Independence and Economic Growth,” which orders, among other things, the EPA to review the Clean Power Plan for consistency with policies articulated by the Executive Order and, if appropriate, to commence a rulemaking to suspend, revise or rescind the Clean Power Plan. On the same day, the EPA asked the D.C. Circuit to hold the ongoing litigation in abeyance until completion of the ongoing review and any subsequent rulemaking. We believe that we are well positioned to comply with the provisions of the Clean Power Plan and expect it to be beneficial to Calpine as regulations protecting the environment positively benefit our competitive position by recognizing the value of our investments in clean and efficient power generation technology.
California: GHG – Cap-and-Trade Regulation
The Cap-and-Trade Regulation has been subject to legal challenges claiming that, by requiring covered entities to obtain allowances, some of which are sold by the state and generate revenue used to achieve GHG reductions in accordance with California law, the Cap-and-Trade Regulation amounts to an unlawful tax. California law requires a two-thirds supermajority vote of the legislature to impose new taxes and AB 32 was not passed by a supermajority. On April 6, 2017, the California Court of Appeal

30



affirmed the decision of the trial court that the Cap-and-Trade Regulation does not amount to an unlawful tax because allowances are valuable commodities, which entities voluntarily purchase to comply with the Cap-and-Trade Regulation. The decision of the Court of Appeal may be appealed to the California Supreme Court.


31



RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 2017 AND 2016
Below are our results of operations for the three months ended March 31, 2017 as compared to the same period in 2016 (in millions, except for percentages and operating performance metrics). In the comparative tables below, increases in revenue/income or decreases in expense (favorable variances) are shown without brackets while decreases in revenue/income or increases in expense (unfavorable variances) are shown with brackets.
 
2017
 
2016
 
Change
 
% Change
Operating revenues:
 
 
 
 
 
 
 
Commodity revenue
$
2,063

 
$
1,585

 
$
478

 
30

Mark-to-market gain
214

 
25

 
189

 
#

Other revenue
4

 
5

 
(1
)
 
(20
)
Operating revenues
2,281

 
1,615

 
666

 
41

Operating expenses:
 
 
 
 
 
 
 
Fuel and purchased energy expense:
 
 
 
 
 
 
 
Commodity expense
1,533

 
1,006

 
(527
)
 
(52
)
Mark-to-market loss
159

 
120

 
(39
)
 
(33
)
Fuel and purchased energy expense
1,692

 
1,126

 
(566
)
 
(50
)
Plant operating expense
282

 
255

 
(27
)
 
(11
)
Depreciation and amortization expense
206

 
180

 
(26
)
 
(14
)
Sales, general and other administrative expense
40

 
38

 
(2
)
 
(5
)
Other operating expenses
20

 
20

 

 

Total operating expenses
2,240

 
1,619

 
(621
)
 
(38
)
(Gain) on sale of assets, net
(27
)
 

 
27

 
#

(Income) from unconsolidated subsidiaries
(4
)
 
(7
)
 
(3
)
 
(43
)
Income from operations
72

 
3

 
69

 
#

Interest expense
159

 
157

 
(2
)
 
(1
)
Debt extinguishment costs
24

 

 
(24
)
 
#

Other (income) expense, net
2

 
5

 
3

 
60

Loss before income taxes
(113
)
 
(159
)
 
46

 
29

Income tax expense (benefit)
(61
)
 
35

 
96

 
#

Net loss
(52
)
 
(194
)
 
142

 
73

Net income attributable to the noncontrolling interest
(4
)
 
(4
)
 

 

Net loss attributable to Calpine
$
(56
)
 
$
(198
)
 
$
142

 
72

 
2017
 
2016
 
Change
 
% Change
Operating Performance Metrics:
 
 
 
 
 
 
 
MWh generated (in thousands)(1)(2)
20,824

 
24,125

 
(3,301
)
 
(14
)
Average availability(2)
87.3
%
 
89.9
%
 
(2.6
)%
 
(3
)
Average total MW in operation(1)
25,274

 
26,238

 
(964
)
 
(4
)
Average capacity factor, excluding peakers
42.8
%
 
47.4
%
 
(4.6
)%
 
(10
)
Steam Adjusted Heat Rate(2)
7,346

 
7,264

 
(82
)
 
(1
)
__________
#
Variance of 100% or greater
(1)
Represents generation and capacity from power plants that we both consolidate and operate and excludes Greenfield LP, Whitby, Freeport Energy Center, 21.5% of Hidalgo Energy Center and 25% each of Freestone Energy Center and Russell City Energy Center.
(2)
Generation, average availability and Steam Adjusted Heat Rate exclude power plants and units that are inactive.

32



We evaluate our Commodity revenue and Commodity expense on a collective basis as the price of power and natural gas tend to move together because the price for power is generally determined by the variable operating cost of the next marginal generator to be dispatched to meet demand. The spread between our Commodity revenue and Commodity expense represents a significant portion of our Commodity Margin. Our financial performance is correlated to how we maximize our Commodity Margin through management of our portfolio of power plants, as well as our hedging and optimization activities. See additional segment discussion in “Commodity Margin and Adjusted EBITDA.”
Commodity revenue, net of Commodity expense, decreased $49 million for the three months ended March 31, 2017, compared to the same period in 2016, primarily due to:
(in millions)
 
 
$
(18
)
 
Lower regulatory capacity revenue in the East segment partially offset by higher resource adequacy revenues in the West segment(1)
(12
)
 
The net period-over-period effect of our portfolio management activities, primarily including the sales of the 375 MW Mankato Power Plant in October 2016 and the 599 MW Osprey Energy Center in January 2017(1)
8

 
Higher energy margins due to increased contribution from our retail hedging activity following the acquisitions of Calpine Solutions in December 2016 and North American Power in January 2017 and the positive effect of a new PPA associated with our Morgan Energy Center in the East segment, which became effective in February 2016. These factors were partially offset by decreased contribution from wholesale hedges and weaker market conditions(1)
(27
)
 
Contract amortization, lease levelization related to tolling contracts and other(2)
$
(49
)
 
 
__________
(1)
These items comprise the period-over-period 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 period-over-period 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 items.     
Mark-to-market gain/loss from hedging our future generation, retail activities and fuel needs had a favorable variance of $150 million primarily driven by the change in forward commodity prices on our forward derivative contracts during the quarter ended March 31, 2017 compared to the same period in 2016 and due to the positive effect of our retail hedging activities.
Our normal, recurring plant operating expense decreased by $1 million for the three months ended March 31, 2017 compared to the same period in 2016, after excluding the effect of a $25 million increase due to the period-over-period effect of power plant portfolio changes and the acquisitions of our retail subsidiaries Calpine Solutions in December 2016 and North American Power in January 2017 as well as a $3 million increase related to severance costs incurred during the first quarter of 2017.
Depreciation and amortization expense increased by $26 million for the three months ended March 31, 2017 compared to the same period in 2016 primarily due to the acquisitions of Granite Ridge Energy Center and Calpine Solutions in February 2016 and December 2016, respectively, accelerated depreciation associated with the retirement of our Clear Lake Power Plant in February 2017 and an adjustment to South Point Energy Center to record at fair value as it was reclassified to held and used during the quarter.
In line with our strategy to focus on competitive wholesale markets and sell or contract power plants located in power markets dominated by regulated utilities or outside our strategic concentration, we completed the sale of the Osprey Energy Center in our East segment on January 3, 2017, resulting in a gain on sale of assets, net of $27 million during the three months ended March 31, 2017.
Debt extinguishment costs for the three months ended March 31, 2017, consisted of $21 million in connection with the redemption of our 2023 First Lien Notes in March 2017, which is comprised of $18 million in prepayment penalty and $3 million from the write-off of debt issuance costs, as well as $3 million in debt extinguishment costs from the write-off of debt issuance costs associated with the $150 million partial repayment of our 2017 First Lien Term Loan in March 2017.
During the three months ended March 31, 2017, we recorded an income tax benefit of $61 million compared to income tax expense of $35 million for the three months ended March 31, 2016. The favorable period-over-period change primarily resulted from estimated state and foreign income tax benefits in jurisdictions where we do not record a valuation allowance on NOLs and

33



a favorable adjustment to our reserve for uncertain tax positions.
COMMODITY MARGIN AND ADJUSTED EBITDA
Management’s Discussion and Analysis of Financial Condition and Results of Operations includes financial information prepared in accordance with U.S. GAAP, as well as the non-GAAP financial measures, Commodity Margin and Adjusted EBITDA, discussed below, which we use as measures of our performance. Generally, a non-GAAP financial measure is a numerical measure of financial performance or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with U.S. GAAP.
We use Commodity Margin, a non-GAAP financial measure, to assess our performance by our reportable segments. Commodity Margin includes our 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 mark-to-market activity and other revenues. We believe that Commodity Margin is a useful tool for assessing the performance of our core operations and is a key operational measure reviewed by our chief operating decision maker. Commodity Margin is not a measure calculated in accordance with U.S. GAAP and should be viewed as a supplement to and not a substitute for our results of operations presented in accordance with U.S. GAAP. Commodity Margin does not intend to represent income from operations, the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. See Note 12 of the Notes to Consolidated Condensed Financial Statements for a reconciliation of Commodity Margin to income (loss) from operations by segment.
Commodity Margin by Segment for the Three Months Ended March 31, 2017 and 2016
The following tables show our Commodity Margin and related operating performance metrics by segment for the three months ended March 31, 2017 and 2016 (exclusive of the noncontrolling interest). In the comparative tables below, favorable variances are shown without brackets while unfavorable variances are shown with brackets. The MWh generated by segment below represent generation from power plants that we both consolidate and operate. Generation, average availability and Steam Adjusted Heat Rate exclude power plants and units that are inactive.
West:
2017
 
2016
 
Change
 
% Change
Commodity Margin (in millions)
$
221

 
$
197

 
$
24

 
12

Commodity Margin per MWh generated
$
40.56

 
$
30.69

 
$
9.87

 
32

 
 
 
 
 
 
 
 
MWh generated (in thousands)
5,449

 
6,418

 
(969
)
 
(15
)
Average availability
86.3
%
 
90.3
%
 
(4.0
)%
 
(4
)
Average total MW in operation
7,425

 
7,425

 

 

Average capacity factor, excluding peakers
36.3
%
 
42.9
%
 
(6.6
)%
 
(15
)
Steam Adjusted Heat Rate
7,336

 
7,329

 
(7
)
 

West — Commodity Margin in our West segment increased by $24 million, or 12%, for the three months ended March 31, 2017 compared to the three months ended March 31, 2016, primarily due to the expansion of our retail hedging activities following the acquisition of Calpine Solutions in December 2016. An increase in Commodity Margin from higher resource adequacy payments and a period-over-period increase in generation at our Geysers Assets, which were recovering from the effects of a wildfire in the first quarter of 2016, was largely offset by lower contribution from wholesale hedges and lower Spark Spreads. Generation decreased 15% primarily due to higher period-over-period hydroelectric generation in the region and an extended outage at our Delta Energy Center during the first quarter of 2017. We expect our Delta Energy Center to be fully restored to service in the fourth quarter of 2017.

34



Texas:
2017
 
2016
 
Change
 
% Change
Commodity Margin (in millions)
$
148

 
$
153

 
$
(5
)
 
(3
)
Commodity Margin per MWh generated
$
15.75

 
$
13.60

 
$
2.15

 
16

 
 
 
 
 
 
 
 
MWh generated (in thousands)
9,398

 
11,249

 
(1,851
)
 
(16
)
Average availability
86.9
%
 
86.6
%
 
0.3
 %
 

Average total MW in operation
8,924

 
9,191

 
(267
)
 
(3
)
Average capacity factor, excluding peakers
48.8
%
 
56.0
%
 
(7.2
)%
 
(13
)
Steam Adjusted Heat Rate
7,121

 
7,049

 
(72
)
 
(1
)
Texas — Commodity Margin in our Texas segment decreased by $5 million, or 3%, for the three months ended March 31, 2017 compared to the three months ended March 31, 2016, primarily due to lower contribution from hedges and, to a lesser extent, lower generation and milder weather. Generation decreased 16% due to weaker market conditions in the northern portion of the state (driven by transmission outages) and weaker ERCOT-wide off-peak Spark Spreads (driven by an increase in coal-fired generation) during the first quarter of 2017 compared to the same period in 2016.
East:
2017
 
2016
 
Change
 
% Change
Commodity Margin (in millions)
$
189

 
$
230

 
$
(41
)
 
(18
)
Commodity Margin per MWh generated
$
31.62

 
$
35.61

 
$
(3.99
)
 
(11
)
 
 
 
 
 
 
 
 
MWh generated (in thousands)
5,977

 
6,458

 
(481
)
 
(7
)
Average availability
88.5
%
 
92.8
%
 
(4.3
)%
 
(5
)
Average total MW in operation
8,925

 
9,622

 
(697
)
 
(7
)
Average capacity factor, excluding peakers
41.5
%
 
40.6
%
 
0.9
 %
 
2

Steam Adjusted Heat Rate
7,718

 
7,597

 
(121
)
 
(2
)
East — Commodity Margin in our East segment decreased by $41 million, or 18% for the three months ended March 31, 2017 compared to the three months ended March 31, 2016, primarily due to lower regulatory capacity revenue, a decrease in realized market Spark Spreads (particularly in New England) resulting from milder weather, lower contribution from wholesale hedges and the sales of the 375 MW Mankato Power Plant in October 2016 and the 599 MW Osprey Energy Center in January 2017. The decrease in Commodity Margin was partially offset by the positive effect of increased retail hedging activity following the acquisitions of Calpine Solutions and North American Power in December 2016 and January 2017, respectively, and the positive effect of a new PPA associated with our Morgan Energy Center, which became effective in February 2016.
Adjusted EBITDA
We define Adjusted EBITDA, a non-GAAP financial measure, as EBITDA adjusted for certain items described below and presented in the accompanying reconciliation. Adjusted EBITDA is not a measure calculated in accordance with U.S. GAAP, and should be viewed as a supplement to, and not a substitute for, our results of operations presented in accordance with U.S. GAAP. Adjusted EBITDA is not intended to represent cash flows from operations or net income (loss) as defined by U.S. GAAP as an indicator of operating performance. Furthermore, Adjusted EBITDA is not necessarily comparable to similarly-titled measures reported by other companies.
We believe Adjusted EBITDA is useful to investors and other users of our financial statements in evaluating our operating performance because it provides them with an additional tool to compare business performance across companies and across periods. We believe that EBITDA is widely used by investors to measure a company’s operating performance without regard to items such as interest expense, taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired.
Additionally, we believe that investors commonly adjust EBITDA information to eliminate the effect of restructuring and other expenses, which vary widely from company to company and impair comparability. As we define it, Adjusted EBITDA represents EBITDA adjusted for the effects of impairment losses, gains or losses on sales, dispositions or retirements of assets, any mark-to-market gains or losses from accounting for derivatives, adjustments to exclude the Adjusted EBITDA related to the noncontrolling interest, stock-based compensation expense, operating lease expense, non-cash gains and losses from foreign currency translations, major maintenance expense, gains or losses on the repurchase, modification or extinguishment of debt, non-cash GAAP-related adjustments to levelize revenues from tolling agreements and any unusual or non-recurring items plus adjustments to reflect the Adjusted EBITDA from our unconsolidated investments. We adjust for these items in our Adjusted

35



EBITDA as our management believes that these items would distort their ability to efficiently view and assess our core operating trends.
In summary, our management uses Adjusted EBITDA as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with our Board of Directors, shareholders, creditors, analysts and investors concerning our financial performance.
The tables below provide a reconciliation of Adjusted EBITDA to our income (loss) from operations on a segment basis and to net income attributable to Calpine on a consolidated basis for the periods indicated (in millions): 
 
Three Months Ended March 31, 2017
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Net loss attributable to Calpine
 
 
 
 
 
 
 
 
$
(56
)
Net income attributable to the noncontrolling interest
 
 
 
 
 
 
 
 
4

Income tax benefit
 
 
 
 
 
 
 
 
(61
)
Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
26

Interest expense
 
 
 
 
 
 
 
 
159

Income (loss) from operations
$
88

 
$
(60
)
 
$
44

 
$

 
$
72

Add:
 
 
 
 
 
 
 
 
 
Adjustments to reconcile income (loss) from operations to Adjusted EBITDA:
 
 
 
 
 
 
 
 
 
Depreciation and amortization expense, excluding deferred financing costs(1)
90

 
62

 
53

 

 
205

Major maintenance expense
9

 
29

 
26

 

 
64

Operating lease expense

 

 
6

 

 
6

Mark-to-market (gain) loss on commodity derivative activity
(60
)
 
20

 
(15
)
 

 
(55
)
(Gain) on sale of assets, net

 

 
(27
)
 

 
(27
)
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest(2)
(4
)
 

 
11

 

 
7

Stock-based compensation expense
4

 
3

 
1

 

 
8

Loss on dispositions of assets

 
1

 

 

 
1

Contract amortization
6

 
17

 
37

 

 
60

Other
(12
)
 
4

 
(7
)
 

 
(15
)
Total Adjusted EBITDA
$
121

 
$
76

 
$
129

 
$

 
$
326


36



 
Three Months Ended March 31, 2016
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Net loss attributable to Calpine
 
 
 
 
 
 
 
 
$
(198
)
Net income attributable to the noncontrolling interest
 
 
 
 
 
 
 
 
4

Income tax expense
 
 
 
 
 
 
 
 
35

Other (income) expense, net
 
 
 
 
 
 
 
 
5

Interest expense
 
 
 
 
 
 
 
 
157

Income (loss) from operations
$
65

 
$
(114
)
 
$
52

 
$

 
$
3

Add:
 
 
 
 
 
 
 
 
 
Adjustments to reconcile income (loss) from operations to Adjusted EBITDA:
 
 
 
 
 
 
 
 
 
Depreciation and amortization expense, excluding deferred financing costs(1)
68

 
53

 
58

 

 
179

Major maintenance expense
17

 
22

 
25

 

 
64

Operating lease expense

 

 
6

 

 
6

Mark-to-market (gain) loss on commodity derivative activity
(23
)
 
97

 
21

 

 
95

Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest(2)
(4
)
 

 
9

 

 
5

Stock-based compensation expense
3

 
4

 
2

 

 
9

Loss on dispositions of assets

 
1

 
1

 

 
2

Contract amortization

 
21

 
6

 

 
27

Other
(13
)
 

 
(3
)
 

 
(16
)
Total Adjusted EBITDA
$
113

 
$
84

 
$
177

 
$

 
$
374

____________
(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 three months ended March 31, 2017 and 2016.

37



LIQUIDITY AND CAPITAL RESOURCES
We maintain a strong focus on liquidity. We manage our liquidity to help provide access to sufficient funding to meet our business needs and financial obligations throughout business cycles.
Our business is capital intensive. Our ability to successfully implement our strategy is dependent on the continued availability of capital on attractive terms. In addition, our ability to successfully operate our business is dependent on maintaining sufficient liquidity. We believe that we have adequate resources from a combination of cash and cash equivalents on hand and cash expected to be generated from future operations to continue to meet our obligations as they become due.
Liquidity
The following table provides a summary of our liquidity position at March 31, 2017 and December 31, 2016 (in millions):
 
March 31, 2017
 
December 31, 2016
Cash and cash equivalents, corporate(1)
$
153

 
$
345

Cash and cash equivalents, non-corporate
90

 
73

Total cash and cash equivalents
243

 
418

Restricted cash
177

 
188

Corporate Revolving Facility availability(2)
1,294

 
1,255

CDHI letter of credit facility availability
63

 
50

Total current liquidity availability(3)
$
1,777

 
$
1,911

____________
(1)
Includes $9 million and $16 million of margin deposits posted with us by our counterparties at March 31, 2017 and December 31, 2016, respectively. See Note 7 of the Notes to Consolidated Condensed Financial Statements for further information related to our collateral.
(2)
Our ability to use availability under our Corporate Revolving Facility is unrestricted.
(3)
Our ability to use corporate cash and cash equivalents is unrestricted. See Note 1 of the Notes to Consolidated Condensed Financial Statements for a description of the restrictions on our use of non-corporate cash and cash equivalents and restricted cash. Our $300 million CDHI letter of credit facility is restricted to support certain obligations under PPAs and power transmission and natural gas transportation agreements.
Our principal source for future liquidity is cash flows generated from our operations. We believe that cash on hand and expected future cash flows from operations will be sufficient to meet our liquidity needs for our operations, both in the near and longer term. See “Cash Flow Activities” below for a further discussion of our change in cash and cash equivalents.
Our principal uses of liquidity and capital resources, outside of those required for our operations, include, but are not limited to, collateral requirements to support our commercial hedging and optimization activities, debt service obligations including principal and interest payments, capital expenditures for construction, project development and other growth initiatives and opportunistically repaying debt to manage our balance sheet. In addition, we may use capital resources to opportunistically repurchase our shares of common stock. The ultimate decision to allocate capital to share repurchases will be based upon the expected returns compared to alternative uses of capital. 
Cash Management — We manage our cash in accordance with our cash management system subject to the requirements of our Corporate Revolving Facility and requirements under certain of our project debt and lease agreements or by regulatory agencies. Our cash and cash equivalents, as well as our restricted cash balances, are invested in money market funds that are not FDIC insured. We place our cash, cash equivalents and restricted cash in what we believe to be creditworthy financial institutions.
We have never paid cash dividends on our common stock. Future cash dividends, if any, may be authorized at the discretion of our Board of Directors and will depend upon, among other things, our future operations and earnings, capital requirements, general financial condition, contractual and financing restrictions and such other factors as our Board of Directors may deem relevant.
Liquidity Sensitivity
Significant changes in commodity prices and Market Heat Rates can affect our liquidity as we use margin deposits, cash prepayments and letters of credit as credit support (collateral) with and from our counterparties for commodity procurement and risk management activities. Utilizing our portfolio of transactions subject to collateral exposure, we estimate that as of March 31,

38



2017, an increase of $1/MMBtu in natural gas prices would result in a decrease of collateral required by approximately $148 million. If natural gas prices decreased by $1/MMBtu, we estimate that our collateral requirements would increase by approximately $218 million. Changes in Market Heat Rates also affect our liquidity. For example, as demand increases, less efficient generation is dispatched, which increases the Market Heat Rate and results in increased collateral requirements. Historical relationships of natural gas and Market Heat Rate movements for our portfolio of assets have been volatile over time and are influenced by the absolute price of natural gas and the regional characteristics of each power market. We estimate that at March 31, 2017, an increase of 500 Btu/KWh in the Market Heat Rate would result in an increase in collateral required by approximately $14 million. If Market Heat Rates were to fall at a similar rate, we estimate that our collateral required would decrease by approximately $6 million. These amounts are not necessarily indicative of the actual amounts that could be required, which may be higher or lower than the amounts estimated above, and also exclude any correlation between the changes in natural gas prices and Market Heat Rates that may occur concurrently. These sensitivities will change as new contracts or hedging activities are executed.
In order to effectively manage our future Commodity Margin, we have economically hedged a portion of our expected generation and natural gas portfolio as well as retail load supply obligations, where appropriate, mostly through power and natural gas forward physical and financial transactions including retail power sales; however, we currently remain susceptible to significant price movements for 2017 and beyond. In addition to the price of natural gas, our Commodity Margin is highly dependent on other factors such as:
the level of Market Heat Rates;
our continued ability to successfully hedge our Commodity Margin;
changes in U.S. macroeconomic conditions;
maintaining acceptable availability levels for our fleet;
the effect of current and pending environmental regulations in the markets in which we participate;
improving the efficiency and profitability of our operations;
increasing future contractual cash flows; and
our significant counterparties performing under their contracts with us.
Additionally, scheduled outages related to the life cycle of our power plant fleet in addition to unscheduled outages may result in maintenance expenditures that are disproportionate in differing periods. In order to manage such liquidity requirements, we maintain additional liquidity availability in the form of our Corporate Revolving Facility (noted in the table above), letters of credit and the ability to issue first priority liens for collateral support. It is difficult to predict future developments and the amount of credit support that we may need to provide should such conditions occur, we experience another economic recession or energy commodity prices increase significantly.
Letter of Credit Facilities 
The table below represents amounts issued under our letter of credit facilities at March 31, 2017 and December 31, 2016 (in millions):
 
March 31, 2017
 
December 31, 2016
Corporate Revolving Facility(1)
$
471

 
$
535

CDHI
237

 
250

Various project financing facilities
183

 
206

Total
$
891

 
$
991

____________
(1)
The Corporate Revolving Facility represents our primary revolving facility.
Disciplined Capital Allocation
In connection with our goal of disciplined capital allocation, we have completed the following key capital management transactions during 2017, as further described below.
Redemption of 2023 First Lien Notes
As part of our stated goal to reduce debt and interest expense, on March 6, 2017, we redeemed the remaining $453 million of our outstanding 2023 First Lien Notes using cash on hand along with the proceeds from the 2019 First Lien Term Loan which

39



contains a substantially lower variable rate of LIBOR plus 1.75% per annum. We intend to repay the 2019 First Lien Term Loan in full by the end of 2018. This accelerates debt reduction and results in substantial annual interest savings of more than $20 million.
2017 First Lien Term Loan
We repaid approximately $150 million in borrowings under our 2017 First Lien Term Loan using cash on hand during the first quarter of 2017.
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. Our significant ongoing projects under construction, growth initiatives and strategic asset sales are discussed below.
York 2 Energy Center — York 2 Energy Center is an 828 MW dual-fuel, combined-cycle project that is co-located with our York Energy Center in Peach Bottom Township, Pennsylvania. Once complete, the power plant will feature two combustion turbines, two heat recovery steam generators and one steam turbine. The project is under construction and the initial 760 MW of capacity cleared PJM’s last three base residual auctions with the 68 MW of incremental capacity clearing the last two base residual auctions. Due to construction delays, we are now targeting COD in early 2018.
Guadalupe Peaking Energy Center — In April 2017, we canceled 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 existing Guadalupe Energy Center. In lieu of building the facility, we will now serve GVEC with 200 MW of generating capacity under a ten-year PPA beginning in June 2019.
Washington Parish Energy Center — On April 21, 2017, we entered into an agreement with Entergy Louisiana (“Entergy”), a subsidiary of Entergy Corporation, to construct an approximately 360 MW natural gas-fired peaking power plant on a partially developed site that we own near Bogalusa, LA. Within a short period of time subsequent to the plant commencing commercial operations and meeting certain performance objectives, Entergy will purchase the plant for a fixed payment, including a fair market return. Construction on the facility will not commence until 2019 with COD expected in early 2021. The agreement contains conditions precedent to effectiveness including, but not limited to, approval of the Louisiana Public Service Commission. We plan to fund the project with a construction loan that will be repaid upon receipt of sale proceeds.
Osprey Energy Center — On January 3, 2017, we completed the sale of our Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million, excluding working capital and other adjustments. This transaction supports our effort to divest non-core assets outside our strategic concentration.
South Point Energy Center As a result of the denial by the Nevada Public Utility Commission of the sale of South Point Energy Center to Nevada Power Company in February 2017, we terminated the corresponding asset sale agreement in the first quarter of 2017. We are currently assessing our options related to South Point Energy Center; however, we do not anticipate that the termination of the asset sale agreement will have a material effect on our financial condition, results of operations or cash flows.
Clear Lake Power Plant — On February 1, 2017, we retired our 400 MW Clear Lake Power Plant due to a lack of adequate compensation in Texas. Built in 1985, Clear Lake utilized an older, less efficient technology. The book value associated with our Clear Lake Power Plant is immaterial.
Expanding our Customer Sales Channels
We continue to focus on getting closer to our customers and providing products and services that are beneficial to them. A summary of certain significant achievements and contracts entered into in 2017 are as follows:
Wholesale
We entered into a new ten-year PPA with Guadalupe Electric Valley Cooperative to provide 200 MW of energy from our Texas power plant fleet commencing in June 2019, in lieu of constructing a 418 MW natural gas-fired peaking power plant.

40



Retail
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 has been integrated into our Champion Energy retail platform.
NOLs
We have significant NOLs that will provide future tax deductions when we generate sufficient taxable income during the applicable carryover periods. At December 31, 2016, our consolidated federal NOLs totaled approximately $6.7 billion.
Cash Flow Activities
The following table summarizes our cash flow activities for the three months ended March 31, 2017 and 2016 (in millions):
 
2017
 
2016
Beginning cash and cash equivalents
$
418

 
$
906

Net cash provided by (used in):
 
 
 
Operating activities
94

 
31

Investing activities
(13
)
 
(611
)
Financing activities
(256
)
 
(82
)
Net decrease in cash and cash equivalents
(175
)
 
(662
)
Ending cash and cash equivalents
$
243

 
$
244

Net Cash Provided By Operating Activities
Cash provided by operating activities for the three months ended March 31, 2017, was $94 million compared to $31 million for the three months ended March 31, 2016. The increase was primarily due to:
Income from operations — Income from operations, adjusted for non-cash items, decreased by $39 million for the three months ended March 31, 2017, compared to the same period in 2016. Non-cash items consist primarily of depreciation and amortization, income from unconsolidated subsidiaries, gain on sale of assets and mark-to-market activity. The decrease in income from operations was primarily driven by a $16 million decrease in Commodity revenue, net of Commodity expense, excluding non-cash amortization, and $27 million increase in plant operating expense. See “Results of Operations for the three months ended March 31, 2017 and 2016” above for further discussion of these changes.
Working capital employed Working capital employed decreased by $92 million for the three months ended March 31, 2017, compared to the same period in 2016, after adjusting for changes in debt, restricted cash and mark-to-market related balances which did not affect cash provided by operating activities. The decrease was primarily due to the change in net margining requirements associated with our commodity hedging activity for the three months ended March 31, 2017, compared to the same period in 2016.
Net Cash Used In Investing Activities
Cash used in investing activities for the three months ended March 31, 2017, was $13 million compared to $611 million for the three months ended March 31, 2016. The decrease was primarily due to:
Acquisitions and Divestitures During the three months ended March 31, 2017, we closed on the acquisition of the retail electric provider North American Power for a net purchase price paid of $111 million and also closed on the sale of Osprey Energy Center receiving net proceeds of $162 million. During the three months ended March 31, 2016, we purchased Granite Ridge Energy Center for a net purchase price of $527 million.
Capital expenditures Capital expenditures for the three months ended March 31, 2017 were $91 million, a decrease of $42 million, compared to expenditures of $133 million for the three months ended March 31, 2016. The decrease was primarily due to lower expenditures on construction projects and outages during the first quarter of 2017 as compared to the first quarter of 2016.

41



Net Cash Used In Financing Activities
Cash used in financing activities for the three months ended March 31, 2017, was $256 million compared to $82 million for the three months ended March 31, 2016. The increase was primarily due to:
First Lien Term Loans and First Lien Notes — During the three months ended March 31, 2017, we received proceeds of $396 million from the issuance of the 2019 First Lien Term Loan which was used, together with cash on hand, to redeem $453 million of the 2023 First Lien Notes. In addition, we used cash on hand to repay $150 million of our outstanding 2017 First Lien Term Loan. There were no similar activities during the first quarter of 2017.
Corporate Revolving Facility — During the three months ended March 31, 2017, we borrowed $25 million under our Corporate Revolving Facility. There was no similar activity during the first quarter of 2016.
Off Balance Sheet Arrangements
There have been no material changes to our off balance sheet arrangements from those disclosed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2016 Form 10-K.

42



RISK MANAGEMENT AND COMMODITY ACCOUNTING
Our commercial hedging and optimization strategies are designed to maximize our risk-adjusted Commodity Margin by leveraging our knowledge, experience and fundamental views on natural gas and power. We actively manage our risk exposures with a variety of physical and financial instruments with varying time horizons. These instruments include PPAs, tolling arrangements, Heat Rate swaps and options, retail power sales including through our retail affiliates, steam sales, buying and selling standard physical power and natural gas products, buying and selling exchange traded instruments, buying and selling environmental and capacity products, natural gas transportation and storage arrangements, electric transmission service and other contracts for the sale and purchase of power products. We utilize these instruments to maximize the risk-adjusted returns for our Commodity Margin. Our retail subsidiaries also provide us with a hedging outlet for our wholesale power plant portfolio.
We conduct our hedging and optimization activities within a structured risk management framework based on controls, policies and procedures. We monitor these activities through active and ongoing management and oversight, defined roles and responsibilities, and daily risk estimates and reporting. Additionally, we seek to manage the associated risks through diversification, by controlling position sizes, by using portfolio position limits, and by actively managing hedge positions to lock in margin. We are exposed to commodity price movements (both profits and losses) in connection with these transactions. These positions are included in and subject to our consolidated risk management portfolio position limits and controls structure. Changes in fair value of commodity positions that do not qualify for or for which we do not elect either hedge accounting or the normal purchase normal sale exemption are recognized currently in earnings and are separately stated on our Consolidated Condensed Statements of Operations in mark-to-market gain/loss as a component of operating revenues (for physical and financial power and Heat Rate and commodity option activity) and fuel and purchased energy expense (for physical and financial natural gas, power, environmental product and fuel oil activity). Our future hedged status and marketing and optimization activities are subject to change as determined by our commercial operations group, Chief Risk Officer, senior management and Board of Directors.
At any point in time, the relative quantity of our products hedged or sold under longer-term contracts is determined by the availability of forward product sales opportunities and our view of the attractiveness of the pricing available for forward sales. We have economically hedged a portion of our expected generation and natural gas portfolio as well as retail load supply obligations, where appropriate, mostly through power and natural gas forward physical and financial transactions including retail power sales; however, we currently remain susceptible to significant price movements for 2017 and beyond. When we elect to enter into these transactions, we are able to economically hedge a portion of our Spark Spread at pre-determined generation and price levels.
We have historically used interest rate hedging instruments to adjust the mix between our fixed and variable rate debt. To the extent eligible, our interest rate hedging instruments have been designated as cash flow hedges, and changes in fair value are recorded in OCI to the extent they are effective with gains and losses reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. See Note 6 of the Notes to Consolidated Condensed Financial Statements for further discussion of our derivative instruments.
The primary factors affecting our market risk and the fair value of our derivatives at any point in time are the volume of open derivative positions (MMBtu, MWh and $ notional amounts); changing commodity market prices, primarily for power and natural gas; our credit standing and that of our counterparties for energy commodity derivatives; and prevailing interest rates for our interest rate hedging instruments. Since prices for power and natural gas and interest rates are volatile, there may be material changes in the fair value of our derivatives over time, driven both by price volatility and the changes in volume of open derivative transactions. Our derivative assets have decreased to approximately $2.1 billion at March 31, 2017, when compared to approximately $2.3 billion at December 31, 2016, and our derivative liabilities have decreased to approximately $1.8 billion at March 31, 2017, when compared to approximately $2.1 billion at December 31, 2016. The fair value of our level 3 derivative assets and liabilities at March 31, 2017 represents approximately 18% and 3% of our total assets and liabilities measured at fair value, respectively, with the majority of that value attributable to the fair value of retail sales contracts acquired in the acquisition of Calpine Solutions in December 2016. See Note 5 of the Notes to Consolidated Condensed Financial Statements for further information related to our level 3 derivative assets and liabilities.

43



The change in fair value of our outstanding commodity and interest rate hedging instruments from January 1, 2017, through March 31, 2017, is summarized in the table below (in millions):
 
Commodity Instruments
 
Interest Rate Hedging Instruments
 
Total
Fair value of contracts outstanding at January 1, 2017
$
191

 
$
(29
)
 
$
162

Items recognized or otherwise settled during the period(1)(2)
(72
)
 
8

 
(64
)
Fair value attributable to new contracts(3)
56

 
9

 
65

Changes in fair value attributable to price movements
77

 
(6
)
 
71

Fair value of contracts outstanding at March 31, 2017(4)
$
252

 
$
(18
)
 
$
234

__________
(1)
Commodity contract settlements consist of the realization of previously recognized gains on contracts not designated as hedging instruments of $54 million (represents a portion of Commodity revenue and Commodity expense as reported on our Consolidated Condensed Statements of Operations) and $18 million related to current period losses from other changes in derivative assets and liabilities not reflected in OCI or earnings.
(2)
Interest rate settlements consist of $7 million related to realized losses from settlements of designated cash flow hedges and $1 million related to realized losses from settlements of undesignated interest rate hedging instruments (represents a portion of interest expense as reported on our Consolidated Condensed Statements of Operations).
(3)
Fair value attributable to new contracts includes $24 million and $18 million of fair value related to commodity contracts and interest rate hedging instruments, respectively, which are not reflected in OCI or earnings.
(4)
Net commodity and interest rate derivative assets and liabilities reported in Notes 5 and 6 of the Notes to Consolidated Condensed Financial Statements.
Commodity Price Risk — Commodity price risks result from exposure to changes in spot prices, forward prices, price volatilities and correlations between the price of power, steam and natural gas. We manage the commodity price risk and the variability in future cash flows from forecasted sales of power and purchases of natural gas of our entire portfolio of generating assets and contractual positions by entering into various derivative and non-derivative instruments.
The net fair value of outstanding derivative commodity instruments at March 31, 2017, based on price source and the period during which the instruments will mature, are summarized in the table below (in millions):
Fair Value Source
 
2017
 
2018-2019
 
2020-2021
 
After 2021
 
Total
Prices actively quoted
 
$
(17
)
 
$
(13
)
 
$
(7
)
 
$
(2
)
 
$
(39
)
Prices provided by other external sources
 
18

 
(41
)
 
(4
)
 

 
(27
)
Prices based on models and other valuation methods
 
120

 
150

 
40

 
8

 
318

Total fair value
 
$
121

 
$
96

 
$
29

 
$
6

 
$
252

We measure the energy commodity price risk in our portfolio on a daily basis using a VAR model to estimate the potential one-day risk of loss based upon historical experience resulting from potential market movements. Our VAR is calculated for our entire portfolio comprising energy commodity derivatives, expected generation and natural gas consumption from our power plants, PPAs, and other physical and financial transactions. We measure VAR using a variance/covariance approach based on a confidence level of 95%, a one-day holding period and actual observed historical correlation. While we believe that our VAR assumptions and approximations are reasonable, different assumptions and/or approximations could produce materially different estimates.

44



The table below presents the high, low and average of our daily VAR for the three months ended March 31, 2017 and 2016 (in millions):
 
2017
 
2016
Three months ended March 31:
 
 
 
High
$
22

 
$
31

Low
$
16

 
$
15

Average
$
19

 
$
22

As of March 31
$
17

 
$
17

Due to the inherent limitations of statistical measures such as VAR, the VAR calculation may not capture the full extent of our commodity price exposure. As a result, actual changes in the value of our energy commodity portfolio could be different from the calculated VAR, and could have a material effect on our financial results. In order to evaluate the risks of our portfolio on a comprehensive basis and augment our VAR analysis, we also measure the risk of the energy commodity portfolio using several analytical methods including sensitivity analysis, non-statistical scenario analysis, including stress testing, and daily position report analysis.
We utilize the forward commodity markets to hedge price risk associated with our power plant portfolio. Our ability to hedge relies in part on market liquidity and the number of counterparties with which to transact. While the number of counterparties in these markets has decreased, to date this occurrence has not had a material adverse effect on our results of operations or financial condition. However, should these conditions persist or increase, it could decrease our ability to hedge our forward commodity price risk and create incremental volatility in our earnings. The effects of declining liquidity in the forward commodity markets is also mitigated by our retail subsidiaries which provides us with an additional outlet to transact hedging activities related to our wholesale power plant portfolio.
Liquidity Risk — Liquidity risk arises from the general funding requirements needed to manage our activities and assets and liabilities. Fluctuating natural gas prices or Market Heat Rates can cause our collateral requirements for our wholesale and retail activities to increase or decrease. Our liquidity management framework is intended to maximize liquidity access and minimize funding costs during times of rising prices. See further discussion regarding our uses of collateral as they relate to our commodity procurement and risk management activities in Note 7 of the Notes to Consolidated Condensed Financial Statements.
Credit Risk — Credit risk relates to the risk of loss resulting from nonperformance or non-payment by our counterparties or customers related to their contractual obligations with us. Risks surrounding counterparty and customer performance and credit could ultimately affect the amount and timing of expected cash flows. We also have credit risk if counterparties or customers are unable to provide collateral or post margin. We monitor and manage our credit risk through credit policies that include:
credit approvals;
routine monitoring of counterparties’ and customer’s credit limits and their overall credit ratings;
limiting our marketing, hedging and optimization activities with high risk counterparties;
margin, collateral, or prepayment arrangements; and
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.

45



We have concentrations of credit risk with a few of our wholesale counterparties and retail customers relating to our sales of power and steam and our hedging, optimization and trading activities. We believe that our credit policies and portfolio of transactions adequately monitor and diversify our credit risk, and currently our counterparties and customers are performing and financially settling timely according to their respective agreements. We monitor and manage our total comprehensive credit risk associated with all of our contracts irrespective of whether they are accounted for as an executory contract, a normal purchase normal sale or whether they are marked-to-market and included in our derivative assets and liabilities on our Consolidated Condensed Balance Sheets. Our counterparty and customer credit quality associated with the net fair value of outstanding derivative commodity instruments is included in our derivative assets and (liabilities) at March 31, 2017, and the period during which the instruments will mature are summarized in the table below (in millions):
Credit Quality
(Based on Standard & Poor’s Ratings
as of March 31, 2017)
 
2017
 
2018-2019
 
2020-2021
 
After 2021
 
Total
Investment grade
 
$
96

 
$
59

 
$
24

 
$
3

 
$
182

Non-investment grade
 
22

 
34

 
5

 
3

 
64

No external ratings
 
3

 
3

 

 

 
6

Total fair value
 
$
121

 
$
96

 
$
29

 
$
6

 
$
252

Interest Rate Risk — Our variable rate financings are indexed to base rates, generally LIBOR. Interest rate risk represents the potential loss in earnings arising from adverse changes in market interest rates. The fair value of our interest rate hedging instruments are validated based upon external quotes. Our interest rate hedging instruments are with counterparties we believe are primarily high quality institutions, and we do not believe that our interest rate hedging instruments expose us to any significant credit risk. Holding all other factors constant, we estimate that a 10% decrease in interest rates would result in a change in the fair value of our interest rate hedging instruments hedging our variable rate debt of approximately $(25) million at March 31, 2017.
New Accounting Standards and Disclosure Requirements
See Note 1 of the Notes to Consolidated Condensed Financial Statements for a discussion of new accounting standards and disclosure requirements.
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
The information required to be disclosed under this Item 3 is set forth under Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Risk Management and Commodity Accounting.” This information should be read in conjunction with the information disclosed in our 2016 Form 10-K.
Item 4.
Controls and Procedures
Disclosure Controls and Procedures
As of the end of the period covered by this Report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rule 13a-15(e) and Rule 15d-15(e) of the Exchange Act. Based upon, and as of the date of, this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective such that the information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
Changes in Internal Control Over Financial Reporting
During the first quarter of 2017, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


46



PART II — OTHER INFORMATION
Item 1.
Legal Proceedings

See Note 11 of the Notes to Consolidated Condensed Financial Statements for a description of our legal proceedings.
Item 1A.
Risk Factors
There were no material changes to the description of the risk factors associated with our business previously disclosed in Part I, Item 1A “Risk Factors” of our 2016 Form 10-K.
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
Repurchase of Equity Securities
Period
 
(a)
Total Number of
Shares Purchased(1)
 
(b)
Average Price
Paid Per Share
 
(c)
Total Number  of
Shares Purchased
as Part of
Publicly Announced
Plans or Programs(2)
 
(d)
Maximum Dollar Value of Shares That May
Yet Be Purchased
Under the Plans or
Programs (in millions)(2)
January
 
2,803

 
$
11.77

 

 
$
307

February
 
466,698

 
$
11.77

 

 
$
307

March
 
1,029

 
$
11.07

 

 
$
307

Total
 
470,530

 
$
11.76

 

 
$
307

___________
(1)
To satisfy tax withholding obligations associated with the vesting of restricted stock awarded to employees during the first quarter of 2017, we withheld a total of 470,530 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.
Item 3.
Defaults Upon Senior Securities
None.
Item 4.
Mine Safety Disclosures

Not applicable.
Item 5.
Other Information

None.

47



Item 6.
Exhibits
EXHIBIT INDEX
Exhibit
Number
 
Description
 
 
 
10.1
 
Credit Agreement, dated February 3, 2017 among Calpine Corporation as borrower and the lenders party thereto, and Morgan Stanley Senior Funding, Inc., as administrative agent, MUFG Union Bank, N.A., as collateral agent (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on February 9, 2017).
 
 
 
10.2
 
 
 
 
10.3
 
 
 
 
10.4
 
 
 
 
10.5
 
 
 
 
10.6
 
 
 
 
31.1
 
 
 
 
31.2
 
 
 
 
32.1
 
 
 
 
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.
_______________
*
Furnished herewith.
Management contract or compensatory plan, contract or arrangement.


48



SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.

CALPINE CORPORATION
(Registrant)
 
 
By:
 
/s/  ZAMIR RAUF
 
 
Zamir Rauf
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
Date: April 27, 2017


49