CALPINE CORP - FORM 10-Q

Attached files

file	filename
EX-32.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER - CALPINE CORP	cpn_exhibit321x06302017.htm
EX-31.2 - SECTION 302 CERTIFICATION OF CHIEF FINANCIAL OFFICER - CALPINE CORP	cpn_exhibit312x06302017.htm
EX-31.1 - SECTION 302 CERTIFICATION OF CHIEF EXECUTIVE OFFICER - CALPINE CORP	cpn_exhibit311x06302017.htm
EX-10.8 - STOCK OPTION AGREEMENT THAD HILL - CALPINE CORP	calpine2017optionagreement.htm
EX-10.7 - PERFORMANCE SHARE UNIT GRANT THAD HILL - CALPINE CORP	calpine2017psuhill.htm
EX-10.6 - RESTRICTED STOCK AGREEMENT THAD HILL - CALPINE CORP	calpine2017rsathadhill.htm
EX-10.2 - FORM OF RESTRICTED STOCK UNIT AGREEMENT SENIOR EMPLOYEES - CALPINE CORP	calpine2017rsuawardseniorm.htm
EX-10.1 - FORM OF RESTRICTED STOCK UNIT AGREEMENT THAD MILLER - CALPINE CORP	calpine2017rsuawardmiller.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 June 30, 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

______________________

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: 360,670,156 shares of common stock, par value $0.001, were outstanding as of July 24, 2017.

CALPINE CORPORATION AND SUBSIDIARIES

REPORT ON FORM 10-Q

For the Quarter Ended June 30, 2017

INDEX




	Page

Definitions	ii

Forward-Looking Statements	vii

Where You Can Find Other Information	viii

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements	1
Consolidated Condensed Statements of Operations for the Three and Six Months Ended June 30, 2017 and 2016	1
Consolidated Condensed Statements of Comprehensive Loss for the Three and Six Months Ended June 30, 2017 and 2016	2
Consolidated Condensed Balance Sheets at June 30, 2017 and December 31, 2016	3
Consolidated Condensed Statements of Cash Flows for the Six Months Ended June 30, 2017 and 2016	4
Notes to Consolidated Condensed Financial Statements	6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Forward-Looking Information	29
Introduction and Overview	29
Results of Operations	35
Commodity Margin and Adjusted Free Cash Flow	40
Liquidity and Capital Resources	44
Risk Management and Commodity Accounting	49
New Accounting Standards and Disclosure Requirements	52
Item 3. Quantitative and Qualitative Disclosures About Market Risk	52
Item 4. Controls and Procedures	52

PART II – OTHER INFORMATION

Item 1. Legal Proceedings	53
Item 1A. Risk Factors	53
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	53
Item 3. Defaults Upon Senior Securities	53
Item 4. Mine Safety Disclosures	53
Item 5. Other Information	53
Item 6. Exhibits	54
Signatures	55

DEFINITIONS

As used in this report for the quarter ended June 30, 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
2008 Director Plan		The Amended and Restated Calpine Corporation 2008 Director Incentive Plan

2008 Equity Plan		The Amended and Restated Calpine Corporation 2008 Equity Incentive Plan

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 Director Plan		The Calpine Corporation 2017 Equity Compensation Plan for Non-Employee Directors

2017 Equity Plan		The Calpine Corporation 2017 Equity Incentive Plan

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 Loans		The $550 million first lien senior secured term loan, dated December 15, 2015, among Calpine Corporation, as borrower, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent and the $562 million first lien senior secured term loan, dated May 31, 2016, among Calpine Corporation, as borrower, the lenders party thereto, Citibank, N.A., as administrative agent and MUFG Union Bank, N.A., as collateral agent

2023 Senior Unsecured Notes		The $1.25 billion aggregate principal amount of 5.375% senior unsecured notes due 2023, issued July 22, 2014

2024 First Lien Notes		The $490 million aggregate principal amount of 5.875% senior secured notes due 2024, issued October 31, 2013

2024 First Lien Term Loan		The $1.6 billion first lien senior secured term loan, dated May 28, 2015 (as amended December 21, 2016), among Calpine Corporation, as borrower, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent

2024 Senior Unsecured Notes		The $650 million aggregate principal amount of 5.5% senior unsecured notes due 2024, issued February 3, 2015

2025 Senior Unsecured Notes		The $1.55 billion aggregate principal amount of 5.75% senior unsecured notes due 2025, issued July 22, 2014



ABBREVIATION		DEFINITION
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

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

Adjusted Free Cash Flow		Cash flows from operating activities adjusted for the effects of changes in working capital, maintenance capital expenditures, adjustments to reflect the Adjusted Free Cash Flow from unconsolidated investments and to exclude the noncontrolling interest and other miscellaneous 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 Plans and the Equity Plans, which provide for grants of equity awards to Calpine non-union employees and non-employee members of Calpine’s Board of Directors

Calpine Receivables		Calpine Receivables, LLC, 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

CARB		California Air Resources Board

iii



ABBREVIATION		DEFINITION
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

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, commodity transmission and transportation expense, environmental compliance expenses and realized settlements from our marketing, hedging and optimization activities including natural gas and fuel oil transactions hedging future power sales

Commodity Margin		Non-GAAP financial measure that includes revenue recognized on our wholesale and retail power sales activity, electric capacity sales, REC sales, steam sales, realized settlements associated with our marketing, hedging, optimization and trading activity, fuel and purchased energy expenses, commodity transmission and transportation expenses and environmental compliance expenses

Commodity revenue		The sum of our revenues recognized on our wholesale and retail power sales activity, electric capacity sales, REC sales, steam sales and realized settlements from our marketing, hedging, optimization and trading activities

Company		Calpine Corporation, a Delaware corporation, and its subsidiaries

Corporate Revolving Facility		The $1.8 billion aggregate amount revolving credit facility credit agreement, dated as of December 10, 2010, as amended on June 27, 2013, July 30, 2014, February 8, 2016 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 Plans		Collectively, the 2008 Director Plan and the 2017 Director Plan

EBITDA		Net income (loss) attributable to Calpine before net (income) loss attributable to the noncontrolling interest, interest, taxes, depreciation and amortization

Equity Plans		Collectively, the 2008 Equity Plan and the 2017 Equity 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



ABBREVIATION		DEFINITION
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

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

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



ABBREVIATION		DEFINITION
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

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

Forward-Looking Statements

This Report contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act, and Section 21E of the Exchange Act. Forward-looking statements may appear throughout this Report, including without limitation, the “Management’s Discussion and Analysis” section. We use words such as “believe,” “intend,” “expect,” “anticipate,” “plan,” “may,” “will,” “should,” “estimate,” “potential,” “project” and similar expressions to identify forward-looking statements. Such statements include, among others, those concerning our expected financial performance and strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. We believe that the forward-looking statements are based upon reasonable assumptions and expectations. However, you are cautioned that any such forward-looking statements are not guarantees of future performance and that a number of risks and uncertainties could cause actual results to differ materially from those anticipated in the forward-looking statements. Such risks and uncertainties include, but are not limited to:


•	Financial results that may be volatile and may not reflect historical trends due to, among other things, seasonality of demand, fluctuations in prices for commodities such as natural gas and power, changes in U.S. macroeconomic conditions, fluctuations in liquidity and volatility in the energy commodities markets and our ability and extent to which we hedge risks;


•	Laws, regulations and market rules in the wholesale and retail markets in which we participate and our ability to effectively respond to changes in laws, regulations or market rules or the interpretation thereof including those related to the environment, derivative transactions and market design in the regions in which we operate;


•	Our ability to manage our liquidity needs, access the capital markets when necessary and comply with covenants under our Senior Unsecured Notes, First Lien 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 offices;


•	Disruptions in or limitations on the transportation of natural gas or fuel oil and the transmission of power;


•	Our ability to manage our counterparty and customer exposure and credit risk, including our commodity positions;


•	Our ability to attract, motivate and retain key employees;


•	Present and possible future claims, litigation and enforcement actions that may arise from noncompliance with market rules promulgated by the SEC, CFTC, FERC and other regulatory bodies; and


•	Other risks identified in this Report, 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 June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(in millions, except share and per share amounts)
Operating revenues:
Commodity revenue	$	2,145		$	1,551		$	4,208		$	3,136
Mark-to-market gain (loss)	(66		)	(391		)	148			(366		)
Other revenue	5			4			9			9
Operating revenues	2,084			1,164			4,365			2,779
Operating expenses:
Fuel and purchased energy expense:
Commodity expense	1,513			897			3,046			1,903
Mark-to-market (gain) loss	16			(355		)	175			(235		)
Fuel and purchased energy expense	1,529			542			3,221			1,668
Plant operating expense	302			271			584			526
Depreciation and amortization expense	186			162			392			342
Sales, general and other administrative expense	40			35			80			73
Other operating expenses	20			17			40			37
Total operating expenses	2,077			1,027			4,317			2,646
(Gain) on sale of assets, net	—			—			(27		)	—
(Income) from unconsolidated subsidiaries	(6		)	(3		)	(10		)	(10		)
Income from operations	13			140			85			143
Interest expense	154			157			313			314
Debt extinguishment costs	1			15			25			15
Other (income) expense, net	7			6			9			11
Loss before income taxes	(149		)	(38		)	(262		)	(197		)
Income tax expense (benefit)	63			(14		)	2			21
Net loss	(212		)	(24		)	(264		)	(218		)
Net income attributable to the noncontrolling interest	(4		)	(5		)	(8		)	(9		)
Net loss attributable to Calpine	$	(216	)	$	(29	)	$	(272	)	$	(227	)

Basic and diluted loss per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands)	355,358			354,066			355,022			353,784
Net loss per common share attributable to Calpine — basic and diluted	$	(0.61	)	$	(0.08	)	$	(0.77	)	$	(0.64	)

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

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE LOSS

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(in millions)
Net loss	$	(212	)	$	(24	)	$	(264	)	$	(218	)
Cash flow hedging activities:
Loss on cash flow hedges before reclassification adjustment for cash flow hedges realized in net loss	(26		)	(17		)	(41		)	(40		)
Reclassification adjustment for loss on cash flow hedges realized in net loss	15			11			26			22
Foreign currency translation gain	4			—			6			12
Income tax expense	(2		)	—			(2		)	—
Other comprehensive loss	(9		)	(6		)	(11		)	(6		)
Comprehensive loss	(221		)	(30		)	(275		)	(224		)
Comprehensive (income) attributable to the noncontrolling interest	(4		)	(5		)	(8		)	(7		)
Comprehensive loss attributable to Calpine	$	(225	)	$	(35	)	$	(283	)	$	(231	)

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

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited)



	June 30,			December 31,
	2017			2016
	(in millions, except share and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents ($49 and $79 attributable to VIEs)	$	294		$	418
Accounts receivable, net of allowance of $8 and $6	874			839
Inventories	455			581
Margin deposits and other prepaid expense	323			441
Restricted cash, current ($62 and $109 attributable to VIEs)	105			173
Derivative assets, current	1,062			1,725
Current assets held for sale (nil and $134 attributable to VIEs)	—			210
Other current assets	74			45
Total current assets	3,187			4,432
Property, plant and equipment, net ($4,139 and $3,979 attributable to VIEs)	12,940			13,013
Restricted cash, net of current portion ($27 and $14 attributable to VIEs)	28			15
Investments in unconsolidated subsidiaries	98			99
Long-term derivative assets	527			543
Goodwill	242			187
Intangible assets, net	578			650
Other assets ($66 and $56 attributable to VIEs)	375			378
Total assets	$	17,975		$	19,317
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	761		$	671
Accrued interest payable	105			125
Debt, current portion ($180 and $176 attributable to VIEs)	615			748
Derivative liabilities, current	1,022			1,630
Other current liabilities	370			528
Total current liabilities	2,873			3,702
Debt, net of current portion ($2,891 and $2,944 attributable to VIEs)	11,307			11,431
Long-term derivative liabilities	428			476
Other long-term liabilities	298			369
Total liabilities	14,906			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, 361,744,735 and 359,627,113 shares issued, respectively, and 360,670,818 and 359,061,764 shares outstanding, respectively	—			—
Treasury stock, at cost, 1,073,917 and 565,349 shares, respectively	(13		)	(7		)
Additional paid-in capital	9,642			9,625
Accumulated deficit	(6,485		)	(6,213		)
Accumulated other comprehensive loss	(148		)	(137		)
Total Calpine stockholders’ equity	2,996			3,268
Noncontrolling interest	73			71
Total stockholders’ equity	3,069			3,339
Total liabilities and stockholders’ equity	$	17,975		$	19,317

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

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended June 30,
	2017			2016
	(in millions)
Cash flows from operating activities:
Net loss	$	(264	)	$	(218	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization⁽¹⁾	510			459
Debt extinguishment costs	7			15
Income taxes	10			11
Gain on sale of assets, net	(27		)	—
Mark-to-market activity, net	26			130
(Income) from unconsolidated subsidiaries	(10		)	(10		)
Return on investments from unconsolidated subsidiaries	16			18
Stock-based compensation expense	20			17
Other	(6		)	(1		)
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable	(39		)	(78		)
Derivative instruments, net	(19		)	(69		)
Other assets	17			(116		)
Accounts payable and accrued expenses	(22		)	(85		)
Other liabilities	27			52
Net cash provided by operating activities	246			125
Cash flows from investing activities:
Purchases of property, plant and equipment	(187		)	(223		)
Proceeds from sale of Osprey Energy Center	162			—
Purchase of Granite Ridge Energy Center	—			(526		)
Purchase of North American Power, net of cash acquired	(111		)	—
Decrease in restricted cash	56			60
Other	29			13
Net cash used in investing activities	(51		)	(676		)
Cash flows from financing activities:
Borrowings under First Lien Term Loans	396			556
Repayment of CCFC Term Loans and First Lien Term Loans	(173		)	(1,209		)
Repurchase of First Lien Notes	(453		)	—
Borrowings under First Lien Notes	—			625
Repayments of project financing, notes payable and other	(68		)	(81		)
Distribution to noncontrolling interest holder	(7		)	—
Financing costs	(9		)	(26		)
Shares repurchased for tax withholding on stock-based awards	(6		)	(5		)
Other	1			—
Net cash used in financing activities	(319		)	(140		)
Net decrease in cash and cash equivalents	(124		)	(691		)
Cash and cash equivalents, beginning of period	418			906
Cash and cash equivalents, end of period	$	294		$	215

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

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS — (CONTINUED)

(Unaudited)



	Six Months Ended June 30,
	2017			2016
	(in millions)
Cash paid during the period for:
Interest, net of amounts capitalized	$	296		$	289
Income taxes	$	8		$	8

Supplemental disclosure of non-cash investing and financing activities:
Change in capital expenditures included in accounts payable	$	(4	)	$	24
Purchase of King City Cogeneration Plant lease⁽²⁾	$	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.


(2)	On April 3, 2017, we completed the purchase of the King City Cogeneration Plant lease in exchange for a three-year promissory note with a discounted value of $57 million. We recorded a net increase to property, plant and equipment, net on our Consolidated Condensed Balance Sheet of $15 million due to the increased value of the promissory note as compared to the carrying value of the lease.

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

CALPINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

June 30, 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.

The table below represents the components of our restricted cash as of June 30, 2017 and December 31, 2016 (in millions):



	June 30, 2017						December 31, 2016
	Current		Non-Current		Total		Current		Non-Current		Total
Debt service	$	18	$	8	$	26	$	11	$	8	$	19
Construction/major maintenance	21		19		40		45		6		51
Security/project/insurance	63		—		63		114		—		114
Other	3		1		4		3		1		4
Total	$	105	$	28	$	133	$	173	$	15	$	188

Property, Plant and Equipment, Net — At June 30, 2017 and December 31, 2016, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):



	June 30, 2017		December 31, 2016		Depreciable Lives
Buildings, machinery and equipment	$	16,511	$	16,468	3	–	46	Years
Geothermal properties	1,468		1,377		13	–	58	Years
Other	232		259		3	–	46	Years
	18,211		18,104
Less: Accumulated depreciation	6,123		5,865
	12,088		12,239
Land	117		116
Construction in progress	735		658
Property, plant and equipment, net	$	12,940	$	13,013

Capitalized Interest — The total amount of interest capitalized was $6 million and $5 million for the three months ended June 30, 2017 and 2016, respectively and $13 million and $9 million during the six months ended June 30, 2017 and 2016, respectively.

Goodwill — We have not recorded any impairment losses associated with our goodwill. The change in goodwill by segment during the six months ended June 30, 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
Purchase price allocation adjustments⁽¹⁾	(4		)	(1		)	11		6
Goodwill at June 30, 2017	$	64		$	30		$	148	$	242

____________


(1)	The purchase price allocation adjustment in the East segment represents adjustments of $16 million for North American Power and $(5) million for Calpine Solutions.

Related Party — Under the Accounts Receivables Sales Program, at June 30, 2017 and December 31, 2016, we had $198 million and $211 million, respectively, in trade accounts receivable outstanding that were sold to Calpine Receivables and $35 million and $32 million, respectively, in notes receivable from Calpine Receivables which were recorded on our Consolidated Condensed Balance Sheets. During the six months ended June 30, 2017, we sold an aggregate of $1.1 billion in trade accounts receivable and recorded $1.1 billion 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 (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.


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. We did not record any material adjustments to the preliminary purchase price allocation during the three months ended June 30, 2017. The pro forma incremental effect of North American Power on our results of operations for each of the three and six months ended June 30, 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 six months ended June 30, 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 six months ended June 30, 2017 associated with the sale of the Osprey Energy Center.

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.


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 six months ended June 30, 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 8,423 MW and 9,491 MW at June 30, 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 and six months ended June 30, 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 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. 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 because 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 Condensed 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 June 30, 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 June 30, 2017	June 30, 2017		December 31, 2016
Greenfield LP	50%	$	85	$	73
Whitby	50%	3		16
Calpine Receivables	100%	10		10
Total investments in unconsolidated subsidiaries		$	98	$	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 June 30, 2017 and December 31, 2016, Greenfield LP’s debt was approximately $258 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 $129 million and $130 million at June 30, 2017 and December 31, 2016, respectively.

Our equity interest in the net income from our investments in unconsolidated subsidiaries for the three and six months ended June 30, 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 and six months ended June 30, 2017. The following table sets forth details of our (income) from unconsolidated subsidiaries for the periods indicated (in millions):



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Greenfield LP	$	(4	)	$	(1	)	$	(6	)	$	(5	)
Whitby	(2		)	(2		)	(4		)	(5		)
Total	$	(6	)	$	(3	)	$	(10	)	$	(10	)

Distributions from Greenfield LP were nil during each of the three and six months ended June 30, 2017, and $5 million during each of the three and six months ended June 30, 2016. Distributions from Whitby were $3 million and $16 million during the three and six months ended June 30, 2017, respectively, and $13 million during each of the three and six months ended June 30, 2016.


4.	Debt

Our debt at June 30, 2017 and December 31, 2016, was as follows (in millions):



	June 30, 2017		December 31, 2016
Senior Unsecured Notes	$	3,414	$	3,412
First Lien Term Loans	3,403		3,165
First Lien Notes	1,842		2,290
Project financing, notes payable and other	1,595		1,597
CCFC Term Loans	1,547		1,553
Capital lease obligations	121		162
Subtotal	11,922		12,179
Less: Current maturities	615		748
Total long-term debt	$	11,307	$	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 six months ended June 30, 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):



	June 30, 2017		December 31, 2016
2023 Senior Unsecured Notes	$	1,238	$	1,237
2024 Senior Unsecured Notes	643		643
2025 Senior Unsecured Notes	1,533		1,532
Total Senior Unsecured Notes	$	3,414	$	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):



	June 30, 2017		December 31, 2016
2017 First Lien Term Loan⁽¹⁾	$	396	$	537
2019 First Lien Term Loan	389		—
2023 First Lien Term Loans	1,068		1,071
2024 First Lien Term Loan	1,550		1,557
Total First Lien Term Loans	$	3,403	$	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 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):



	June 30, 2017		December 31, 2016
2022 First Lien Notes	$	740	$	739
2023 First Lien Notes⁽¹⁾	—		450
2024 First Lien Notes	485		485
2026 First Lien Notes	617		616
Total First Lien Notes	$	1,842	$	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 June 30, 2017 and December 31, 2016 (in millions):



	June 30, 2017		December 31, 2016
Corporate Revolving Facility⁽¹⁾	$	474	$	535
CDHI	257		250
Various project financing facilities	215		206
Total	$	946	$	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 and debt issuance costs. The following table details the fair values and carrying values of our debt instruments at June 30, 2017 and December 31, 2016 (in millions):



	June 30, 2017				December 31, 2016
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Unsecured Notes	$	3,303	$	3,414	$	3,343	$	3,412
First Lien Term Loans	3,454		3,403		3,244		3,165
First Lien Notes	1,893		1,842		2,349		2,290
Project financing, notes payable and other⁽¹⁾	1,537		1,503		1,543		1,506
CCFC Term Loans	1,554		1,547		1,567		1,553
Total	$	11,741	$	11,709	$	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 (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.

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 June 30, 2017 and December 31, 2016, by level within the fair value hierarchy:



	Assets and Liabilities with Recurring Fair Value Measures as of June 30, 2017
	Level 1		Level 2		Level 3		Total
	(in millions)
Assets:
Cash equivalents⁽¹⁾	$	128	$	—	$	—	$	128
Commodity instruments:
Commodity exchange traded futures and swaps contracts	932		—		—		932
Commodity forward contracts⁽²⁾	—		285		351		636
Interest rate hedging instruments	—		21		—		21
Total assets	$	1,060	$	306	$	351	$	1,717
Liabilities:
Commodity instruments:
Commodity exchange traded futures and swaps contracts	975		—		—		975
Commodity forward contracts⁽²⁾	—		361		57		418
Interest rate hedging instruments	—		57		—		57
Total liabilities	$	975	$	418	$	57	$	1,450



	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 June 30, 2017 and December 31, 2016, we had cash equivalents of $29 million and $26 million included in cash and cash equivalents and $99 million and $127 million included in restricted cash, respectively.


(2)	Includes OTC swaps and options and retail contracts.

At June 30, 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 June 30, 2017 and December 31, 2016:



	Quantitative Information about Level 3 Fair Value Measurements
	June 30, 2017
	Fair Value, Net Asset			Significant Unobservable
	(Liability)		Valuation Technique	Input	Range
	(in millions)
Power Contracts	$	245	Discounted cash flow	Market price (per MWh)	$	7.40		—	$93.77	/MWh
Power Congestion Products	$	12	Discounted cash flow	Market price (per MWh)	$	(7.92	)	—	$5.13	/MWh
Natural Gas Contracts	$	37	Discounted cash flow	Market price (per MMBtu)	$	1.62		—	$6.15	/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 June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Balance, beginning of period	$	342		$	(65	)	$	399		$	(46	)
Realized and mark-to-market gains (losses):
Included in net loss:
Included in operating revenues⁽¹⁾	28			(174		)	104			(181		)
Included in fuel and purchased energy expense⁽²⁾	(14		)	165			1			155
Purchases and settlements:
Purchases	3			4			3			5
Settlements	(67		)	(1		)	(97		)	(4		)
Transfers in and/or out of level 3⁽³⁾:
Transfers into level 3⁽⁴⁾	2			—			(3		)	—
Transfers out of level 3⁽⁵⁾	—			8			(113		)	8
Balance, end of period	$	294		$	(63	)	$	294		$	(63	)
Change in unrealized gains (losses) relating to instruments still held at end of period	$	14		$	(9	)	$	105		$	(26	)

___________


(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 and six months ended June 30, 2017 and 2016.


(4)	There were $(2) million and nil in gains transferred out of level 2 into level 3 for each of the three months ended June 30, 2017 and 2016, and $3 million and nil in losses transferred out of level 2 into level 3 for the six months ended June 30, 2017 and 2016, respectively, due to changes in market liquidity in various power markets.


(5)	We had nil and $(8) million in losses transferred out of level 3 into level 2 for the three months ended June 30, 2017 and 2016, respectively, and $113 million in gains and $(8) million in losses transferred out of level 3 into level 2 for the six months ended June 30, 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 and six months ended June 30, 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 June 30, 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 June 30, 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
Derivative Instruments	June 30, 2017				December 31, 2016
Power (MWh)	(95		)		(86		)
Natural gas (MMBtu)	842				613
Environmental credits (Tonnes)	17				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 June 30, 2017, was $66 million for which we have posted collateral of $4 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 $1 million related to our derivative liabilities would be required and that no counterparty could request immediate, full settlement.

Accounting for Derivative Instruments

We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated 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 June 30, 2017 and December 31, 2016 (in millions):



	June 30, 2017
	Commodity Instruments		Interest Rate Hedging Instruments			Total Derivative Instruments
Balance Sheet Presentation
Current derivative assets	$	1,061	$	1		$	1,062
Long-term derivative assets	507		20			527
Total derivative assets	$	1,568	$	21		$	1,589

Current derivative liabilities	$	995	$	27		$	1,022
Long-term derivative liabilities	398		30			428
Total derivative liabilities	$	1,393	$	57		$	1,450
Net derivative assets (liabilities)	$	175	$	(36	)	$	139



	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



	June 30, 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	$	21	$	57	$	29	$	58
Total derivatives designated as cash flow hedging instruments	$	21	$	57	$	29	$	58

Derivatives not designated as hedging instruments:
Commodity instruments	$	1,568	$	1,393	$	2,239	$	2,048
Total derivatives not designated as hedging instruments	$	1,568	$	1,393	$	2,239	$	2,048
Total derivatives	$

CALPINE CORP - FORM 10-Q - July 27, 2017

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