Quarterly Report (10-q)

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

CO ₂		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 (CO ₂ ), and including methane (CH ₄ ), nitrous oxide (N ₂ O), sulfur hexafluoride (SF ₆ ), 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	$	1,589	$	1,450	$	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.

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 June 30, 2017 and December 31, 2016 (in millions):



	June 30, 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	$	932		$	(927	)	$	(5	)	$	—
Commodity forward contracts	636			(174		)	—			462
Interest rate hedging instruments	21			(8		)	—			13
Total derivative assets	$	1,589		$	(1,109	)	$	(5	)	$	475
Derivative (liabilities):
Commodity exchange traded futures and swaps contracts	$	(975	)	$	927		$	48		$	—
Commodity forward contracts	(418		)	174			28			(216		)
Interest rate hedging instruments	(57		)	8			—			(49		)
Total derivative (liabilities)	$	(1,450	)	$	1,109		$	76		$	(265	)
Net derivative assets (liabilities)	$	139		$	—		$	71		$	210



	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.

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 June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Realized gain (loss) ⁽¹⁾⁽²⁾
Commodity derivative instruments	$	44		$	63		$	73		$	181
Total realized gain (loss)	$	44		$	63		$	73		$	181

Mark-to-market gain (loss) ⁽³⁾
Commodity derivative instruments	$	(82	)	$	(36	)	$	(27	)	$	(131	)
Interest rate hedging instruments	1			—			1			1
Total mark-to-market gain (loss)	$	(81	)	$	(36	)	$	(26	)	$	(130	)
Total activity, net	$	(37	)	$	27		$	47		$	51

___________


(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 June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Realized and mark-to-market gain (loss) ⁽¹⁾
Derivatives contracts included in operating revenues ⁽²⁾⁽³⁾	$	(31	)	$	(272	)	$	192		$	(68	)
Derivatives contracts included in fuel and purchased energy expense ⁽²⁾⁽³⁾	(7		)	299			(146		)	118
Interest rate hedging instruments included in interest expense ⁽⁴⁾	1			—			1			1
Total activity, net	$	(37	)	$	27		$	47		$	51

___________


(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 June 30,						Three Months Ended June 30,
	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⁾	$	(15	)	$	(6	)	$	(11	)	$	(11	)	Interest expense
Interest rate hedging instruments ⁽¹⁾⁽²⁾	4			—			(4		)	—			Depreciation expense
Total	$	(11	)	$	(6	)	$	(15	)	$	(11	)



	Six Months Ended June 30,						Six Months Ended June 30,
	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⁾	$	(19	)	$	(18	)	$	(22	)	$	(22	)	Interest expense
Interest rate hedging instruments ⁽¹⁾⁽²⁾	4			—			(4		)	—			Depreciation expense
Total	$	(15	)	$	(18	)	$	(26	)	$	(22	)

____________


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


(2)	We recorded an income tax expense of $2 million in losses for each of the three and six months ended June 30, 2017 and nil for each of the three and six months ended June 30, 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 $107 million and $90 million at June 30, 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 June 30, 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 June 30, 2017 and December 31, 2016 (in millions):



	June 30, 2017		December 31, 2016
Margin deposits ⁽¹⁾	$	248	$	350
Natural gas and power prepayments	22		25
Total margin deposits and natural gas and power prepayments with our counterparties ⁽²⁾	$	270	$	375

Letters of credit issued	$	743	$	798
First priority liens under power and natural gas agreements	195		206
First priority liens under interest rate hedging instruments	55		55
Total letters of credit and first priority liens with our counterparties	$	993	$	1,059

Margin deposits posted with us by our counterparties ⁽¹⁾⁽³⁾	$	1	$	16
Letters of credit posted with us by our counterparties	27		43
Total margin deposits and letters of credit posted with us by our counterparties	$	28	$	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 June 30, 2017 and December 31, 2016 , $261 million and $366 million , respectively, were included in margin deposits and other prepaid expense and $9 million and $9 million , respectively, were included in other assets on our Consolidated Condensed Balance Sheets.


(3)	Included in other current liabilities on our Consolidated Condensed Balance Sheets.

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


8.	Income Taxes

Income Tax Expense (Benefit)

The table below shows our consolidated income tax expense (benefit) and our effective tax rates for the periods indicated (in millions):



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Income tax expense (benefit)	$	63		$	(14	)	$	2		$	21
Effective tax rate	(41		)%	33		%	(1		)%	(10		)%

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 and six months ended June 30, 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 six months ended June 30, 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 . Our Canadian subsidiaries are currently subject to examination by the Canada Revenue Agency for the years ended December 31, 2013 through 2016.

Valuation Allowance — U.S. GAAP requires that we consider all available evidence, both positive and negative, and tax planning strategies to determine whether, based on the weight of that evidence, a valuation allowance is needed to reduce the value of deferred tax assets. Future realization of the tax benefit of an existing deductible temporary difference or carryforward ultimately depends on the existence of sufficient taxable income of the appropriate character within the carryback or carryforward periods available under the tax law. Due to our history of losses, we were unable to assume future profits; however, we are able to consider available tax planning strategies.

Unrecognized Tax Benefits — At June 30, 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 $4 million for income tax matters at June 30, 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 and six months ended June 30, 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 and six months ended June 30, 2017 and 2016 , because they were anti-dilutive (shares in thousands):



	Three Months Ended June 30,		Six Months Ended June 30,
	2017	2016	2017	2016
Share-based awards	5,287	3,335	5,059	3,294


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 June 30, 2017 , 300,000 shares and 21,865,106 shares remain available for issuance under the 2017 Director Plan and the 2017 Equity Plan, respectively. There are no shares available for issuance under the 2008 Director Plan and the 2008 Equity Plan.

Equity Classified Share-Based Awards

Stock-based compensation expense recognized for our equity classified share-based awards was $9 million and $ 8 million for the three months ended June 30, 2017 and 2016 , respectively, and $ 17 million and $15 million for the six months ended June 30, 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 six months ended June 30, 2017 and 2016 . At June 30, 2017 , there was unrecognized compensation cost of $ 43 million related to restricted stock and restricted stock units and $ 6 million related to options which is expected to be recognized over a weighted average period of 1.7 years for restricted stock and restricted stock units and 2.3 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 Plans for the six months ended June 30, 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	1,476,480	$	11.70
Forfeited	15,721	$	11.69
Expired	22,800	$	17.69
Outstanding — June 30, 2017	4,135,095	$	12.90	5.0	$	6
Exercisable — June 30, 2017	2,674,336	$	13.55	2.5	$	4
Vested and expected to vest – June 30, 2017	3,946,197	$	12.96	4.8	$	6

The fair value of options granted during the six months ended June 30, 2017 , was determined on the grant date using the Black-Scholes option-pricing model. Certain assumptions were used in order to estimate fair value for options as noted in the following table:



	2017
Expected term (in years) ⁽¹⁾	7.3 - 10.0
Risk-free interest rate ⁽²⁾	2.25		%
Expected volatility ⁽³⁾	33 - 40		%
Dividend yield ⁽⁴⁾	—
Weighted average grant-date fair value (per option)	$	5.38

___________


(1)	Expected term calculated using historical exercise data.


(2)	Zero Coupon U.S. Treasury rate or equivalent based on expected term.


(3)	Volatility calculated using the implied volatility of our exchange traded stock options.


(4)	We have never paid cash dividends on our common stock and we do not anticipate any cash dividend payments on our common stock in the near future.

A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the six months ended June 30, 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	3,606,816		$	11.76
Forfeited	493,472		$	13.98
Vested	1,650,036		$	17.11
Nonvested — June 30, 2017	6,332,956	⁽¹⁾	$	13.32

___________


(1)	Includes 63,075 shares of restricted stock and restricted stock units outstanding under the Director Plans and 6,269,881 shares of restricted stock and restricted stock units outstanding under the Equity Plans.

The total fair value of our restricted stock and restricted stock units that vested during the six months ended June 30, 2017 and 2016 was approximately $ 19 million and $ 16 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 $3 million and nil for the three months ended June 30, 2017 and 2016 , respectively, and $3 million and $ 2 million for the six months ended June 30, 2017 and 2016 , respectively.

A summary of our performance share unit activity for the six months ended June 30, 2017 , is as follows:



	Number of Performance Share Units	Weighted Average Grant-Date Fair Value
Nonvested — December 31, 2016	890,587	$	17.90
Granted	478,984	$	10.73
Forfeited	54,638	$	18.38
Vested ⁽¹⁾	30,312	$	17.21
Nonvested — June 30, 2017	1,284,621	$	15.22

___________


(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 Plans 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 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 (“SF ₆ ”) due to a leak of SF ₆ during 2015 from one of the high voltage circuit breakers located in the Russell City Energy Center switchyard. SF ₆ is a gas used as an electrical insulator in

high voltage circuit breakers and is a GHG. During the second quarter of 2017, we reached a resolution of this issue with the CARB, which will not have a material effect on our financial condition, results of operations or cash flows.

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 June 30, 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 June 30, 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):



	Three Months Ended June 30, 2017
	West			Texas			East			Consolidation and Elimination			Total
Revenues from external customers	$	401		$	797		$	886		$	—		$	2,084
Intersegment revenues	—			5			2			(7		)	—
Total operating revenues	$	401		$	802		$	888		$	(7	)	$	2,084
Commodity Margin	$	244		$	167		$	236		$	—		$	647
Add: Mark-to-market commodity activity, net and other ⁽¹⁾	(38		)	(30		)	(18		)	(6		)	(92		)
Less:
Plant operating expense	111			109			89			(7		)	302
Depreciation and amortization expense	63			65			58			—			186
Sales, general and other administrative expense	8			21			11			—			40
Other operating expenses	8			3			8			1			20
(Income) from unconsolidated subsidiaries	—			—			(6		)	—			(6		)
Income (loss) from operations	16			(61		)	58			—			13
Interest expense													154
Debt extinguishment costs and other (income) expense, net													8
Loss before income taxes													$	(149	)



	Three Months Ended June 30, 2016
	West			Texas		East			Consolidation and Elimination			Total
Revenues from external customers	$	211		$	530	$	423		$	—		$	1,164
Intersegment revenues	1			4		4			(9		)	—
Total operating revenues	$	212		$	534	$	427		$	(9	)	$	1,164
Commodity Margin	$	254		$	160	$	243		$	—		$	657
Add: Mark-to-market commodity activity, net and other ⁽¹⁾	(62		)	7		28			(8		)	(35		)
Less:
Plant operating expense	98			85		96			(8		)	271
Depreciation and amortization expense	56			53		53			—			162
Sales, general and other administrative expense	8			14		12			1			35
Other operating expenses	7			2		10			(2		)	17
(Income) from unconsolidated subsidiaries	—			—		(3		)	—			(3		)
Income from operations	23			13		103			1			140
Interest expense												157
Debt extinguishment costs and other (income) expense, net												21
Loss before income taxes												$	(38	)



	Six Months Ended June 30, 2017
	West		Texas			East			Consolidation and Elimination			Total
Revenues from external customers	$	1,113	$	1,596		$	1,656		$	—		$	4,365
Intersegment revenues	2		8			4			(14		)	—
Total operating revenues	$	1,115	$	1,604		$	1,660		$	(14	)	$	4,365
Commodity Margin	$	465	$	315		$	425		$	—		$	1,205
Add: Mark-to-market commodity activity, net and other ⁽²⁾	39		(60		)	(26		)	(14		)	(61		)
Less:
Plant operating expense	208		205			185			(14		)	584
Depreciation and amortization expense	154		127			111			—			392
Sales, general and other administrative expense	21		38			21			—			80
Other operating expenses	17		6			17			—			40
(Gain) on sale of assets, net	—		—			(27		)	—			(27		)
(Income) from unconsolidated subsidiaries	—		—			(10		)	—			(10		)
Income (loss) from operations	104		(121		)	102			—			85
Interest expense												313
Debt extinguishment costs and other (income) expense, net												34
Loss before income taxes												$	(262	)



	Six Months Ended June 30, 2016
	West			Texas			East			Consolidation and Elimination			Total
Revenues from external customers	$	635		$	1,062		$	1,082		$	—		$	2,779
Intersegment revenues	3			7			7			(17		)	—
Total operating revenues	$	638		$	1,069		$	1,089		$	(17	)	$	2,779
Commodity Margin	$	451		$	313		$	473		$	—		$	1,237
Add: Mark-to-market commodity activity, net and other ⁽²⁾	(16		)	(103		)	7			(14		)	(126		)
Less:
Plant operating expense	189			171			180			(14		)	526
Depreciation and amortization expense	125			106			111			—			342
Sales, general and other administrative expense	18			30			24			1			73
Other operating expenses	15			4			20			(2		)	37
(Income) from unconsolidated subsidiaries	—			—			(10		)	—			(10		)
Income (loss) from operations	88			(101		)	155			1			143
Interest expense													314
Debt extinguishment costs and other (income) expense, net													26
Loss before income taxes													$	(197	)

_________


(1)	Includes $(24) million and $(20) million of lease levelization and $44 million and $27 million of amortization expense for the three months ended June 30, 2017 and 2016 , respectively.


(2)	Includes $(46) million and $(42) million of lease levelization and $104 million and $54 million of amortization expense for the six months ended June 30, 2017 and 2016 , respectively.


Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operation s

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 44 million MWh of electricity during the six months ended June 30, 2017 .


•	Our entire fleet achieved a starting reliability of 97.6% during the six months ended June 30, 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 is 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

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 successfully negotiated an amendment to the Clean Energy Supply Agreement associated with Greenfield LP for CO ₂ costs related to Ontario’s GHG law.


•	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.

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 natural gas and 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.

Strategic Alternatives Review

Early this Spring, our Board of Directors decided to explore strategic alternatives for the Company, seeking to enhance value for our shareholders. At this time, the Board, together with management and financial and legal advisors, are in discussions regarding a potential sale of Calpine. The Board plans to proceed in a timely manner, but has not set a definitive timetable for completion of these discussions. There can be no assurance that these discussions will result in a transaction of any kind, or if a transaction is undertaken, as to terms or timing. Calpine does not intend to disclose developments or provide updates on the status of these discussions unless or until it is determined that further disclosure is appropriate or required by law. Notwithstanding these discussions, the Calpine team remains committed to operational excellence, customer focus and financial discipline.

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 staff was directed to undertake the study over a 60-day period starting from April 19, 2017 to explore the evolution of wholesale electricity markets and the effect of federal policy interventions and changes in the electricity fuel mix; whether wholesale energy and capacity markets are adequately compensating attributes such as on-site fuel supply; and the extent to which continued regulations and policies are responsible for forcing the premature retirement of baseload power plants.

According to Secretary Perry’s directive, the results of the study are intended to be used to develop policy recommendations and solutions to protect the reliability and resiliency of the electric grid. The effect of this study on our business 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.

The CAISO is increasingly concerned with the premature retirement of uneconomic generation resources. It is evaluating the viability of units upon request and on a case-by-case basis particularly focusing on the risk of retirement in local, reliability constrained areas. 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.

Additionally, the PUCT has established a project to assess price formation rules in ERCOT’s energy-only market in an effort to take market participant input on the white paper, Priorities for the Evolution of an Energy-Only Electricity Market Design in ERCOT , which was commissioned by Calpine and NRG Energy, Inc. The paper was authored by Drs. William W. Hogan of Harvard University and Susan L. Pope of FTI Consulting, both widely recognized experts in the field of wholesale electric market design and price formation. The PUCT has scheduled an open workshop on the white paper’s recommendations to be conducted on August 10, 2017.

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

The Ohio utilities, led by American Electric Power, Inc. and FirstEnergy Corp. (“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 as it is currently stalled in the legislature and its prospects are uncertain, 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. On July 14, 2017, the federal district court dismissed the lawsuit in part for lack of subject-matter jurisdiction and in part for failure to state a claim. On July 17, 2017, the plaintiffs filed an appeal of this ruling to the U.S. Court of Appeals for the Seventh Circuit.

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 was 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 was 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 implemented transient/scarcity pricing on a five minute basis as ordered by the FERC. This new pricing regime is expected to increase energy revenues in the real-time energy market as well as reserve revenues.

In June 2017, the U.S. Court of Appeals for the District of Columbia Circuit (“D.C. Circuit”) denied the appeal filed by several entities related to the FERC’s orders which approved the PJM capacity market rule changes, referred to as Capacity Performance, which set forth stronger performance incentives and more significant penalties for failure to perform during emergency power system conditions. We support PJM’s capacity market rule changes and believe that, overall, they enhance the competitiveness and reliability of the PJM power market.

In July 2017, the D.C. Circuit granted an appeal filed by several generators regarding a May 2013 FERC order rejecting parts of a PJM proposal intended to make a component of PJM’s Reliability Pricing Model, the Minimum Offer Price Rule (“MOPR”), more transparent and objective. In the May 2013 order, the FERC accepted parts of PJM’s proposal but found that PJM must amend its tariff proposal in certain ways in order to make the proposal just and reasonable as required by the FERC’s regulations. PJM agreed to these changes, and the FERC approved the revised tariff filing. Several generators sought rehearing of the FERC’s order, which the FERC denied. In October 2015, an appeal followed. In the July 2017 decision, the D.C. Circuit found that the FERC does not have the authority under Section 205 of the Federal Power Act to propose its own tariff modifications, even though PJM agreed to the FERC’s proposed changes. The D.C. Circuit vacated the FERC’s orders with respect to several components of the tariff filing and remanded the matter to the FERC. We cannot predict how the FERC will address the case on remand or what effect, if any, the D.C. Circuit’s decision will have on our business.

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 March 27, 2017, the Massachusetts Department of Public Utilities approved the issuance of a Request for Proposals (“RFP”) for up to 1,200 MW of new “clean energy” resources. A separate RFP for at least 400 MW of offshore wind was issued on June 29, 2017. 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 PPA. The legislation did not pass in the regular legislative session which adjourned on June 7, 2017; however, it may be reintroduced in a special legislative session expected to be convened later this summer. 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.

ISO-NE and PJM Market Reform Proposals

Both ISO-NE and PJM have released draft proposals that would accommodate state procurement initiatives while at the same time protecting the integrity of their power markets. ISO-NE’s proposal focuses on changes to the Forward Capacity Market, while PJM’s proposals suggest possible changes to energy price formation, ancillary service procurement, as well as modifications to the Reliability Pricing Model. All of these proposals will be discussed in stakeholder processes over the upcoming months. It is possible that the current proposals may be significantly modified, or possibly even withdrawn altogether. Because of this, and because it is unknown how the FERC will rule on any resulting tariff changes, we cannot predict the effect these changes will have on our business in those regions.

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 in the form of ZECs 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. On July 25, 2017, the federal district court dismissed the lawsuit, finding that plaintiffs do not have a private right to bring the claims, and further finds that the ZEC program is not preempted by

federal law and does not violate the dormant Commerce Clause. The plaintiffs will likely appeal this ruling to the U.S. Court of Appeals for the Second Circuit. We cannot predict the outcome of the appeal, but if the PSC’s action is 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.

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 CO ₂ 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 CO ₂ surcharge on its natural gas transportation invoice. Greenfield LP has a long-term Clean Energy Supply Contract (“CESA”) with the IESO, successor to the Ontario Power Authority. In May 2017, Greenfield LP and the IESO reached an agreement on the effect of Ontario’s Cap-and-Trade program under the CESA which will not have a material effect on Calpine’s financial condition, results of operations or cash flows. On a related note, Whitby has a PPA with the Ontario Electricity Financial Corporation, successor to Ontario Hydro. Whitby is seeking to recover related CO ₂ 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 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.

California: GHG – Cap-and-Trade Regulation

The Cap-and-Trade Regulation was subject to legal challenges claiming that, by requiring covered entities to obtain allowances, 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 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. On June 28, 2017, the California Supreme Court rejected petitions for review of the decision, affirming the legality of the Cap-and-Trade program through 2020.

On July 17, 2017, the California legislature passed Assembly Bill (“AB”) 398, by a two-thirds supermajority vote, authorizing extension of the Cap-and-Trade Regulation through 2030. AB 398 requires the CARB to develop a price ceiling considering, among other things, the full social cost associated with emitting a ton of GHGs and the cost per ton of GHG emission reductions needed to achieve California’s goal of reducing statewide GHG emissions to 40 percent below 1990 levels by 2030. AB 398 was passed along with a companion bill, AB 617, which requires the CARB to prepare a statewide strategy to reduce emissions of toxic air contaminants and criteria air pollutants in communities affected by a high cumulative exposure burden and the local air districts to prepare community emissions reduction programs to achieve emissions reductions within such communities, as identified by the CARB. California Governor Brown is expected to sign both bills into law.

Several of our natural gas-fired power plants in California will likely remain subject to the Cap-and-Trade Regulation through 2030 as a result of passage of AB 398, although we believe the net effect of the Cap-and-Trade Regulation will be beneficial to us, particularly by increasing the appeal of our Geysers Assets. While it is too early to predict whether any of our California natural gas-fired power plants may ultimately be subject to a requirement to reduce emissions under AB 617 or what such a requirement might entail, much of our California fleet already meets emissions limits that are among the lowest in the U.S. and we do not anticipate that significant additional reductions will be required from our fleet pursuant to AB 617.

California RPS

California’s RPS requires retail power providers to generate or procure 33% and 50% of the power they sell to retail customers from renewable resources by 2020 and 2030, respectively, with intermediate targets leading up to 2020 and 2030. Behind-the-meter solar generally does not count towards California’s RPS requirements. Under California’s RPS, there are limits

on different “buckets” of procurement that can be used to satisfy the RPS. Load-serving entities must satisfy a growing fraction of their compliance obligations with renewable power from resources located in California or delivered into California within the hour, such as our Geysers Assets. The California legislature is currently considering increasing the RPS to 60% by 2030 and, potentially, a 100% CO ₂ -free RPS by 2045. While the RPS generally depresses wholesale energy prices, the intermittency of many renewable resources raises operational flexibility challenges that present opportunities for natural gas-fired generation to provide capacity and ancillary services products.

RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED JUNE 30, 2017 AND 2016

Below are our results of operations for the three months ended June 30, 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	$	2,145		$	1,551		$	594		38
Mark-to-market (loss)	(66		)	(391		)	325			83
Other revenue	5			4			1			25
Operating revenues	2,084			1,164			920			79
Operating expenses:
Fuel and purchased energy expense:
Commodity expense	1,513			897			(616		)	(69	)
Mark-to-market (gain) loss	16			(355		)	(371		)	#
Fuel and purchased energy expense	1,529			542			(987		)	#
Plant operating expense	302			271			(31		)	(11	)
Depreciation and amortization expense	186			162			(24		)	(15	)
Sales, general and other administrative expense	40			35			(5		)	(14	)
Other operating expenses	20			17			(3		)	(18	)
Total operating expenses	2,077			1,027			(1,050		)	#
(Income) from unconsolidated subsidiaries	(6		)	(3		)	3			#
Income from operations	13			140			(127		)	(91	)
Interest expense	154			157			3			2
Debt extinguishment costs	1			15			14			93
Other (income) expense, net	7			6			(1		)	(17	)
Loss before income taxes	(149		)	(38		)	(111		)	#
Income tax expense (benefit)	63			(14		)	(77		)	#
Net loss	(212		)	(24		)	(188		)	#
Net income attributable to the noncontrolling interest	(4		)	(5		)	1			20
Net loss attributable to Calpine	$	(216	)	$	(29	)	$	(187	)	#



	2017		2016		Change		% Change
Operating Performance Metrics:
MWh generated (in thousands) ⁽¹⁾⁽²⁾	21,849		26,355		(4,506	)	(17	)
Average availability ⁽²⁾	82.2	%	85.6	%	(3.4	)%	(4	)
Average total MW in operation ⁽¹⁾	25,128		26,502		(1,374	)	(5	)
Average capacity factor, excluding peakers	44.4	%	50.2	%	(5.8	)%	(12	)
Steam Adjusted Heat Rate ⁽²⁾	7,318		7,313		(5	)	—

__________


#	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.

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 Free Cash Flow.”

Commodity revenue, net of Commodity expense, decreased $22 million for the three months ended June 30, 2017, compared to the same period in 2016, primarily due to (favorable variances are shown without brackets while unfavorable variances are shown with brackets):



(in millions)
$	51		Higher energy margins due to increased contribution from hedging activity following the acquisitions of Calpine Solutions in December 2016 and North American Power in January 2017 and higher realized Spark Spreads in our Texas segment. These factors were partially offset by the expiration of a PPA at our York Energy Center in our East segment, lower market Spark Spreads in our East segment and lower generation across all segments ⁽¹⁾
(40		)	A natural gas pipeline transportation billing credit received in our West segment during the second quarter of 2016 with no similar credit received in 2017 ⁽¹⁾
(18		)	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⁾
(3		)	Lower regulatory capacity revenue primarily in our East segment ⁽¹⁾
(12		)	Contract amortization, lease levelization related to tolling contracts and other ⁽²⁾
$	(22	)

__________


(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 Free Cash Flow” 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, net from hedging our future generation, retail activities and fuel needs had an unfavorable variance of $46 million primarily driven by the change in forward commodity prices on our derivative contracts during the quarter ended June 30, 2017.

Our normal, recurring plant operating expense decreased by $3 million for the three months ended June 30, 2017 compared to the same period in 2016, after excluding the effect of a $13 million increase due to the period-over-period effect associated with the expansion of our retail portfolio through the acquisitions of Calpine Solutions in December 2016 and North American Power in January 2017, a $9 million increase in severance and other employee-related costs, an $8 million increase in equipment failure costs primarily due to an outage at our Delta Energy Center and a $4 million increase in major maintenance expense resulting from our plant outage schedule and costs from scrap parts related to outages.

Depreciation and amortization expense increased by $24 million for the three months ended June 30, 2017 compared to the same period in 2016 primarily due to the acquisitions of Calpine Solutions and North American Power in December 2016 and January 2017, respectively, and the reclassification of South Point Energy Center from held for sale to held and used during the first quarter of 2017.

Sales, general and other administrative expense increased by $5 million for the three months ended June 30, 2017 compared to the same period in 2016 primarily due to the acquisitions of Calpine Solutions and North American Power in December 2016 and January 2017, respectively, and higher stock-based compensation expense resulting from an increase in the value of our performance share units during the second quarter of 2017.

Debt extinguishment costs for the three months ended June 30, 2016, consisted of $15 million from the write-off of deferred financing costs in connection with the repayment of our 2019 and 2020 First Lien Term Loans in April 2016.

During the three months ended June 30, 2017, we recorded an income tax expense of $63 million compared to an income tax benefit of $14 million for the three months ended June 30, 2016. The unfavorable period-over-period change primarily resulted

from an increase in state income tax expense due to higher income in the current year in state tax jurisdictions where we do not have NOLs.

RESULTS OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2017 AND 2016

Below are our results of operations for the six months ended June 30, 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	$	4,208		$	3,136		$	1,072		34
Mark-to-market gain (loss)	148			(366		)	514			#
Other revenue	9			9			—			—
Operating revenues	4,365			2,779			1,586			57
Operating expenses:
Fuel and purchased energy expense:
Commodity expense	3,046			1,903			(1,143		)	(60	)
Mark-to-market (gain) loss	175			(235		)	(410		)	#
Fuel and purchased energy expense	3,221			1,668			(1,553		)	(93	)
Plant operating expense	584			526			(58		)	(11	)
Depreciation and amortization expense	392			342			(50		)	(15	)
Sales, general and other administrative expense	80			73			(7		)	(10	)
Other operating expenses	40			37			(3		)	(8	)
Total operating expenses	4,317			2,646			(1,671		)	(63	)
(Gain) on sale of assets, net	(27		)	—			27			#
(Income) from unconsolidated subsidiaries	(10		)	(10		)	—			—
Income from operations	85			143			(58		)	(41	)
Interest expense	313			314			1			—
Debt extinguishment costs	25			15			(10		)	(67	)
Other (income) expense, net	9			11			2			18
Loss before income taxes	(262		)	(197		)	(65		)	(33	)
Income tax expense	2			21			19			90
Net loss	(264		)	(218		)	(46		)	(21	)
Net income attributable to the noncontrolling interest	(8		)	(9		)	1			11
Net loss attributable to Calpine	$	(272	)	$	(227	)	$	(45	)	(20	)



	2017		2016		Change		% Change
Operating Performance Metrics:
MWh generated (in thousands) ⁽¹⁾⁽²⁾	42,673		50,480		(7,807	)	(15	)
Average availability ⁽²⁾	84.8	%	87.8	%	(3.0	)%	(3	)
Average total MW in operation ⁽¹⁾	25,202		26,370		(1,168	)	(4	)
Average capacity factor, excluding peakers	43.6	%	48.8	%	(5.2	)%	(11	)
Steam Adjusted Heat Rate ⁽²⁾	7,331		7,289		(42	)	(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.

Commodity revenue, net of Commodity expense, decreased $71 million for the six months ended June 30, 2017, compared to the same period in 2016, primarily due to (favorable variances are shown without brackets while unfavorable variances are shown with brackets):



(in millions)
$	59		Higher energy margins due to increased contribution from hedging activity following the acquisitions of Calpine Solutions in December 2016 and North American Power in January 2017 and higher market Spark Spreads in our Texas segment. These factors were partially offset by the expiration of a PPA at our York Energy Center in our East segment, lower market Spark Spreads in our East segment and lower generation across all segments ⁽¹⁾
(40		)	A natural gas pipeline transportation billing credit received in our West segment during the second quarter of 2016 with no similar credit received in 2017 ⁽¹⁾
(30		)	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⁾
(21		)	Lower regulatory capacity revenue primarily in our East segment ⁽¹⁾
(39		)	Contract amortization, lease levelization related to tolling contracts and other ⁽²⁾
$	(71	)

__________


(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 Free Cash Flow” 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, net from hedging our future generation, retail activities and fuel needs had a favorable variance of $104 million primarily driven by the change in forward commodity prices on our derivative contracts during the six months ended June 30, 2017 and due to the expansion of our retail hedging portfolio following the acquisition of Calpine Energy Solutions in December 2016.

Our normal, recurring plant operating expense decreased by $7 million for the six months ended June 30, 2017 compared to the same period in 2016, after excluding the effect of a $38 million increase due to the period-over-period effect associated with the expansion of our retail portfolio through the acquisitions of Calpine Solutions in December 2016 and North American Power in January 2017 which was partially offset by the period-over-period effect of power plant portfolio changes, a $12 million increase in severance and other employee-related costs, an $11 million increase in equipment failure costs primarily due to an outage at our Delta Energy Center and a $4 million increase in major maintenance expense resulting from our plant outage schedule and costs from scrap parts related to outages.

Depreciation and amortization expense increased by $50 million for the six months ended June 30, 2017 compared to the same period in 2016 primarily due to the acquisitions of Granite Ridge Energy Center in February 2016 and Calpine Solutions and North American Power in December 2016 and January 2017, respectively. Also contributing to the increase in depreciation and amortization expense was an adjustment to South Point Energy Center as it was reclassified from held for sale to held and used during the first quarter of 2017.

Sales, general and other administrative expense increased by $7 million for the six months ended June 30, 2017 compared to the same period in 2016 primarily due to the acquisitions of Calpine Solutions and North American Power in December 2016 and January 2017, respectively.

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 six months ended June 30, 2017.

Debt extinguishment costs for the six months ended June 30, 2017, primarily 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, and $3 million 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. Debt extinguishment costs for the six months ended June 30, 2016, consisted of $15 million from the write-off of deferred financing costs in connection with the repayment of our 2019 and 2020 First Lien Term Loans in May 2016.

During the six months ended June 30, 2017, we recorded an income tax expense of $2 million compared to an income tax expense of $21 million for the six months ended June 30, 2016. The favorable period-over-period change primarily resulted from a favorable adjustment to our reserve for uncertain tax positions.

COMMODITY MARGIN AND ADJUSTED FREE CASH FLOW

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 Free Cash Flow, discussed below, which we use as measures of our performance and liquidity, respectively. 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.

With respect to our non-GAAP financial measures, over the next two quarterly reporting periods, we are transitioning from using Adjusted EBITDA as a performance measure to using Commodity Margin and Adjusted Free Cash Flow as measures of our performance and liquidity, respectively.

We use Commodity Margin, a non-GAAP financial measure, to assess reportable segment performance. Commodity Margin includes revenues recognized on our wholesale and retail power sales activity, electric capacity sales, REC sales, steam sales, realized settlements associated with our marketing, hedging, optimization and trading activity, fuel and purchased energy expenses, commodity transmission and transportation expenses and environmental compliance expenses. 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 (loss) 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 June 30, 2017 and 2016

The following tables show our Commodity Margin and related operating performance metrics by segment for the three months ended June 30, 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)	$	244		$	254		$	(10	)	(4	)
Commodity Margin per MWh generated	$	67.35		$	50.45		$	16.90		33

MWh generated (in thousands)	3,623			5,035			(1,412		)	(28	)
Average availability	72.5		%	85.6		%	(13.1		)%	(15	)
Average total MW in operation	7,425			7,425			—			—
Average capacity factor, excluding peakers	23.8		%	33.1		%	(9.3		)%	(28	)
Steam Adjusted Heat Rate	7,547			7,316			(231		)	(3	)

West — Commodity Margin in our West segment decreased by $10 million, or 4%, for the three months ended June 30, 2017 compared to the three months ended June 30, 2016, primarily due to the receipt of a $40 million natural gas pipeline transportation billing credit during the second quarter of 2016. The decrease in Commodity Margin was partially offset by the expansion of our retail hedging activities following the acquisition of Calpine Solutions in December 2016 and higher generation margin where we realized higher Spark Spreads during hours in which we generated, particularly evening peak times. Generation decreased 28% resulting from an increase in hydroelectric generation in the region and an extended outage at our Delta Energy

Center during the first half of 2017. Our Delta Energy Center was restored to simple-cycle operation during the second quarter of 2017 and we expect the power plant will be fully restored to service in the fourth quarter of 2017.



Texas:	2017			2016			Change			% Change
Commodity Margin (in millions)	$	167		$	160		$	7		4
Commodity Margin per MWh generated	$	15.45		$	12.92		$	2.53		20

MWh generated (in thousands)	10,809			12,387			(1,578		)	(13	)
Average availability	84.2		%	88.9		%	(4.7		)%	(5	)
Average total MW in operation	8,791			9,191			(400		)	(4	)
Average capacity factor, excluding peakers	56.3		%	61.7		%	(5.4		)%	(9	)
Steam Adjusted Heat Rate	7,058			7,138			80			1

Texas — Commodity Margin in our Texas segment increased by $7 million, or 4%, for the three months ended June 30, 2017 compared to the three months ended June 30, 2016, primarily due to higher on-peak realized Spark Spreads in the ERCOT Houston zone and the expansion of our retail hedging activities following the acquisition of Calpine Solutions in December 2016. The increase in Commodity Margin was partially offset by a 13% decrease in generation resulting from lower availability due to an increase in outages and higher natural gas prices during the second quarter of 2017 compared to the same period in 2016.



East:	2017			2016			Change			% Change
Commodity Margin (in millions)	$	236		$	243		$	(7	)	(3	)
Commodity Margin per MWh generated	$	31.82		$	27.20		$	4.62		17

MWh generated (in thousands)	7,417			8,933			(1,516		)	(17	)
Average availability	87.4		%	82.4		%	5.0		%	6
Average total MW in operation	8,912			9,886			(974		)	(10	)
Average capacity factor, excluding peakers	50.3		%	51.7		%	(1.4		)%	(3	)
Steam Adjusted Heat Rate	7,646			7,570			(76		)	(1	)

East — Commodity Margin in our East segment decreased by $7 million, or 3%, for the three months ended June 30, 2017 compared to the three months ended June 30, 2016, primarily due to the sales of the 375 MW Mankato Power Plant in October 2016 and the 599 MW Osprey Energy Center in January 2017, lower market Spark Spreads during the second quarter of 2017 and the expiration of a PPA associated with our York Energy Center in May 2017. The decrease in Commodity Margin was partially offset by the expansion of our retail hedging activities following the acquisitions of Calpine Solutions in December 2016 and North American Power in January 2017. Generation decreased 17% resulting from the power plant sales and lower Spark Spreads during the second quarter of 2017 compared to the same period in 2016.

Commodity Margin by Segment for the Six Months Ended June 30, 2017 and 2016

The following tables show our Commodity Margin and related operating performance metrics by segment for the six months ended June 30, 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)	$	465		$	451		$	14		3
Commodity Margin per MWh generated	$	51.26		$	39.38		$	11.88		30

MWh generated (in thousands)	9,072			11,453			(2,381		)	(21	)
Average availability	79.4		%	88.0		%	(8.6		)%	(10	)
Average total MW in operation	7,425			7,425			—			—
Average capacity factor, excluding peakers	30.0		%	38.0		%	(8.0		)%	(21	)
Steam Adjusted Heat Rate	7,410			7,324			(86		)	(1	)

West — Commodity Margin in our West segment increased by $14 million, or 3%, for the six months ended June 30, 2017 compared to the six months ended June 30, 2016, primarily due to the expansion of our retail hedging activities following the acquisition of Calpine Solutions in December 2016 and higher generation margin where we realized higher Spark Spreads during hours in which we generated, particularly evening peak times. The increase in Commodity Margin was partially offset by receipt of a $40 million natural gas pipeline transportation billing credit during the second quarter of 2016. Generation decreased 21% resulting from an increase in hydroelectric generation in the region and an extended outage at our Delta Energy Center during the first half of 2017. Our Delta Energy Center was restored to simple-cycle operation during the second quarter of 2017 and we expect the power plant will be fully restored to service in the fourth quarter of 2017.



Texas:	2017			2016			Change			% Change
Commodity Margin (in millions)	$	315		$	313		$	2		1
Commodity Margin per MWh generated	$	15.59		$	13.24		$	2.35		18

MWh generated (in thousands)	20,207			23,636			(3,429		)	(15	)
Average availability	85.6		%	87.8		%	(2.2		)%	(3	)
Average total MW in operation	8,858			9,191			(333		)	(4	)
Average capacity factor, excluding peakers	52.5		%	58.9		%	(6.4		)%	(11	)
Steam Adjusted Heat Rate	7,086			7,095			9			—

Texas — Commodity Margin in our Texas segment increased by $2 million, or 1%, for the six months ended June 30, 2017 compared to the six months ended June 30, 2016, primarily due to higher market Spark Spreads and the expansion of our retail hedging activities following the acquisition of Calpine Solutions in December 2016. The increase in Commodity Margin was largely offset by lower contribution from wholesale hedging activity as well as a 15% decrease in generation resulting from lower availability due to an increase in outages and higher natural gas prices during the six months ended June 30, 2017 compared to the same period in 2016.



East:	2017			2016			Change			% Change
Commodity Margin (in millions)	$	425		$	473		$	(48	)	(10	)
Commodity Margin per MWh generated	$	31.73		$	30.73		$	1.00		3

MWh generated (in thousands)	13,394			15,391			(1,997		)	(13	)
Average availability	88.0		%	87.7		%	0.3		%	—
Average total MW in operation	8,919			9,754			(835		)	(9	)
Average capacity factor, excluding peakers	45.9		%	46.3		%	(0.4		)%	(1	)
Steam Adjusted Heat Rate	7,678			7,581			(97		)	(1	)

East — Commodity Margin in our East segment decreased by $48 million, or 10%, for the six months ended June 30, 2017 compared to the six months ended June 30, 2016, primarily due to the sales of the 375 MW Mankato Power Plant in October 2016 and the 599 MW Osprey Energy Center in January 2017, the expiration of a PPA associated with our York Energy Center in May 2017, lower market Spark Spreads during the first half of 2017 and lower regulatory capacity revenue in PJM. The decrease in Commodity Margin was partially offset by the expansion of our retail hedging activities 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 which became effective in February 2016. Generation decreased 13% primarily resulting from the power plant sales.

Adjusted Free Cash Flow

We define Adjusted Free Cash Flow, a non-GAAP liquidity measure, as cash flows from operating activities adjusted for certain items described below and presented in the accompanying reconciliation. We believe Adjusted Free Cash Flow is useful to investors and other users of our financial statements in evaluating our liquidity and operating performance as it provides an additional tool to compare financial results across companies and across periods. Additionally, we believe that Adjusted Free Cash Flow is widely used by investors to measure a company’s liquidity. Adjusted Free Cash Flow 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 financial results presented in accordance with U.S. GAAP. Adjusted Free Cash Flow is not intended to represent cash flows from operations as defined by U.S. GAAP as an indicator of liquidity and is not necessarily comparable to similarly-titled measures reported by other companies.

As we define it, Adjusted Free Cash Flow represents cash flows from operating activities including the effects of maintenance capital expenditures, adjustments to reflect the Adjusted Free Cash Flow from unconsolidated investments and to exclude the noncontrolling interest, and other miscellaneous adjustments such as the effect of changes in working capital. We adjust for these items in our Adjusted Free Cash Flow as our management believes that they would distort their ability to efficiently view and assess our core operating and liquidity trends.

In summary, our management determined that Adjusted Free Cash Flow is a useful measure of liquidity to assist in comparing financial results 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 results.

In the following table, we have reconciled our cash flows from operating activities to our Adjusted Free Cash Flow for the three and six months ended June 30, 2017 and 2016 (in millions):



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Net cash provided by operating activities	$	152		$	94		$	246		$	125
Maintenance capital expenditures	(59		)	(41		)	(109		)	(81		)
Tax differences	(13		)	4			(16		)	2
Adjustments to reflect Adjusted Free Cash Flow from unconsolidated investments and exclude the non-controlling interest	5			(11		)	—			(2		)
Capitalized corporate interest	(6		)	(5		)	(13		)	(9		)
Changes in working capital ⁽¹⁾	34			133			46			251
Other ⁽²⁾	(10		)	(16		)	(8		)	(26		)
Adjusted Free Cash Flow ⁽³⁾	$	103		$	158		$	146		$	260

Net cash used in investing activities	$	(38	)	$	(65	)	$	(51	)	$	(676	)
Net cash used in financing activities	$	(63	)	$	(58	)	$	(319	)	$	(140	)

_________


(1)	Adjustment excludes $3 million and $35 million in amortization of acquired derivatives contracts for the three months ended June 30, 2017 and 2016 , respectively, and $(10) million and $45 million in amortization of acquired derivatives contracts for the six months ended June 30, 2017 and 2016 , respectively.


(2)	Other adjustments primarily represent miscellaneous items excluded from Adjusted Free Cash Flow that are included in cash flow from operations.


(3)	Adjusted Free Cash Flow is shown net of the following items for the three and six months ended June 30, 2017 and 2016 (in millions):



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Cash interest, net	$	153	$	159	$	311	$	317
Operating lease payments	$	7	$	7	$	13	$	13

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 June 30, 2017 and December 31, 2016 (in millions):



	June 30, 2017		December 31, 2016
Cash and cash equivalents, corporate ⁽¹⁾	$	235	$	345
Cash and cash equivalents, non-corporate	59		73
Total cash and cash equivalents	294		418
Restricted cash	133		188
Corporate Revolving Facility availability ⁽²⁾	1,316		1,255
CDHI letter of credit facility availability	43		50
Total current liquidity availability ⁽³⁾	$	1,786	$	1,911

____________


(1)	Includes $1 million and $16 million of margin deposits posted with us by our counterparties at June 30, 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 June 30,

2017 , an increase of $1/MMBtu in natural gas prices would result in a decrease of collateral required by approximately $304 million. If natural gas prices decreased by $1/MMBtu, we estimate that our collateral requirements would increase by approximately $325 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 June 30, 2017 , an increase of 500 Btu/KWh in the Market Heat Rate would result in an increase in collateral required by approximately $16 million. If Market Heat Rates were to fall at a similar rate, we estimate that our collateral required would decrease by approximately $9 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 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.

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

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. Due to construction delays, we are now targeting COD in the first half of 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.

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 six months ended June 30, 2017 and 2016 (in millions):



	2017			2016
Beginning cash and cash equivalents	$	418		$	906
Net cash provided by (used in):
Operating activities	246			125
Investing activities	(51		)	(676		)
Financing activities	(319		)	(140		)
Net decrease in cash and cash equivalents	(124		)	(691		)
Ending cash and cash equivalents	$	294		$	215

Net Cash Provided By Operating Activities

Cash provided by operating activities for the six months ended June 30, 2017, was $246 million compared to $125 million for the six months ended June 30, 2016. The increase was primarily due to:

•

Income from operations — Income from operations, adjusted for non-cash items, decreased by $88 million for the six months ended June 30, 2017, compared to the same period in 2016. Non-cash items consist primarily of depreciation and amortization, income from unconsolidated investments in subsidiaries, gain on sale of assets and mark-to-market activity. The decrease in income from operations was primarily driven by a $20 million decrease in Commodity revenue, net of Commodity expense, excluding non-cash amortization, and a $58 million increase in plant operating expense. See “Results of Operations for the Six Months Ended June 30, 2017 and 2016” above for further discussion of these changes.

•

Working capital employed — Working capital employed decreased by $210 million for the six months ended June 30, 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 primarily related to the newly acquired Calpine Solutions retail energy provider acquired during December 2016 and a decrease in accounts receivable, net of accounts payable, resulting from timing of payments made during the periods offset by the effect of the acquisitions of Calpine Solutions during the fourth quarter of 2016 and North American Power during the first quarter of 2017.

Net Cash Used In Investing Activities

Cash used in investing activities for the six months ended June 30, 2017, was $51 million compared to $676 million for the six months ended June 30, 2016. The decrease was primarily due to:

•

Acquisitions and Divestitures — During the six months ended June 30, 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 six months ended June 30, 2016, we purchased Granite Ridge Energy Center for a net purchase price of $526 million.


•	Capital expenditures — Capital expenditures for the six months ended June 30, 2017 were $187 million, a decrease of $36 million compared to expenditures of $223 million for the six months ended June 30, 2016. The decrease was

primarily due to lower expenditures on construction projects during the six months ended June 30, 2017 as compared to the same period in 2016.

Net Cash Used In Financing Activities

Cash used in financing activities for the six months ended June 30, 2017, was $319 million compared to $140 million for the six months ended June 30, 2016. The increase was primarily due to:

•

First Lien Term Loans and First Lien Notes — During the six months ended June 30, 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. During the six months ended June 30, 2016, we utilized proceeds from the issuance of a portion of our 2023 First Lien Term Loans and the 2026 First Lien Notes to repay the 2019 and 2020 First Lien Term Loans of $1.2 billion.


•	Financing costs — During the six months ended June 30, 2017, we incurred finance costs of $9 million due to issuance of the 2019 First Lien Term Loan. During the six months ended June 30, 2016, we incurred finance costs of $26 million due to the issuances of a portion of our 2023 First Lien Term Loans and 2026 First Lien Notes and amending the Corporate Revolving Facility.

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.

Special Purpose Subsidiaries

Pursuant to applicable transaction agreements, we have established certain of our entities separate from Calpine Corporation and our other subsidiaries. In accordance with applicable accounting standards, we consolidate these entities with the exception of Calpine Receivables (see Notes 2 and 5 of the Notes to Consolidated Financial Statements in our 2016 Form 10-K for further information related to Calpine Receivables). As of the date of filing of this Report, these entities included: Russell City Energy Company, LLC, Otay Mesa Energy Center, LLC and Calpine Receivables.

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 $1.6 billion at June 30, 2017 , when compared to approximately $2.3 billion at December 31, 2016 , and our derivative liabilities have decreased to approximately $1.5 billion at June 30, 2017 , when compared to approximately $2.1 billion at December 31, 2016 . The fair value of our level 3 derivative assets and liabilities at June 30, 2017 represents approximately 20% and 4% 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.

The change in fair value of our outstanding commodity and interest rate hedging instruments from January 1, 2017, through June 30, 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⁾	(128		)	15			(113		)
Fair value attributable to new contracts ⁽³⁾	85			(2		)	83
Changes in fair value attributable to price movements	25			(20		)	5
Changes in fair value attributable to nonperformance risk	2			—			2
Fair value of contracts outstanding at June 30, 2017 ⁽⁴⁾	$	175		$	(36	)	$	139

__________

(1)

Commodity contract settlements consist of the realization of previously recognized gains on contracts not designated as hedging instruments of $116 million (represents a portion of Commodity revenue and Commodity expense as reported on our Consolidated Condensed Statements of Operations) and $12 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 $14 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 $23 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 June 30, 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	$	(28	)	$	(7	)	$	(6	)	$	(2	)	$	(43	)
Prices provided by other external sources	(33		)	(10		)	2			—			(41		)
Prices based on models and other valuation methods	79			127			42			11			259
Total fair value	$	18		$	110		$	38		$	9		$	175

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

The table below presents the high, low and average of our daily VAR for the three and six months ended June 30, 2017 and 2016 (in millions):



	2017		2016
Three months ended June 30:
High	$	22	$	35
Low	$	16	$	14
Average	$	19	$	23

Six months ended June 30:
High	$	22	$	35
Low	$	16	$	14
Average	$	19	$	22
As of June 30	$	21	$	32

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.

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 June 30, 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 June 30, 2017)	2017			2018-2019			2020-2021		After 2021		Total
Investment grade	$	13		$	75		$	31	$	5	$	124
Non-investment grade	10			36			7		4		57
No external ratings	(5		)	(1		)	—		—		(6		)
Total fair value	$	18		$	110		$	38	$	9	$	175

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 $(21) million at June 30, 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 second 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.

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⁾
April	4,497	$	10.88	—	$	307
May	25,509	$	12.16	—	$	307
June	8,032	$	13.54	—	$	307
Total	38,038	$	12.30	—	$	307

___________


(1)	Represents shares withheld by us to satisfy tax withholding obligations associated with the vesting of restricted stock awarded to employees during the second quarter of 2017.


(2)	In November 2014, our Board of Directors authorized an increase in the total authorization of our multi-year share repurchase program to $1.0 billion. There is no expiration date on the repurchase authorization and the amount and timing of future share repurchases, if any, will be determined as market and business conditions warrant.


Item 3.	Defaults Upon Senior Securities

None.


Item 4.	Mine Safety Disclosures

Not applicable.


Item 5.	Other Information

None.


Item 6.	Exhibits

EXHIBIT INDEX



Exhibit Number		Description

3.1		Amended and Restated Bylaws of the Company (as amended through May 10, 2017) (incorporated by reference to Exhibit 3.1 to Calpine ’ s Current Report on Form 8-K, filed with the SEC on May 10, 2017).

10.1		Form of Restricted Stock Unit Award Agreement Under Amended and Restated Calpine Corporation 2017 Equity Incentive Plan between the Company and W. Thaddeus Miller. †

10.2		Form of Restricted Stock Unit Award Agreement Under Amended and Restated Calpine Corporation 2017 Equity Incentive Plan between the Company and Certain Designated Senior Employees. †

10.3		Calpine Corporation 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.1 to Calpine ’ s Current Report on Form 8-K, filed with the SEC on May 10, 2017). †

10.4		Calpine Corporation Equity Compensation Plan for Non-Employee Directors (incorporated by reference to Exhibit 10.2 to Calpine ’ s Current Report on Form 8-K, filed with the SEC on May 10, 2017). †

10.5		Amended and Restated Executive Employment Agreement between the Company and John B. (Thad) Hill, dated May 16, 2017 (incorporated by reference to Exhibit 10.1 to Calpine ’ s Current Report on Form 8-K, filed with the SEC on May 18, 2017). †

10.6		Restricted Stock Agreement, Pursuant to the 2017 Equity Incentive Plan, dated May 16, 2017, between John B. (Thad) Hill III and Calpine Corporation. †

10.7		Performance Share Unit Grant Award Agreement, Pursuant to the 2017 Equity Incentive Plan, dated May 16, 2017, between John B. (Thad) Hill III and Calpine Corporation. †

10.8		Non-Qualified Stock Option Agreement, Pursuant to the 2017 Equity Incentive Plan, dated May 16, 2017, between John B. (Thad) Hill III and Calpine Corporation. †

31.1		Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		Certification of the Chief Executive Officer and the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. *

101.INS		XBRL Instance Document.

101.SCH		XBRL Taxonomy Extension Schema.

101.CAL		XBRL Taxonomy Extension Calculation Linkbase.

101.DEF		XBRL Taxonomy Extension Definition Linkbase.

101.LAB		XBRL Taxonomy Extension Label Linkbase.

101.PRE		XBRL Taxonomy Extension Presentation Linkbase.

_______________


*	Furnished herewith.


†	Management contract or compensatory plan, contract or arrangement.

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.