Calpine 10Q 2018 Q2 Quarterly report

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, 2018

		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 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: 105.2 shares of common stock, par value $0.001, were outstanding as of August 8, 2018, none of which were publicly traded.

CALPINE CORPORATION AND SUBSIDIARIES

REPORT ON FORM 10-Q

For the Quarter Ended June 30, 2018

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, 2018 and 2017	1
Consolidated Condensed Statements of Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2018 and 2017	2
Consolidated Condensed Balance Sheets at June 30, 2018 and December 31, 2017	3
Consolidated Condensed Statement of Stockholder’s Equity for the Six Months Ended June 30, 2018	4
Consolidated Condensed Statements of Cash Flows for the Six Months Ended June 30, 2018 and 2017	5
Notes to Consolidated Condensed Financial Statements	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Forward-Looking Information	33
Introduction and Overview	33
Results of Operations	35
Commodity Margin by Segment	39
Liquidity and Capital Resources	42
Risk Management and Commodity Accounting	46
New Accounting Standards and Disclosure Requirements	49
Item 3. Quantitative and Qualitative Disclosures About Market Risk	49
Item 4. Controls and Procedures	49

PART II – OTHER INFORMATION

Item 1. Legal Proceedings	50
Item 1A. Risk Factors	50
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	51
Item 3. Defaults Upon Senior Securities	51
Item 4. Mine Safety Disclosures	51
Item 5. Other Information	51
Item 6. Exhibits	52
Signatures	53

DEFINITIONS

As used in this report for the quarter ended June 30, 2018 (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

2017 Form 10-K		Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2017, filed with the SEC on February 16, 2018

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, repaid in a series of transactions on March 16, 2017, August 31, 2017, September 29, 2017, October 31, 2017 and November 30, 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 a series of transactions on November 7, 2012, December 2, 2013, December 4, 2014, February 3, 2015, December 7, 2015, December 19, 2016 and March 6, 2017

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		Collectively, the $625 million aggregate principal amount of 5.25% senior secured notes due 2026, issued May 31, 2016, and the $560 million aggregate principal amount of 5.25% senior secured notes due 2026, issued on December 15, 2017

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

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

Calpine Equity Incentive Plans		Collectively, the Director Plans and the Equity Plans, which provided 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, an indirect, wholly-owned subsidiary of Calpine, which was established as bankruptcy remote, special purpose subsidiary and is responsible for administering the Accounts Receivable Sales Program

Calpine Solutions		Calpine Energy Solutions, LLC, an indirect, wholly-owned subsidiary of Calpine, which is the third largest supplier of power to commercial and industrial retail customers in the United States with customers in 20 states, including presence in California, Texas, the Mid-Atlantic and the Northeast

CCFC		Calpine Construction Finance Company, L.P., an indirect, wholly-owned subsidiary of Calpine

CCFC Term Loan		The $1.0 billion first lien senior secured term loan entered into on December 15, 2017 among CCFC as borrower, the lenders party thereto, and Credit Suisse AG, Cayman Islands Branch, as administrative agent and collateral agent

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, repaid on December 15, 2017

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 14 states and the District of Columbia, including presence in California, Texas, the Mid-Atlantic and Northeast

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, ancillary retail expense and realized settlements from our marketing, hedging and optimization activities including natural gas and fuel oil transactions hedging future power sales

iii



ABBREVIATION		DEFINITION
Commodity Margin		Measure of profit reviewed by our chief operating decision maker that includes revenue recognized on our wholesale and retail power sales activity, electric capacity sales, REC sales, steam sales, realized settlements associated with our marketing, hedging, optimization and trading activities, fuel and purchased energy expenses, commodity transmission and transportation expenses, environmental compliance expenses and ancillary retail expense. Commodity Margin is a measure of segment profit or loss under FASB Accounting Standards Codification 280 used by our chief operating decision maker to make decisions about allocating resources to the relevant segments and assessing their performance

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 approximately $1.69 billion aggregate amount revolving credit facility credit agreement, dated as of December 10, 2010, as amended on June 27, 2013, July 30, 2014, February 8, 2016, December 1, 2016, September 15, 2017, October 20, 2017, March 8, 2018 and May 18, 2018 among Calpine Corporation, the Bank of Tokyo-Mitsubishi UFJ, Ltd., as successor administrative agent, MUFG Union Bank, N.A., as successor collateral agent, the lenders party thereto and the other parties thereto

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

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

Exchange Act		U.S. Securities Exchange Act of 1934, as amended

FASB		Financial Accounting Standards Board

FDIC		U.S. Federal Deposit Insurance Corporation

FERC		U.S. Federal Energy Regulatory Commission

First Lien Notes		Collectively, the 2022 First Lien Notes, the 2024 First Lien Notes and the 2026 First Lien Notes

First Lien Term Loans		Collectively, 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

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

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

Lyondell		LyondellBasell Industries N.V.



ABBREVIATION		DEFINITION
Market Heat Rate(s)		The regional power price divided by the corresponding regional natural gas price

Merger		Merger of Volt Merger Sub, Inc. with and into Calpine pursuant to the terms of the Merger Agreement, which was consummated on March 8, 2018

Merger Agreement		Agreement and Plan of Merger, dated, August 17, 2017, by and among Calpine Corporation, Volt Parent, LP and Volt Merger Sub, Inc.

MMBtu		Million Btu

MW		Megawatt(s), a measure of plant capacity

MWh		Megawatt hour(s), a measure of power produced, purchased or sold

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 retail energy supplier for homes and small businesses primarily concentrated in the Northeast U.S.

OCI		Other Comprehensive Income

OMEC		Otay Mesa Energy Center, LLC, an indirect, wholly owned subsidiary that owns the Otay Mesa Energy Center, a 608 MW power plant located in San Diego County, California

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

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

SDG&E		San Diego Gas & Electric Company

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

Short Term Credit Facility		The $300 million aggregate amount credit agreement, dated as of April 11, 2018, among Calpine Corporation, Morgan Stanley Senior Funding, Inc., as administrative agent, and the lenders party thereto



ABBREVIATION		DEFINITION
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:


•	The effect of the Merger on our customer relationships, operating results and business;


•	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 Loan 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 2017 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,
	2018			2017			2018			2017
	(in millions)
Operating revenues:
Commodity revenue	$	2,121		$	2,145		$	4,517		$	4,208
Mark-to-market gain (loss)	131			(66		)	(260		)	148
Other revenue	7			5			11			9
Operating revenues	2,259			2,084			4,268			4,365
Operating expenses:
Fuel and purchased energy expense:
Commodity expense	1,426			1,513			3,216			3,046
Mark-to-market (gain) loss	(57		)	16			(77		)	175
Fuel and purchased energy expense	1,369			1,529			3,139			3,221
Operating and maintenance expense	242			302			517			584
Depreciation and amortization expense	186			186			387			392
General and other administrative expense	31			40			91			80
Other operating expenses	19			20			56			40
Total operating expenses	1,847			2,077			4,190			4,317
(Gain) on sale of assets, net	—			—			—			(27		)
(Income) from unconsolidated subsidiaries	(5		)	(6		)	(11		)	(10		)
Income from operations	417			13			89			85
Interest expense	157			154			308			313
Debt extinguishment costs	—			1			—			25
Other (income) expense, net	62			7			69			9
Income (loss) before income taxes	198			(149		)	(288		)	(262		)
Income tax expense (benefit)	(158		)	63			(50		)	2
Net income (loss)	356			(212		)	(238		)	(264		)
Net income attributable to the noncontrolling interest	(4		)	(4		)	(8		)	(8		)
Net income (loss) attributable to Calpine	$	352		$	(216	)	$	(246	)	$	(272	)

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

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
	(in millions)
Net income (loss)	$	356		$	(212	)	$	(238	)	$	(264	)
Cash flow hedging activities:
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income (loss)	15			(26		)	63			(41		)
Reclassification adjustment for loss on cash flow hedges realized in net income (loss)	—			15			7			26
Foreign currency translation gain (loss)	(2		)	4			(8		)	6
Income tax benefit (expense)	7			(2		)	(4		)	(2		)
Other comprehensive income (loss)	20			(9		)	58			(11		)
Comprehensive income (loss)	376			(221		)	(180		)	(275		)
Comprehensive (income) attributable to the noncontrolling interest	(4		)	(4		)	(10		)	(8		)
Comprehensive income (loss) attributable to Calpine	$	372		$	(225	)	$	(190	)	$	(283	)

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,
	2018			2017
	(in millions, except share and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents ($45 and $39 attributable to VIEs)	$	201		$	284
Accounts receivable, net of allowance of $13 and $9	983			970
Inventories	560			498
Margin deposits and other prepaid expense	293			203
Restricted cash, current ($52 and $74 attributable to VIEs)	103			134
Derivative assets, current	238			174
Current assets held for sale	9			—
Other current assets	137			43
Total current assets	2,524			2,306
Property, plant and equipment, net ($3,976 and $4,048 attributable to VIEs)	12,586			12,724
Restricted cash, net of current portion ($29 and $24 attributable to VIEs)	30			25
Investments in unconsolidated subsidiaries	111			106
Long-term derivative assets	234			218
Goodwill	242			242
Intangible assets, net	454			512
Other assets ($35 and $22 attributable to VIEs)	294			320
Total assets	$	16,475		$	16,453
LIABILITIES & STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	763		$	777
Accrued interest payable	108			104
Debt, current portion ($461 and $175 attributable to VIEs)	512			225
Derivative liabilities, current	250			197
Other current liabilities	507			571
Total current liabilities	2,140			1,874
Debt, net of current portion ($1,884 and $2,238 attributable to VIEs)	11,095			11,180
Long-term derivative liabilities	188			119
Other long-term liabilities	230			213
Total liabilities	13,653			13,386

Commitments and contingencies (see Note 11)
Stockholder’s equity:
Common stock, $0.001 par value per share; authorized 5,000 and 1,400,000,000 shares, respectively, 105.2 and 361,677,891 shares issued, respectively, and 105.2 and 360,516,091 shares outstanding, respectively	—			—
Treasury stock, at cost, nil and 1,161,800 shares, respectively	—			(15		)
Additional paid-in capital	9,582			9,661
Accumulated deficit	(6,798		)	(6,552		)
Accumulated other comprehensive loss	(50		)	(106		)
Total Calpine stockholder’s equity	2,734			2,988
Noncontrolling interest	88			79
Total stockholder’s equity	2,822			3,067
Total liabilities and stockholder’s equity	$	16,475		$	16,453

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

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENT OF STOCKHOLDER’S EQUITY

(Unaudited)

(in millions)



	Common Stock		Treasury Stock			Additional Paid-In Capital			Accumulated Deficit			Accumulated Other Comprehensive Loss			Noncontrolling Interest			Total Stockholder’s Equity
Balance, December 31, 2017	$	—	$	(15	)	$	9,661		$	(6,552	)	$	(106	)	$	79		$	3,067
Treasury stock transactions	—		(7		)	—			—			—			—			(7		)
Stock-based compensation expense	—		—			41			—			—			—			41
Effects of the Merger	—		22			(120		)	—			—			—			(98		)
Contribution from the noncontrolling interest	—		—			—			—			—			2			2
Distribution to the noncontrolling interest	—		—			—			—			—			(3		)	(3		)
Net income (loss)	—		—			—			(246		)	—			8			(238		)
Other comprehensive income	—		—			—			—			56			2			58
Balance, June 30, 2018	$	—	$	—		$	9,582		$	(6,798	)	$	(50	)	$	88		$	2,822

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,
	2018			2017
	(in millions)
Cash flows from operating activities:
Net loss	$	(238	)	$	(264	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization⁽¹⁾	443			510
Debt extinguishment costs	—			25
Deferred income taxes	36			10
Gain on sale of assets, net	—			(27		)
Mark-to-market activity, net	180			26
(Income) from unconsolidated subsidiaries	(11		)	(10		)
Return on investments from unconsolidated subsidiaries	5			16
Stock-based compensation expense	57			20
Other	9			(6		)
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable	(8		)	(39		)
Derivative instruments, net	(74		)	(19		)
Other assets	(380		)	11
Accounts payable and accrued expenses	(22		)	(16		)
Other liabilities	59			27
Net cash provided by operating activities	56			264
Cash flows from investing activities:
Purchases of property, plant and equipment	(231		)	(187		)
Proceeds from sale of Osprey Energy Center	—			162
Purchase of North American Power, net of cash acquired	—			(111		)
Other	(3		)	30
Net cash used in investing activities	(234		)	(106		)
Cash flows from financing activities:
Borrowings under First Lien Term Loans	—			396
Repayment of CCFC Term Loan, CCFC Term Loans and First Lien Term Loans	(21		)	(173		)
Repurchase of First Lien Notes	—			(453		)
Borrowings under Corporate Revolving Facility	275			—
Repayments of project financing, notes payable and other	(66		)	(68		)
Distribution to noncontrolling interest holder	(3		)	(7		)
Financing costs	(12		)	(27		)
Stock repurchases	(79		)	—
Shares repurchased for tax withholding on stock-based awards	(7		)	(6		)
Other	(18		)	1
Net cash provided by (used in) financing activities	69			(337		)
Net decrease in cash, cash equivalents and restricted cash	(109		)	(179		)
Cash, cash equivalents and restricted cash, beginning of period	443			606
Cash, cash equivalents and restricted cash, end of period⁽²⁾	$	334		$	427

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,
	2018			2017
	(in millions)
Cash paid during the period for:
Interest, net of amounts capitalized	$	284		$	296
Income taxes	$	10		$	8

Supplemental disclosure of non-cash investing and financing activities:
Change in capital expenditures included in accounts payable	$	(14	)	$	(4	)
Purchase of King City Cogeneration Plant lease⁽³⁾	$	—		$	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)	Our cash and cash equivalents, restricted cash, current and restricted cash, net of current portion are stated as separate line items on our Consolidated Condensed Balance Sheets.


(3)	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 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, 2018

(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 and retail power markets in California, Texas and the Northeast and Mid-Atlantic regions 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 customers through the 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, 2017, included in our 2017 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.

Reclassifications — We have reclassified certain prior period amounts for comparative purposes. These reclassifications did not have a material effect on our financial condition, results of operations or cash flows.

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.

The table below represents the components of our restricted cash as of June 30, 2018 and December 31, 2017 (in millions):



	June 30, 2018						December 31, 2017
	Current		Non-Current		Total		Current		Non-Current		Total
Debt service	$	18	$	8	$	26	$	11	$	8	$	19
Construction/major maintenance	15		20		35		28		16		44
Security/project/insurance	67		—		67		92		—		92
Other	3		2		5		3		1		4
Total	$	103	$	30	$	133	$	134	$	25	$	159

Business Interruption Proceeds — We record business interruption insurance proceeds in operating revenues when they are realizable and recorded approximately $14 million and nil of business interruption proceeds during the three months ended June 30, 2018 and 2017, respectively, and $14 million and $1 million during the six months ended June 30, 2018 and 2017, respectively.

Property, Plant and Equipment, Net — At June 30, 2018 and December 31, 2017, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):



	June 30, 2018		December 31, 2017		Depreciable Lives
Buildings, machinery and equipment	$	16,440	$	16,506	1.5	–	46	Years
Geothermal properties	1,500		1,494		13	–	58	Years
Other	261		236		3	–	46	Years
	18,201		18,236
Less: Accumulated depreciation	6,590		6,383
	11,611		11,853
Land	118		117
Construction in progress	857		754
Property, plant and equipment, net	$	12,586	$	12,724

Depreciable Lives — During the first quarter of 2018, we reviewed our accounting policies related to depreciation associated with our estimates of useful lives related to our componentized balance of plant parts. As a result, the useful lives of our rotable parts are now generally estimated to range from 1.5 to 12 years. Our change in the method of depreciation for rotable parts is considered a change in accounting estimate and will result in changes to our depreciation expense prospectively. The change in estimate resulted in a decrease to our net income (loss) attributable to Calpine of $(4) million and $(43) million for the three and six months ended June 30, 2018, respectively.

Capitalized Interest — The total amount of interest capitalized was $7 million and $6 million during the three months ended June 30, 2018 and 2017, respectively, and $14 million and $13 million during the six months ended June 30, 2018 and 2017, respectively.

Goodwill — We have not recorded any impairment losses associated with our goodwill. During the first quarter of 2018, we altered the composition of our segments to report the results associated with our retail business as a separate segment. This change reflects the manner in which our segment information is presented internally to our chief operating decision maker associated with the strategic utilization of our retail business subsequent to the consummation of the Merger. Thus, beginning in the first quarter of 2018, our geographic reportable segments for our wholesale business are West (including geothermal), Texas and East (including Canada) and we have a separate reportable segment for our retail business. As our goodwill resulted from the acquisition of our retail business over the last several years, our goodwill balance of $242 million was allocated to our Retail segment in connection with the change in segment presentation.

New Accounting Standards and Disclosure Requirements

Revenue Recognition — On January 1, 2018, we adopted Accounting Standards Update 2014-09, “Revenue from Contracts with Customers” (“Topic 606”). The comprehensive new revenue recognition standard supersedes all pre-existing revenue recognition guidance. The core principle of Topic 606 is that a company will 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 the recognition of revenue from contracts with customers. We adopted the new revenue recognition standards under Topic 606 using the modified retrospective method and applied Topic 606 to those contracts which were not completed as of January 1, 2018. Results for reporting periods beginning after December 31, 2017 are presented under Topic 606, while prior period amounts continue to be reported in accordance with historical accounting standards. The adoption of Topic 606 resulted in no adjustment to our opening retained earnings as of January 1, 2018. There was no material effect to our revenues, results of operations or cash flows for the six months ending June 30, 2018 from the adoption of Topic 606 and we do not expect the new revenue standard to have a material effect on our results of operations in future periods. See Note 3 for additional disclosures required by Topic 606.

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. In January 2018, the FASB issued Accounting Standards Update 2018-01, “Land Easement Practical Expedient for Transition to Topic 842” that allows an entity to not evaluate existing and expired land easements that were not previously accounted for as leases upon adoption of Accounting Standards Update 2016-02. Any land easements entered into prospectively or modified after adoption should be evaluated to assess whether they meet the definition of a lease. In July 2018, the FASB issued Accounting Standards Update 2018-10 “Codification Improvements to Topic 842, Leases” which clarifies, corrects or consolidates authoritative guidance issued in Accounting Standards Update 2016-02 and is effective upon adoption of Accounting Standards Update 2016-02. Also in July 2018, the FASB issued Accounting Standards Update 2018-11 “Leases (Topic 842): Targeted Improvements” which provides a new transitional method to adopt the new leases standard and a practical expedient for lessors in applying the provisions of the new leases standard, which is effective upon adoption of Accounting Standards Update 2016-02. We expect to adopt the standards in the first quarter of 2019. We have completed our initial evaluation of the standards 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. We are considering electing certain practical expedients 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, and requires retrospective adoption. We adopted Accounting Standards Update 2016-15 in the first quarter of 2018 which resulted in the reclassification of cash payments for debt extinguishment costs from a cash outflow for operating activities to a cash outflow for financing activities. The adoption of this standard did not have a material effect on our financial condition, results of operations or cash flows.

Income Taxes — In October 2016, the FASB issued Accounting Standards Update 2016-16, “Intra-Entity Transfers of Assets Other than Inventory.” The standard requires an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs which differs from the current requirement that prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party. The standard is effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period and requires modified retrospective adoption. We adopted Accounting Standards Update 2016-16 in the first quarter of 2018 which did not have 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 retrospective adoption with early adoption permitted. We adopted Accounting Standards Update 2016-18 in the first quarter of 2018 which did not have a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard.

Derivatives and Hedging — In August 2017, the FASB issued Accounting Standards Update 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” The standard better aligns an entity’s hedging activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results in the financial statements. The standard will prospectively make hedge accounting easier to apply to hedging activities and also enhances disclosure requirements for how hedge transactions are reflected in the financial statements when hedge accounting is elected. The standard is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We are currently assessing the future effect this standard may have on our financial condition, results of operations or cash flows.


2.	Merger

Merger — On August 17, 2017, we entered into the Merger Agreement with Volt Parent, LP (“Volt Parent”) and Volt Merger Sub, Inc. (“Merger Sub”), a wholly-owned subsidiary of Volt Parent, pursuant to which Merger Sub merged with and into Calpine, with Calpine surviving the Merger as a subsidiary of Volt Parent. On March 8, 2018, we completed the Merger contemplated in the Merger Agreement.

At the effective time of the Merger, each share of Calpine common stock outstanding as of immediately prior to the effective time of the Merger (excluding certain shares as described in the Merger Agreement) ceased to be outstanding and was converted into the right to receive $15.25 per share in cash or approximately $5.6 billion in total. See Note 10 for a discussion of the treatment of the outstanding share-based awards to employees at the effective time of the Merger.

We recorded approximately $1 million and nil for the three months ended June 30, 2018 and 2017, respectively, and $32 million and nil for the six months ended June 30, 2018 and 2017, respectively, in Merger-related costs which was recorded in other operating expenses on our Consolidated Condensed Statements of Operations and primarily related to legal, investment banking and other professional fees associated with the Merger. We elected not to apply pushdown accounting in connection with the consummation of the Merger.


3.	Revenue from Contracts with Customers

Disaggregation of Revenues with Customers

The following tables represent a disaggregation of our revenue for the three and six months ended June 30, 2018 by reportable segment (in millions). See Note 13 for a description of our segments.



	Three Months Ended June 30, 2018
	Wholesale
	West		Texas		East		Retail		Elimination			Total
Third Party:
Energy & other products	$	176	$	326	$	120	$	451	$	—		$	1,073
Capacity	35		23		140		—		—			198
Revenues relating to physical or executory contracts – third party	$	211	$	349	$	260	$	451	$	—		$	1,271

Affiliate⁽¹⁾:	$	5	$	9	$	21	$	1	$	(36	)	$	—

Revenues relating to leases and derivative instruments⁽²⁾												$	988
Total operating revenues												$	2,259



	Six Months Ended June 30, 2018
	Wholesale
	West		Texas		East		Retail		Elimination			Total
Third Party:
Energy & other products	$	375	$	630	$	252	$	894	$	—		$	2,151
Capacity	54		49		289		—		—			392
Revenues relating to physical or executory contracts – third party	$	429	$	679	$	541	$	894	$	—		$	2,543

Affiliate⁽¹⁾:	$	13	$	13	$	42	$	2	$	(70	)	$	—

Revenues relating to leases and derivative instruments⁽²⁾												$	1,725
Total operating revenues												$	4,268

___________


(1)	Affiliate energy, other and capacity revenues reflect revenues on transactions between wholesale and retail affiliates excluding affiliate activity related to leases and derivative instruments. All such activity supports retail supply needs from the wholesale business and/or allows for collateral margin netting efficiencies at Calpine Corporation.

(2)

Revenues relating to contracts accounted for as leases and derivatives include energy and capacity revenues relating to PPAs that we are required to account for as operating leases and physical and financial commodity derivative contracts, primarily relating to power, natural gas and environmental products. Revenue related to derivative instruments includes revenue recorded in Commodity revenue and mark-to-market gain (loss) within our operating revenues on our Consolidated Condensed Statement of Operations.

For contracts that do not meet the requirements of a lease and either do not meet the definition of a derivative instrument or are exempt from derivative accounting, we have applied the new revenue recognition guidance beginning in the first quarter of 2018. Under the new guidance, the majority of our operating revenue continues to be recognized as the underlying commodity or service is delivered to our customers.

Energy and Other Products

Variable payments for power and steam that are based on generation, including retail sales of power, are recognized over time as the underlying commodity is generated and control is transferred to our customer upon transmission and delivery. Ancillary service revenues are also included within energy-related revenues and are recognized over time as the service is provided.

For our power, steam and ancillary service contracts, we have elected the practical expedient that allows us to recognize revenue in the amount to which we have the right to invoice to the extent we determine that we have a right to consideration in an amount that corresponds directly with the value provided to date. To the extent this practical expedient cannot be utilized, we will recognize revenue over time based on the quantity of the commodity delivered to the customer for power and steam sales and over time as the service is provided for our ancillary service sales.

Energy and other revenues also includes revenues generated from the sale of natural gas and environmental products, including RECs and are recognized at either a point in time or over time when control of the commodity has transferred. Revenues from the sale of RECs are primarily related to credits that are generated upon generation of renewable power from our Geysers Assets and are recognized over a period of time similar to the timing of the related energy sale. Revenues from sales of RECs or other environmental products that are not generated from our assets are recognized once all certifications have been completed and the credits are delivered to the customer at a point in time. Revenues from our natural gas sales are recognized at a point in time when delivery of the natural gas is provided. Revenues from natural gas and emission product sales are generally at the contracted transaction price, which may be fixed or index-based.

Capacity

Capacity revenues include fixed and variable capacity payments, which are based on generation volumes and include capacity payments received from RTO and ISO capacity auctions. For these contracts, we have elected the practical expedient that allows us to recognize revenue in the amount to which we have the right to invoice to the extent we determine that we have a right to consideration in an amount that corresponds directly with the value provided to date. To the extent this practical expedient cannot be utilized, we will recognize revenue over time as the service is being provided to the customer.

Performance Obligations and Contract Balances

Certain of our contracts have multiple performance obligations. The revenues associated with each individual performance obligation is based on the relative stand-alone sales price of each good or service or, when not available, is based on a cost incurred plus margin approach. For a significant portion of our contracts with multiple performance obligations, management has applied the practical expedient that results in recognition of revenue commensurate with the invoiced amount and no allocation is required as all performance obligations are transferred over the same period of time.

Certain of our contracts include volumetric optionality based on the customer’s needs. The transaction price within these contracts are based on a stand-alone sale price of the good or service being provided and revenue is recognized based on the customer’s usage. On a monthly basis, revenue is recognized based on estimated or actual usage by the customer at the transaction price. To the extent estimated usage is used in the recognition of revenue, revenues are adjusted for actual usage once known; however, this adjustment is not material to the revenues recognized. Generally, we have applied the practical expedient that allows us to recognize revenue based on the invoiced amount for these contracts.

Changes in estimates for our contracts are not material and revisions to estimates are recognized when the amounts can be reasonably estimated. Unbilled retail sales are based upon estimates of customer usage since the date of the last meter reading provided by the ISOs or electric distribution companies by applying the estimated revenue per KWh by customer class to the estimated number of KWhs delivered but not yet billed. Estimated amounts are adjusted when actual usage is known and billed. During the three and six months ended June 30, 2018, there were no significant changes to revenue amounts recognized in prior periods as a result of a change in estimates. Sales and other taxes we collect concurrent with revenue-producing activities are excluded from our operating revenues.

Billing requirements for our wholesale customers generally result in billing customers on a monthly basis in the month following the delivery of the good or service. Once billed, payment is generally required within 20 days resulting in payment for the delivery of the good or service in the month following delivery of the good or service. Billing requirements for our retail customers are generally once every 30 days and may result in billed amounts relating to our retail customers extending up to 60 days. Based on the terms of our agreements, payment is generally received at or shortly after delivery of the good or service.

Changes in accounts receivable relating to our customers is primarily due to the timing difference between payment and when the good or service is provided. During the three and six months ended June 30, 2018, there were no significant changes in accounts receivable other than normal billing and collection transactions and there were no material credit or impairment losses recognized relating to accounts receivable balances associated with contracts with customers.

When we receive consideration from a customer prior to transferring goods or services to the customer under the terms of a contract, we record deferred revenue, which represents a contract liability. Such deferred revenue typically results from consideration received prior to the transfer of goods and services relating to our capacity contracts and the sale of RECs that are not generated from our power plants. Based on the nature of these contracts and the timing between when consideration is received and delivery of the good or service is provided, these contracts do not contain any material financing elements.

At June 30, 2018 and December 31, 2017, deferred revenue balances relating to contracts with our customers were included in other current liabilities on our Consolidated Condensed Balance Sheets. We classify deferred revenue as current or long-term based on the timing of when we expect to recognize revenue. The balances outstanding at both June 30, 2018 and December 31, 2017 were not material. The revenue recognized during the three and six months ended June 30, 2018, relating to the deferred revenue balance at the beginning of the period was immaterial and resulted from our performance under the customer contracts. The change in deferred revenues during the three and six months ended June 30, 2018 was primarily due to the timing difference of when consideration was received and when the related good or service was transferred.

Contract Costs

For certain retail contracts, we incur third party incremental broker costs that are capitalized on our Consolidated Condensed Balance Sheets. Capitalized contract costs are amortized on a straight line basis over the term of the underlying sales

contract to the extent the term extends beyond one year. Contract costs associated with sales contracts that are less than one year are expensed as incurred under a practical expedient.

At both June 30, 2018 and December 31, 2017, the capitalized contract cost balance was not material. There were no impairment losses or changes in amortization during the three and six months ended June 30, 2018 and amortization of contract costs during the three and six months ended June 30, 2018 was immaterial.

Performance Obligations not yet Satisfied

As of June 30, 2018, we have entered into certain contracts with customers under which we have not yet completed our performance obligations which includes agreements for which we are providing power and capacity from our generating facilities for an aggregate transaction price of approximately $79 million that we expect to recognize as revenue through 2029. We also have revenues related to the sale of capacity through participation in various ISO capacity auctions estimated based upon cleared volumes and the sale of capacity to our customers of $374 million, $558 million, $494 million, $467 million and $200 million that will be recognized during the years ending December 31, 2018, 2019, 2020, 2021 and 2022, respectively, and $42 million thereafter. Revenues under these contracts will be recognized as we transfer control of the commodities to our customers.


4.	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, 2018. See Note 6 in our 2017 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 7,880 MW and 7,880 MW at June 30, 2018 and December 31, 2017, 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, 2018 and 2017.

OMEC — OMEC has a ten-year tolling agreement with SDG&E which commenced on October 3, 2009. Under a ground lease agreement, OMEC holds a put option to sell the Otay Mesa Energy Center for $280 million to SDG&E, which is exercisable through April 2019 and SDG&E holds a call option to purchase the Otay Mesa Energy Center for $377 million, which is exercisable through October 2018. If either option is exercised, the sale would occur upon the conclusion of the tolling agreement in October 2019. We have concluded that we are the primary beneficiary of OMEC as we believe the activity that has the most effect on the financial performance of OMEC is operations and maintenance which is controlled by us. As a result, we consolidate OMEC.

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, 2018 and December 31, 2017, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):



	Ownership Interest as of June 30, 2018	June 30, 2018		December 31, 2017
Greenfield LP	50%	$	96	$	92
Whitby	50%	8		6
Calpine Receivables	100%	7		8
Total investments in unconsolidated subsidiaries		$	111	$	106

Our risk of loss related to our investments in Greenfield LP and Whitby is limited to our investment balance. Our risk of loss related to our investment in Calpine Receivables is $56 million which consists of our notes receivable from Calpine Receivables at June 30, 2018 and our initial investment associated with Calpine Receivables. See Note 12 for further information associated with our related party activity with Calpine Receivables.

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, 2018 and December 31, 2017, Greenfield LP’s debt was approximately $244 million and $256 million, respectively, and based on our pro rata share of our investment in Greenfield LP, our share of such debt would be approximately $122 million and $128 million at June 30, 2018 and December 31, 2017, respectively.

Our equity interest in the net income from our investments in unconsolidated subsidiaries for the three and six months ended June 30, 2018 and 2017, is recorded in (income) from unconsolidated subsidiaries. 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,
	2018			2017			2018			2017
Greenfield LP	$	(2	)	$	(4	)	$	(4	)	$	(6	)
Whitby	(4		)	(2		)	(8		)	(4		)
Calpine Receivables	1			—			1			—
Total	$	(5	)	$	(6	)	$	(11	)	$	(10	)

Distributions from Greenfield LP were nil during each of the three and six months ended June 30, 2018 and 2017. Distributions from Whitby were $2 million and $5 million during the three and six months ended June 30, 2018, respectively, and $3 million and $16 million during the three and six months ended June 30, 2017, respectively. We did not have material distributions from our investment in Calpine Receivables for the three and six months ended June 30, 2018 and 2017.


5.	Debt

Our debt at June 30, 2018 and December 31, 2017, was as follows (in millions):



	June 30, 2018		December 31, 2017
Senior Unsecured Notes	$	3,420	$	3,417
First Lien Term Loans	2,986		2,995
First Lien Notes	2,397		2,396
Project financing, notes payable and other	1,440		1,498
CCFC Term Loan	978		984
Capital lease obligations	111		115
Corporate Revolving Facility	275		—
Subtotal	11,607		11,405
Less: Current maturities	512		225
Total long-term debt	$	11,095	$	11,180

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, increased to 5.7% for the six months ended June 30, 2018, from 5.4% for the same period in 2017.

Senior Unsecured Notes

The amounts outstanding under our Senior Unsecured Notes are summarized in the table below (in millions):



	June 30, 2018		December 31, 2017
2023 Senior Unsecured Notes	$	1,240	$	1,239
2024 Senior Unsecured Notes	644		644
2025 Senior Unsecured Notes	1,536		1,534
Total Senior Unsecured Notes	$	3,420	$	3,417

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, 2018		December 31, 2017
2019 First Lien Term Loan	$	389	$	389
2023 First Lien Term Loans	1,062		1,064
2024 First Lien Term Loan	1,535		1,542
Total First Lien Term Loans	$	2,986	$	2,995

First Lien Notes

The amounts outstanding under our senior secured First Lien Notes are summarized in the table below (in millions):



	June 30, 2018		December 31, 2017
2022 First Lien Notes	$	742	$	741
2024 First Lien Notes	486		485
2026 First Lien Notes	1,169		1,170
Total First Lien Notes	$	2,397	$	2,396

Corporate Revolving Facility and Other Letter of Credit Facilities

The table below represents amounts issued under our letter of credit facilities at June 30, 2018 and December 31, 2017 (in millions):



	June 30, 2018		December 31, 2017
Corporate Revolving Facility⁽¹⁾	$	800	$	629
CDHI	267		244
Various project financing facilities	217		196
Other corporate facilities⁽²⁾	96		—
Total	$	1,380	$	1,069

____________


(1)	The Corporate Revolving Facility represents our primary revolving facility.


(2)	During the second quarter of 2018, we executed two unsecured $50 million letter of credit facilities with third party financial institutions, each maturing on June 20, 2020. On July 26, 2018, we upsized one of the letter of credit facilities to $100 million.

On May 18, 2018, we amended our Corporate Revolving Facility to increase the capacity by approximately $220 million from $1.47 billion to approximately $1.69 billion. On March 8, 2018, we amended our Corporate Revolving Facility to increase the letter of credit facility from $1.15 billion to $1.3 billion and increased the Incremental Revolving Facilities (as defined in the credit agreement) amount to $500 million.

On September 15, 2017, we amended our Corporate Revolving Facility to, among other things, provide that the Merger does not constitute a “Change of Control” thereunder, effective upon consummation of the Merger. On October 20, 2017, we further amended our Corporate Revolving Facility to extend the maturity of most revolving commitments (totaling $1.3 billion in the aggregate) to March 8, 2023. Both amendments to the Corporate Revolving Facility became effective upon consummation of the Merger on March 8, 2018. See Note 2 for further information related to the Merger.

Short Term Credit Facility — On April 11, 2018, we entered into a credit agreement which allows us access to $300 million in aggregate available borrowings until August 31, 2018. Any cash draws from the Short Term Credit Facility are unsecured but will be converted to first lien senior secured term loans if not repaid within 21 days of the initial draw date. Any borrowings converted into first lien senior secured loans have a 364-day maturity from the initial draw date and will contain substantially similar interest rates, covenants, qualifications, exceptions and limitations as our 2019 First Lien Term Loan.

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, 2018 and December 31, 2017 (in millions):



	June 30, 2018				December 31, 2017
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Unsecured Notes	$	3,193	$	3,420	$	3,294	$	3,417
First Lien Term Loans	3,026		2,986		3,043		2,995
First Lien Notes	2,368		2,397		2,437		2,396
Project financing, notes payable and other⁽¹⁾	1,374		1,351		1,439		1,409
CCFC Term Loan	994		978		1,000		984
Corporate Revolving Facility	275		275		—		—
Total	$	11,230	$	11,407	$	11,213	$	11,201

____________


(1)	Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP.

Our Senior Unsecured Notes, First Lien Term Loans, First Lien Notes, CCFC Term Loan and Corporate Revolving Facility are categorized as level 2 within the fair value hierarchy. Our project financing, notes payable and other debt instruments are categorized as level 3 within the fair value hierarchy. We do not have any debt instruments with fair value measurements categorized as level 1 within the fair value hierarchy.


6.	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 an 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, including the Black-Scholes option-pricing model, 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.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement at period end. 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, 2018 and December 31, 2017, by level within the fair value hierarchy:



	Assets and Liabilities with Recurring Fair Value Measures as of June 30, 2018
	Level 1			Level 2			Level 3			Total
	(in millions)
Assets:
Cash equivalents⁽¹⁾	$	126		$	—		$	—		$	126
Commodity instruments:
Commodity exchange traded derivatives contracts	569			—			—			569
Commodity forward contracts⁽²⁾	—			642			244			886
Interest rate hedging instruments	—			76			—			76
Effect of netting and allocation of collateral⁽³⁾⁽⁴⁾	(569		)	(466		)	(24		)	(1,059		)
Total assets	$	126		$	252		$	220		$	598
Liabilities:
Commodity instruments:
Commodity exchange traded derivatives contracts	$	687		$	—		$	—		$	687
Commodity forward contracts⁽²⁾	—			821			112			933
Interest rate hedging instruments	—			16			—			16
Effect of netting and allocation of collateral⁽³⁾⁽⁴⁾	(687		)	(488		)	(23		)	(1,198		)
Total liabilities	$	—		$	349		$	89		$	438



	Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2017
	Level 1			Level 2			Level 3			Total
	(in millions)
Assets:
Cash equivalents⁽¹⁾	$	131		$	—		$	—		$	131
Commodity instruments:
Commodity exchange traded derivatives contracts	746			—			—			746
Commodity forward contracts⁽²⁾	—			327			265			592
Interest rate hedging instruments	—			29			—			29
Effect of netting and allocation of collateral⁽³⁾⁽⁴⁾	(746		)	(206		)	(23		)	(975		)
Total assets	$	131		$	150		$	242		$	523
Liabilities:
Commodity instruments:
Commodity exchange traded derivatives contracts	$	790		$	—		$	—		$	790
Commodity forward contracts⁽²⁾	—			461			68			529
Interest rate hedging instruments	—			34			—			34
Effect of netting and allocation of collateral⁽³⁾⁽⁴⁾	(790		)	(224		)	(23		)	(1,037		)
Total liabilities	$	—		$	271		$	45		$	316

___________


(1)	At June 30, 2018 and December 31, 2017, we had cash equivalents of $27 million and $21 million included in cash and cash equivalents and $99 million and $110 million included in restricted cash, respectively.


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

(3)

We offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation; therefore, amounts recognized for the right to reclaim, or the obligation to return, cash collateral are presented net with the corresponding derivative instrument fair values. See Note 7 for further discussion of our derivative instruments subject to master netting arrangements.

(4)

Cash collateral posted with (received from) counterparties allocated to level 1, level 2 and level 3 derivative instruments totaled $118 million, $22 million and $(1) million, respectively, at June 30, 2018. Cash collateral posted with (received from) counterparties allocated to level 1, level 2 and level 3 derivative instruments totaled $44 million, $18 million and nil, respectively, at December 31, 2017.

At June 30, 2018 and December 31, 2017, 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, 2018 and December 31, 2017:



	Quantitative Information about Level 3 Fair Value Measurements
	June 30, 2018
	Fair Value, Net Asset			Significant Unobservable
	(Liability)		Valuation Technique	Input	Range
	(in millions)
Power Contracts	$	89	Discounted cash flow	Market price (per MWh)	$	1.42		—	$158.04	/MWh
Power Congestion Products	$	7	Discounted cash flow	Market price (per MWh)	$	(7.52	)	—	$15.57	/MWh
Natural Gas Contracts	$	7	Discounted cash flow	Market price (per MMBtu)	$	1.10		—	$5.82	/MMBtu

	December 31, 2017
	Fair Value, Net Asset			Significant Unobservable
	(Liability)		Valuation Technique	Input	Range
	(in millions)
Power Contracts	$	149	Discounted cash flow	Market price (per MWh)	$	4.13		—	$119.20	/MWh
Power Congestion Products	$	11	Discounted cash flow	Market price (per MWh)	$	(10.54	)	—	$9.13	/MWh
Natural Gas Contracts	$	34	Discounted cash flow	Market price (per MMBtu)	$	1.62		—	$13.67	/MMBtu

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,
	2018			2017			2018			2017
Balance, beginning of period	$	129		$	350		$	197		$	416
Realized and mark-to-market gains (losses):
Included in net income (loss):
Included in operating revenues⁽¹⁾	31			28			(28		)	104
Included in fuel and purchased energy expense⁽²⁾	18			(14		)	15			1
Change in collateral	1			1			(1		)	(8		)
Purchases and settlements:
Purchases	5			3			9			3
Settlements	(42		)	(67		)	(53		)	(97		)
Transfers in and/or out of level 3⁽³⁾:
Transfers into level 3⁽⁴⁾	(1		)	2			(1		)	(3		)
Transfers out of level 3⁽⁵⁾	(10		)	—			(7		)	(113		)
Balance, end of period	$	131		$	303		$	131		$	303
Change in unrealized gains (losses) relating to instruments still held at end of period	$	49		$	14		$	(13	)	$	105

___________


(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, 2018 and 2017.


(4)	We had $(1) million in losses and $2 million in gains transferred out of level 2 into level 3 for the three months ended June 30, 2018 and 2017, respectively, and $(1) million and $(3) million in losses transferred out of level 2 into level 3 for the six months ended June 30, 2018 and 2017, respectively, due to changes in market liquidity in various power markets.


(5)	We had $10 million and nil in gains transferred out of level 3 into level 2 for the three months ended June 30, 2018 and 2017, respectively, and $7 million and $113 million in gains transferred out of level 3 into level 2 for the six months ended June 30, 2018 and 2017, respectively, due to changes in market liquidity in various power markets.


7.	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 or natural gas 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, 2018 and 2017.

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, 2018, the maximum length of time over which we were hedging using interest rate hedging instruments designated as cash flow hedges was 8 years.

As of June 30, 2018 and December 31, 2017, 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, 2018			December 31, 2017
Power (MWh)	(155		)	(119		)
Natural gas (MMBtu)	997			405
Environmental credits (Tonnes)	16			12
Interest rate hedging instruments	$	4,600		$	4,600

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, 2018, was $393 million for which we have posted collateral of $347 million by posting margin deposits, letters of credit 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 $4 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 currently apply hedge accounting to most of 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

During the third quarter of 2017, we elected to begin offsetting fair value amounts associated with our derivative instruments and related cash collateral and margin deposits on our Consolidated Condensed Balance Sheets that are executed with the same counterparty under master netting arrangements. 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 and/or receive cash collateral in support of our derivative instruments which may also be subject to a master netting arrangement with the same counterparty.

The following tables present the fair values of our derivative instruments and our net exposure after offsetting amounts subject to a master netting arrangement with the same counterparty to our derivative instruments recorded on our Consolidated Condensed Balance Sheets by location and hedge type at June 30, 2018 and December 31, 2017 (in millions):



	June 30, 2018
	Gross Amounts of Assets and (Liabilities)			Gross Amounts Offset on the Consolidated Condensed Balance Sheets			Net Amount Presented on the Consolidated Condensed Balance Sheets⁽¹⁾
Derivative assets:
Commodity exchange traded derivatives contracts	$	456		$	(456	)	$	—
Commodity forward contracts	631			(421		)	210
Interest rate hedging instruments	28			—			28
Total current derivative assets⁽²⁾	$	1,115		$	(877	)	$	238
Commodity exchange traded derivatives contracts	113			(113		)	—
Commodity forward contracts	255			(69		)	186
Interest rate hedging instruments	48			—			48
Total long-term derivative assets⁽²⁾	$	416		$	(182	)	$	234
Total derivative assets	$	1,531		$	(1,059	)	$	472

Derivative (liabilities):
Commodity exchange traded derivatives contracts	$	(514	)	$	514		$	—
Commodity forward contracts	(649		)	410			(239		)
Interest rate hedging instruments	(11		)	—			(11		)
Total current derivative (liabilities)⁽²⁾	$	(1,174	)	$	924		$	(250	)
Commodity exchange traded derivatives contracts	(173		)	173			—
Commodity forward contracts	(284		)	101			(183		)
Interest rate hedging instruments	(5		)	—			(5		)
Total long-term derivative (liabilities)⁽²⁾	$	(462	)	$	274		$	(188	)
Total derivative liabilities	$	(1,636	)	$	1,198		$	(438	)
Net derivative assets (liabilities)	$	(105	)	$	139		$	34



	December 31, 2017
	Gross Amounts of Assets and (Liabilities)			Gross Amounts Offset on the Consolidated Condensed Balance Sheets			Net Amount Presented on the Consolidated Condensed Balance Sheets⁽¹⁾
Derivative assets:
Commodity exchange traded derivatives contracts	$	672		$	(672	)	$	—
Commodity forward contracts	361			(194		)	167
Interest rate hedging instruments	7			—			7
Total current derivative assets⁽³⁾	$	1,040		$	(866	)	$	174
Commodity exchange traded derivatives contracts	74			(74		)	—
Commodity forward contracts	231			(32		)	199
Interest rate hedging instruments	22			(3		)	19
Total long-term derivative assets⁽³⁾	$	327		$	(109	)	$	218
Total derivative assets	$	1,367		$	(975	)	$	392

Derivative (liabilities):
Commodity exchange traded derivatives contracts	$	(702	)	$	702		$	—
Commodity forward contracts	(389		)	209			(180		)
Interest rate hedging instruments	(17		)	—			(17		)
Total current derivative (liabilities)⁽³⁾	$	(1,108	)	$	911		$	(197	)
Commodity exchange traded derivatives contracts	(88		)	88			—
Commodity forward contracts	(140		)	35			(105		)
Interest rate hedging instruments	(17		)	3			(14		)
Total long-term derivative (liabilities)⁽³⁾	$	(245	)	$	126		$	(119	)
Total derivative liabilities	$	(1,353	)	$	1,037		$	(316	)
Net derivative assets (liabilities)	$	14		$	62		$	76

____________


(1)	At June 30, 2018 and December 31, 2017, we had $227 million and $155 million of collateral under master netting arrangements that were not offset against our derivative instruments on the Consolidated Condensed Balance Sheets primarily related to initial margin requirements.


(2)	At June 30, 2018, current and long-term derivative assets are shown net of collateral of $(49) million and $(3) million, respectively, and current and long-term derivative liabilities are shown net of collateral of $96 million and $95 million, respectively.


(3)	At December 31, 2017, current and long-term derivative assets are shown net of collateral of $(8) million and $(2) million, respectively, and current and long-term derivative liabilities are shown net of collateral of $52 million and $20 million, respectively.



	June 30, 2018				December 31, 2017
	Fair Value of Derivative Assets		Fair Value of Derivative Liabilities		Fair Value of Derivative Assets		Fair Value of Derivative Liabilities
Derivatives designated as cash flow hedging instruments:
Interest rate hedging instruments	$	75	$	16	$	26	$	31
Total derivatives designated as cash flow hedging instruments	$	75	$	16	$	26	$	31

Derivatives not designated as hedging instruments:
Commodity instruments	$	396	$	422	$	366	$	285
Interest rate hedging instruments	1		—		—		—
Total derivatives not designated as hedging instruments	$	397	$	422	$	366	$	285
Total derivatives	$	472	$	438	$	392	$	316

Derivatives Included on Our Consolidated Condensed Statements of Operations

Changes in the fair values of our derivative instruments 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,
	2018		2017			2018			2017
Realized gain (loss)⁽¹⁾⁽²⁾
Commodity derivative instruments	$	69	$	44		$	66		$	73
Total realized gain (loss)	$	69	$	44		$	66		$	73

Mark-to-market gain (loss)⁽³⁾
Commodity derivative instruments	$	188	$	(82	)	$	(183	)	$	(27	)
Interest rate hedging instruments	1		1			3			1
Total mark-to-market gain (loss)	$	189	$	(81	)	$	(180	)	$	(26	)
Total activity, net	$	258	$	(37	)	$	(114	)	$	47

___________


(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,
	2018		2017			2018			2017
Realized and mark-to-market gain (loss)⁽¹⁾
Derivatives contracts included in operating revenues⁽²⁾⁽³⁾	$	183	$	(31	)	$	(176	)	$	192
Derivatives contracts included in fuel and purchased energy expense⁽²⁾⁽³⁾	74		(7		)	59			(146		)
Interest rate hedging instruments included in interest expense	1		1			3			1
Total activity, net	$	258	$	(37	)	$	(114	)	$	47

___________


(1)	In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.


(2)	Does not include the realized value associated with derivative instruments that settle through physical delivery.


(3)	Includes amortization of acquisition date fair value of financial derivative activity related to the acquisition of Champion Energy, Calpine Solutions and North American Power.

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⁾
	2018		2017			2018		2017			Affected Line Item on the Consolidated Condensed Statements of Operations
Interest rate hedging instruments⁽¹⁾⁽²⁾	$	15	$	(15	)	$	—	$	(11	)	Interest expense
Interest rate hedging instruments⁽¹⁾⁽²⁾	—		4			—		(4		)	Depreciation expense
Total	$	15	$	(11	)	$	—	$	(15	)



	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⁾
	2018		2017			2018			2017			Affected Line Item on the Consolidated Condensed Statements of Operations
Interest rate hedging instruments⁽¹⁾⁽²⁾	$	69	$	(19	)	$	(6	)	$	(22	)	Interest expense
Interest rate hedging instruments⁽¹⁾⁽²⁾	1		4			(1		)	(4		)	Depreciation expense
Total	$	70	$	(15	)	$	(7	)	$	(26	)

____________


(1)	We recorded $1 million in gains on hedge ineffectiveness related to our interest rate hedging instruments designated as cash flow hedges during each of the three and six months ended June 30, 2018. 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.


(2)	We recorded an income tax benefit of $7 million and income tax expense of $2 million for the three months ended June 30, 2018 and 2017, respectively, and income tax expense of $4 million and $2 million for the six months ended June 30, 2018 and 2017, respectively, in AOCI related to our cash flow hedging activities.


(3)	Cumulative cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $8 million and $72 million at June 30, 2018 and December 31, 2017, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $4 million and $6 million at June 30, 2018 and December 31, 2017, respectively.

We estimate that pre-tax net gains of $7 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.


8.	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, 2018 and December 31, 2017 (in millions):



	June 30, 2018		December 31, 2017
Margin deposits⁽¹⁾	$	407	$	221
Natural gas and power prepayments	32		23
Total margin deposits and natural gas and power prepayments with our counterparties⁽²⁾	$	439	$	244

Letters of credit issued	$	1,192	$	885
First priority liens under power and natural gas agreements	34		102
First priority liens under interest rate hedging instruments	17		31
Total letters of credit and first priority liens with our counterparties	$	1,243	$	1,018

Margin deposits posted with us by our counterparties⁽¹⁾⁽³⁾	$	41	$	4
Letters of credit posted with us by our counterparties	18		30
Total margin deposits and letters of credit posted with us by our counterparties	$	59	$	34

___________

(1)


(2)	At June 30, 2018 and December 31, 2017, $177 million and $64 million, respectively, were included in current and long-term derivative assets and liabilities, $254 million and $171 million, respectively, were included in margin deposits and other prepaid expense and $8 million and $9 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets.


(3)	At June 30, 2018 and December 31, 2017, $38 million and $2 million, respectively, were included in current and long-term derivative assets and liabilities and $3 million and $2 million, respectively, were 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.


9.	Income Taxes

Tax Cuts and Jobs Act (the “Act”)

On December 22, 2017, the Act was signed into law resulting in significant changes from previous tax law. Some of the more meaningful provisions which will affect us are:


•	a reduction in the U.S. federal corporate tax rate from 35% to 21%;


•	limitation on the deduction of certain interest expense;


•	full expense deduction for certain business capital expenditures;


•	limitation on the utilization of NOLs arising after December 31, 2017; and


•	a system of taxing foreign-sourced income from multinational corporations.

Because of the complexity of the new Global Intangible Low Taxed Income (“GILTI”) rules in the Act, we are continuing to evaluate this provision and its application under U.S. GAAP and have recorded a reasonable estimate of the effect of this

provision of the Act in our Consolidated Condensed Financial Statements. We have not made a policy decision regarding whether to record deferred taxes on GILTI.

In December 2017, the SEC issued Staff Accounting Bulletin No. 118 “Income Tax Accounting Implications of the Tax Cuts and Jobs Act” (“SAB 118”) which allows a company up to one year to finalize and record the tax effects of the Act. We are currently in the process of finalizing and quantifying the tax effects of the Act, but have recorded provisional amounts based on reasonable estimates for the measurement and accounting of certain effects of the Act in our Consolidated Condensed Financial Statements for the six months ended June 30, 2018. Under SAB 118, we will complete the required analyses and accounting during the year ended December 31, 2018.

Comprehensive Income — In February 2018, the FASB issued Accounting Standards Update 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.” The standard allows an entity to reclassify the income tax effects of the Act on items within AOCI to retained earnings and also requires additional disclosures. The standard is effective for fiscal years beginning after December 15, 2018, 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.

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,
	2018			2017			2018			2017
Income tax expense (benefit)	$	(158	)	$	63		$	(50	)	$	2
Effective tax rate	(81		)%	(41		)%	17		%	(1		)%

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, 2018 and 2017, 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. As a result of the Merger, an increase of approximately $57 million in the valuation allowance and a related charge to deferred tax expense was recorded during the six months ended June 30, 2018, due to our Canadian NOLs being substantially limited and not available to offset future income.

NOL Carryforwards — As of December 31, 2017, our NOL carryforwards consisted primarily of federal NOL carryforwards of approximately $6.6 billion, which expire between 2024 and 2037, and NOL carryforwards in 27 states and the District of Columbia totaling approximately $3.5 billion, which expire between 2018 and 2037. Substantially all of the federal and state NOLs are offset with a full valuation allowance. Certain of the state NOL carryforwards may be subject to limitations on their annual usage. As a result of the ownership change, our ability to utilize the NOL carryforwards will be limited. The reduction in our federal NOLs will be offset by an adjustment to the existing valuation allowance for an equal and offsetting amount. Additionally, our state NOLs available to offset future state income could materially decrease which would also be offset by an equal and offsetting adjustment to the existing valuation allowance. Given the offsetting adjustments to the existing valuation allowance, the ownership change is not expected to have a material adverse effect on our Consolidated Condensed Financial Statements.

As of December 31, 2017, we had approximately $659 million in foreign NOLs, which expire between 2026 and 2037, and the associated deferred tax asset of approximately $165 million is partially offset by a valuation allowance of $106 million. As a result of the Merger, an increase of approximately $57 million in the valuation allowance and a related charge to deferred tax expense occurred, which resulted in our Canadian NOLs being substantially limited and not available to offset future income.

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 were generated. Any adjustment of state or federal returns could result in a reduction of deferred tax assets rather than a cash payment of income taxes in tax jurisdictions where we have NOLs. We have concluded our U.S. federal income tax examination for the year ended December 31, 2015 with no adjustments. We are currently under various state income tax audits for various periods. Our Canadian subsidiaries are currently under 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, 2018, we had unrecognized tax benefits of $34 million. If recognized, $14 million of our unrecognized tax benefits could affect the annual effective tax rate and $20 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 $2 million for income tax matters at June 30, 2018. 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 $9 million in unrecognized tax benefits could occur within the next twelve months primarily related to federal tax issues.


10.	Stock-Based Compensation

Calpine Equity Incentive Plans

Prior to the effective date of the Merger on March 8, 2018, the Calpine Equity Incentive Plans provided for the issuance of equity awards to all non-union employees as well as the non-employee members of our Board of Directors. As a result of the Merger, the outstanding share-awards were treated as follows during the first quarter of 2018:


•	all restricted stock and restricted stock units were vested and canceled and the holders received a cash payment equal to a share price of $15.25 per share less any applicable withholding taxes;


•	all vested and unvested stock options were vested (in the case of unvested stock options) and canceled and the holders of the stock options received a cash payment equal to the intrinsic value based on a share price of $15.25 per share less any applicable withholding taxes; and


•	all Performance Share Units (“PSUs”), including the PSUs awarded in 2015 for the measurement period of January 1, 2015 through December 31, 2017, were vested and canceled in exchange for a cash payment with the payout value based on the greater of target value or actual performance over the truncated period using a share price of $15.25 per share less any applicable withholding taxes.

The amount of cash transferred to repurchase the share-based awards associated with our equity classified share-based awards totaled $79 million and was recorded to additional paid-in capital on our Consolidated Condensed Balance Sheet during the six months ended June 30, 2018. The amount of unrecognized compensation related to our equity classified share-based awards that we recognized in connection with the shortened service period associated with the completion of the Merger was $35 million for the six months ended June 30, 2018, which did not include any incremental compensation cost as the amount paid did not exceed the fair value of the equity classified share-based awards at the effective time of the Merger. The total stock-based compensation expense for our equity classified share-based awards was nil and $9 million for the three months ended June 30, 2018 and 2017, respectively, and $41 million and $17 million for the six months ended June 30, 2018 and 2017, respectively.

The amount of cash transferred to repurchase the share-based awards associated with our liability classified share-based awards totaled $25 million and was recorded to the associated liability in other long-term liabilities on our Consolidated Condensed Balance Sheet during the six months ended June 30, 2018. The amount of unrecognized compensation related to our liability classified share-based awards that we recognized in connection with the shortened implied service period associated with the completion of the Merger was $16 million for the six months ended June 30, 2018. The total stock-based compensation expense for our liability classified share-based awards was nil and $3 million for the three months ended June 30, 2018 and 2017, respectively, and $16 million and $3 million for the six months ended June 30, 2018 and 2017, respectively.

The total intrinsic value of our employee stock options exercised was nil for each of the three months ended June 30, 2018 and 2017 and $11 million and nil for the six months ended June 30, 2018 and 2017, respectively. We did not receive any material cash proceeds from the exercise of our employee stock options for the three and six months ended June 30, 2018 and 2017, respectively.

The total fair value of our restricted stock and restricted stock units that vested during the six months ended June 30, 2018 and 2017 was approximately $88 million and $19 million, respectively.


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 an adverse effect on our financial condition, results of operations or cash flows.

Former Stockholder Appraisal Rights — After the Merger, we received demands for appraisal pursuant to Section 262 of the Delaware General Corporate Law from certain dissenting stockholders. In May and July 2018, we entered into settlement agreements which resolved the appraisal claims with the stockholders that demanded a statutory right to appraisal of their shares. In July 2018, one such dissenting stockholder filed a petition for appraisal in the Delaware Chancery Court, captioned Marble Holdings LLC v. Calpine Corporation, C.A. No. 2018-0492. The case was subsequently dismissed pursuant to settlement. As a result of the settlement agreements, we recorded a charge of approximately $52 million to other (income) expense, net on our Consolidated Condensed Statement of Operation during the three months ended June 30, 2018.

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.

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, 2018, 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 16 of our 2017 Form 10-K.


12.	Related Party Transactions

We have entered into various agreements with related parties associated with the operation of our business. A description of these related party transactions is provided below (see Note 2 for a description of the Merger):

Calpine Receivables — Under the Accounts Receivable Sales Program, at June 30, 2018 and December 31, 2017, we had $228 million and $196 million, respectively, in trade accounts receivable outstanding that were sold to Calpine Receivables and $46 million and $26 million, respectively, in notes receivable from Calpine Receivables which were recorded on our Consolidated Condensed Balance Sheets. During the six months ended June 30, 2018 and 2017, we sold an aggregate of $1.1 billion and $1.1 billion, respectively, in trade accounts receivable and recorded $1.1 billion and $1.1 billion, respectively, in proceeds. For a further discussion of the Accounts Receivable Sales Program and Calpine Receivables, see Notes 3 and 6 in our 2017 Form 10-K.

Lyondell — We have a ground lease agreement with Houston Refining LP (“Houston Refining”), a subsidiary of Lyondell, for our Channel Energy Center site from which we sell power, capacity and steam to Houston Refining under a PPA. We purchase refinery gas and raw water from Houston Refining under a facilities services agreement. One of the entities which obtained an

ownership interest in Calpine through the Merger which closed on March 8, 2018, also has an ownership interest in Lyondell whereby they may significantly influence the management and operating policies of Lyondell. The terms of the PPA with Lyondell were negotiated prior to the Merger closing. We recorded $19 million and $38 million in Commodity revenue during the three and six months ended June 30, 2018, respectively, and $4 million and $6 million in Commodity expense during the three and six months ended June 30, 2018, respectively, associated with Lyondell. At June 30, 2018, the related party receivable and payable associated with Lyondell were immaterial.

Other — Following the Merger, we have identified other related party contracts for the sale of power, capacity and RECs which are entered into in the ordinary course of our business. Most of these contracts relate to the sale of commodities and capacity for varying tenors. The terms of most of these contracts were negotiated prior to the Merger. As of June 30, 2018, the related party receivables and payables associated with these transactions were immaterial.

At June 30, 2018, we have a payable totaling $11 million due to CPN Management, LP, our direct parent which holds 100% of our common stock, associated with a payment for a legal settlement made by CPN Management, LP on our behalf in May 2018. In July 2018, we repaid the related party payable.


13.	Segment Information

We assess our wholesale 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. During the first quarter of 2018, we altered the composition of our segments to report the results associated with our retail business as a separate segment. This change reflects the manner in which our segment information is presented internally to our chief operating decision maker associated with the strategic utilization of our retail business subsequent to the consummation of the Merger. Thus, beginning in the first quarter of 2018, our geographic reportable segments for our wholesale business are West (including geothermal), Texas and East (including Canada) and we have a separate reportable segment for our retail business. The tables below have been updated to present our segments on this revised basis for all periods. 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 segments.

Commodity Margin is a key operational measure of profit reviewed by our chief operating decision maker to assess the performance of our segments. The tables below show financial data for our segments (including a reconciliation of our Commodity Margin to income (loss) from operations by segment) for the periods indicated (in millions):



	Three Months Ended June 30, 2018
	Wholesale											Consolidation
	West			Texas		East			Retail			Elimination			Total
Total operating revenues⁽¹⁾	$	355		$	993	$	341		$	935		$	(365	)	$	2,259

Commodity Margin	$	241		$	151	$	225		$	77		$	—		$	694
Add: Mark-to-market commodity activity, net and other⁽²⁾	(23		)	301		(7		)	(67		)	(8		)	196
Less:
Operating and maintenance expense	80			65		65			41			(9		)	242
Depreciation and amortization expense	67			57		49			13			—			186
General and other administrative expense	5			13		8			5			—			31
Other operating expenses	8			3		8			—			—			19
(Income) from unconsolidated subsidiaries	—			—		(6		)	1			—			(5		)
Income (loss) from operations	58			314		94			(50		)	1			417
Interest expense															157
Other (income) expense, net															62
Income before income taxes															$	198



	Three Months Ended June 30, 2017
	Wholesale											Consolidation
	West			Texas			East			Retail		Elimination			Total
Total operating revenues⁽¹⁾	$	352		$	548		$	457		$	910	$	(183	)	$	2,084

Commodity Margin	$	214		$	136		$	190		$	107	$	—		$	647
Add: Mark-to-market commodity activity, net and other⁽²⁾	(26		)	(73		)	7			6		(6		)	(92		)
Less:
Operating and maintenance expense	106			94			73			36		(7		)	302
Depreciation and amortization expense	60			55			49			22		—			186
General and other administrative expense	8			20			8			4		—			40
Other operating expenses	8			3			8			—		1			20
(Income) from unconsolidated subsidiaries	—			—			(6		)	—		—			(6		)
Income (loss) from operations	6			(109		)	65			51		—			13
Interest expense															154
Debt extinguishment costs and other (income) expense, net															8
Loss before income taxes															$	(149	)



	Six Months Ended June 30, 2018
	Wholesale											Consolidation
	West			Texas			East			Retail		Elimination			Total
Total operating revenues⁽³⁾	$	835		$	1,133		$	955		$	1,873	$	(528	)	$	4,268

Commodity Margin	$	426		$	317		$	409		$	154	$	—		$	1,306
Add: Mark-to-market commodity activity, net and other⁽⁴⁾	(10		)	(246		)	33			61		(15		)	(177		)
Less:
Operating and maintenance expense	170			145			136			81		(15		)	517
Depreciation and amortization expense	134			133			94			26		—			387
General and other administrative expense	21			38			23			9		—			91
Other operating expenses	22			19			15			—		—			56
(Income) from unconsolidated subsidiaries	—			—			(12		)	1		—			(11		)
Income (loss) from operations	69			(264		)	186			98		—			89
Interest expense															308
Other (income) expense, net															69
Loss before income taxes															$	(288	)



	Six Months Ended June 30, 2017
	Wholesale											Consolidation
	West		Texas			East			Retail			Elimination			Total
Total operating revenues⁽³⁾	$	871	$	1,156		$	873		$	1,870		$	(405	)	$	4,365

Commodity Margin	$	417	$	261		$	332		$	195		$	—		$	1,205
Add: Mark-to-market commodity activity, net and other⁽⁴⁾	54		(30		)	21			(92		)	(14		)	(61		)
Less:
Operating and maintenance expense	197		175			154			72			(14		)	584
Depreciation and amortization expense	147		109			97			39			—			392
General and other administrative expense	20		36			15			9			—			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	90		(95		)	107			(17		)	—			85
Interest expense															313
Debt extinguishment costs and other (income) expense, net															34
Loss before income taxes															$	(262	)

_________

(1)

Includes intersegment revenues of $70 million and $47 million in the West, $276 million and $54 million in Texas, $18 million and $81 million in the East and $1 million and $1 million in Retail for the three months ended June 30, 2018 and 2017, respectively. Intersegment revenues for sales between wholesale and retail operations are executed to manage supply needs for our retail operations from our wholesale fleet or to facilitate margin collateral netting at Calpine Corporation.


(2)	Includes $(19) million and $(24) million of lease levelization and $25 million and $44 million of amortization expense for the three months ended June 30, 2018 and 2017, respectively.

(3)

Includes intersegment revenues of $184 million and $108 million in the West, $209 million and $126 million in Texas, $133 million and $169 million in the East and $2 million and $2 million in Retail for the six months ended June 30, 2018 and 2017, respectively. Intersegment revenues for sales between wholesale and retail operations are executed to manage supply needs for our retail operations from our wholesale fleet or to facilitate margin collateral netting at Calpine Corporation.


(4)	Includes $(35) million and $(46) million of lease levelization and $53 million and $104 million of amortization expense for the six months ended June 30, 2018 and 2017, respectively.


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

Forward-Looking Information

This Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our accompanying Consolidated Condensed Financial Statements and related Notes. See the cautionary statement regarding forward-looking statements at the beginning of this Report for a description of important factors that could cause actual results to differ from expected results.

Introduction and Overview

Our wholesale power plant portfolio, including partnership interests, consists of 79 power plants, including one under construction, with an aggregate current generation capacity of 25,850 MW and 828 MW under construction. Our fleet, including projects under construction, consists of 64 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 wholesale geographic segments have an aggregate generation capacity of 7,425 MW in the West, 9,086 MW in Texas and 9,339 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 24 states in the U.S. and in Canada and Mexico.

Merger

On August 17, 2017, we entered into the Merger Agreement with Volt Parent, LP (“Volt Parent”) and Volt Merger Sub, Inc. (“Merger Sub”), a wholly-owned subsidiary of Volt Parent, pursuant to which Merger Sub merged with and into Calpine, with Calpine surviving the Merger as a subsidiary of Volt Parent. On March 8, 2018, we completed the Merger contemplated in the Merger Agreement.

Governmental and Regulatory Matters

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 2017 Form 10-K.

U.S. Department of Energy

The U.S. Department of Energy (“DOE”) has initiated a formal inter-agency review process to consider possible action under Section 202(c) of the Federal Power Act and the Defense Production Act to ensure the continued operation of certain fuel-secure electric generation capacity, consisting of nuclear and coal-fired power plants across the U.S. facing retirement. The review process is being conducted under the guise that these uneconomic power resources are needed to provide reliability and resiliency to the U.S. power system as they are better equipped to withstand extreme weather events and cyber attacks. We and others are advocating against any such action and believe if such actions are permitted to be implemented, prices could be negatively affected. We cannot predict what action, if any, the DOE may take in response to this request, nor can we predict what effect such action would have on our business.

PJM

On June 29, 2018, the FERC issued a decision finding PJM’s current tariff to be unjust and unreasonable due to the price-suppressive effects of out-of-market compensation provided to certain generation resources by states within the PJM market. However, the FERC rejected both proposals to address the issue submitted by PJM and instead opted for an expedited paper hearing with a final decision expected by January 2019. In its decision, the FERC outlined a Fixed Resource Requirement Alternative (“FRR Alternative”) in which power resources receiving out-of-market subsidies could choose to be removed from the PJM market along with a commensurate amount of load. We do not support the proposed FRR Alternative, and we believe a resolution can be reached which would both accommodate the state actions and provide the necessary market adjustments which would protect the PJM capacity market. We intend to actively participate in the paper hearing currently underway. As this issue is unresolved, we cannot predict the ultimate effect on our financial condition, results of operations or cash flows.

RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED JUNE 30, 2018 AND 2017

Below are our results of operations for the three months ended June 30, 2018 as compared to the same period in 2017 (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.



	2018			2017			Change			% Change
Operating revenues:
Commodity revenue	$	2,121		$	2,145		$	(24	)	(1	)
Mark-to-market gain (loss)	131			(66		)	197			#
Other revenue	7			5			2			40
Operating revenues	2,259			2,084			175			8
Operating expenses:
Fuel and purchased energy expense:
Commodity expense	1,426			1,513			87			6
Mark-to-market (gain) loss	(57		)	16			73			#
Fuel and purchased energy expense	1,369			1,529			160			10
Operating and maintenance expense	242			302			60			20
Depreciation and amortization expense	186			186			—			—
General and other administrative expense	31			40			9			23
Other operating expenses	19			20			1			5
Total operating expenses	1,847			2,077			230			11
(Income) from unconsolidated subsidiaries	(5		)	(6		)	(1		)	(17	)
Income from operations	417			13			404			#
Interest expense	157			154			(3		)	(2	)
Debt extinguishment costs	—			1			1			#
Other (income) expense, net	62			7			(55		)	#
Income (loss) before income taxes	198			(149		)	347			#
Income tax expense (benefit)	(158		)	63			221			#
Net income (loss)	356			(212		)	568			#
Net income attributable to the noncontrolling interest	(4		)	(4		)	—			—
Net income (loss) attributable to Calpine	$	352		$	(216	)	$	568		#



	2018		2017		Change		% Change
Operating Performance Metrics:
MWh generated (in thousands)⁽¹⁾⁽²⁾	21,451		21,849		(398	)	(2	)
Average availability⁽²⁾	80.8	%	82.2	%	(1.4	)%	(2	)
Average total MW in operation⁽¹⁾	25,153		25,128		25		—
Average capacity factor, excluding peakers	41.4	%	44.4	%	(3.0	)%	(7	)
Steam Adjusted Heat Rate⁽²⁾	7,387		7,318		(69	)	(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.

We evaluate our Commodity revenue and Commodity expense on a collective basis because the price of power and natural gas tend to move together as 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 by Segment.”

Commodity revenue, net of Commodity expense, increased $63 million for the three months ended June 30, 2018, compared to the same period in 2017, primarily due to (favorable variances are shown without brackets while unfavorable variances are shown with brackets):



(in millions)
$	43	Higher regulatory capacity revenue in our East segment
4		Higher energy margins for our wholesale business associated with higher contribution from hedges, the positive effect of new PPAs in the West and higher market Spark Spreads in Texas. The increase was partially offset by lower energy margins associated with our Retail segment primarily in Texas and the Northeast
16		Period-over-period change in contract amortization, lease levelization relating to tolling contracts and other⁽¹⁾
$	63

__________


(1)	Commodity Margin excludes amortization expense related to contracts recorded at fair value, non-cash GAAP-related adjustments to levelize revenues from tolling agreements, Commodity revenue and Commodity expense attributable to the noncontrolling interest and other unusual items or non-recurring items.

Mark-to-market gain/loss, net from hedging our future generation, fuel supply requirements and retail activities had a favorable variance of $270 million primarily driven by the decrease in forward commodity prices in ERCOT during the quarter ended June 30, 2018.

Our normal, recurring operating and maintenance expense decreased by $6 million for the three months ended June 30, 2018 compared to the same period in 2017, after excluding the effect of a $56 million decrease in major maintenance expense resulting from a decrease in plant outages and changes in our capitalization accounting policy partially offset by a $2 million increase in variable operating costs associated with restarting of our Sutter Energy Center during 2018.

General and other administrative expense decreased by $9 million for the three months ended June 30, 2018 compared to the same period in 2017 primarily related to a decrease in stock-based compensation expense associated with the consummation of the Merger in March 2018.

Other (income) expense, net increased by $55 million for the three months ended June 30, 2018 compared to the same period in 2017 primarily due to legal settlements with former stockholders who exercised their appraisal rights which were recorded during the three months ended June 30, 2018. See Note 11 of the Notes to Consolidated Condensed Financial Statements for further information related to the legal settlements with former stockholders.

During the three months ended June 30, 2018, we recorded an income tax benefit of $158 million compared to an income tax expense of $63 million for the three months ended June 30, 2017. The favorable period-over-period change primarily resulted from changes in the effect of applying the intraperiod tax allocation rules to our results of operations and related tax expense.

RESULTS OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2018 AND 2017

Below are our results of operations for the six months ended June 30, 2018 as compared to the same period in 2017 (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.



	2018			2017			Change			% Change
Operating revenues:
Commodity revenue	$	4,517		$	4,208		$	309		7
Mark-to-market gain (loss)	(260		)	148			(408		)	#
Other revenue	11			9			2			22
Operating revenues	4,268			4,365			(97		)	(2	)
Operating expenses:
Fuel and purchased energy expense:
Commodity expense	3,216			3,046			(170		)	(6	)
Mark-to-market (gain) loss	(77		)	175			252			#
Fuel and purchased energy expense	3,139			3,221			82			3
Operating and maintenance expense	517			584			67			11
Depreciation and amortization expense	387			392			5			1
General and other administrative expense	91			80			(11		)	(14	)
Other operating expenses	56			40			(16		)	(40	)
Total operating expenses	4,190			4,317			127			3
(Gain) on sale of assets, net	—			(27		)	(27		)	#
(Income) from unconsolidated subsidiaries	(11		)	(10		)	1			10
Income from operations	89			85			4			5
Interest expense	308			313			5			2
Debt extinguishment costs	—			25			25			#
Other (income) expense, net	69			9			(60		)	#
Loss before income taxes	(288		)	(262		)	(26		)	(10	)
Income tax expense (benefit)	(50		)	2			52			#
Net loss	(238		)	(264		)	26			10
Net income attributable to the noncontrolling interest	(8		)	(8		)	—			—
Net loss attributable to Calpine	$	(246	)	$	(272	)	$	26		10



	2018		2017		Change		% Change
Operating Performance Metrics:
MWh generated (in thousands)⁽¹⁾⁽²⁾	42,251		42,673		(422	)	(1	)
Average availability⁽²⁾	84.2	%	84.8	%	(0.6	)%	(1	)
Average total MW in operation⁽¹⁾	25,170		25,202		(32	)	—
Average capacity factor, excluding peakers	41.7	%	43.6	%	(1.9	)%	(4	)
Steam Adjusted Heat Rate⁽²⁾	7,356		7,331		(25	)	—

__________


#	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, increased $139 million for the six months ended June 30, 2018, compared to the same period in 2017, primarily due to (favorable variances are shown without brackets while unfavorable variances are shown with brackets):



(in millions)
$	82		Higher regulatory capacity revenue in our East segment
31			Higher revenue associated with the sale of environmental credits in our Texas segment during the first quarter of 2018 with no similar activity in the same period in 2017
(12		)	Lower energy margins associated with our Retail segment resulting from higher purchase energy and capacity supply costs in Texas and the Northeast. The decrease was partially offset by positive value captured by our wholesale business associated with colder weather in the Northeast during January 2018, higher market Spark Spreads in Texas, the execution of new PPAs in the West and a gain associated with the cancellation of a PPA recorded during the first quarter of 2018
38			Period-over-period change in contract amortization, lease levelization relating to tolling contracts and other⁽¹⁾
$	139

__________


(1)	Commodity Margin excludes amortization expense related to contracts recorded at fair value, non-cash GAAP-related adjustments to levelize revenues from tolling agreements, Commodity revenue and Commodity expense attributable to the noncontrolling interest and other unusual items or non-recurring items.

Mark-to-market gain/loss, net from hedging our future generation, fuel supply requirements and retail activities had an unfavorable variance of $156 million primarily driven by the increase in forward commodity prices and corresponding Market Heat Rate expansion in ERCOT during the six months ended June 30, 2018.

Our normal, recurring operating and maintenance expense decreased by $8 million for the six months ended June 30, 2018 compared to the same period in 2017, after excluding the effect of a $23 million increase related to the acceleration of unrecognized compensation expense for share-based equity awards and performance share units as a result of the Merger in March 2018, a $3 million increase in variable operating costs associated with restarting of our Sutter Energy Center during 2018 and a $85 million decrease in major maintenance expense resulting from a decrease in plant outages and changes in our capitalization accounting policy.

General and other administrative expense increased by $11 million for the six months ended June 30, 2018 compared to the same period in 2017 primarily due to the acceleration of the unamortized expense for the share-based equity awards and performance share units resulting from the change in control associated with the consummation of the Merger in March 2018.

Other operating expenses increased by $16 million for the six months ended June 30, 2018 compared to the same period in 2017 primarily due to Merger-related costs associated with legal, investment banking and other professional fees associated with the Merger partially offset by the write-off of unamortized balances associated with the termination of a PPA during the first quarter of 2018. See Note 2 of the Notes to Consolidated Condensed Financial Statements for further information related to the Merger.

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, consisted of $21 million in connection with the redemption of our 2023 First Lien Notes in March 2017, which is comprised of $18 million in prepayment penalty and $3 million from the write-off of debt issuance costs, as well as $3 million in debt extinguishment costs from the write-off of debt issuance costs associated with the $150 million partial repayment of our 2017 First Lien Term Loan in March 2017.

Other (income) expense, net increased by $60 million for the six months ended June 30, 2018 compared to the same period in 2017 primarily due to legal settlements with former stockholders who exercised their appraisal rights which were recorded during the six months ended June 30, 2018. See Note 11 of the Notes to Consolidated Condensed Financial Statements for further information related to the legal settlements with former stockholders.

During the six months ended June 30, 2018, we recorded an income tax benefit of $50 million compared to an income tax expense of $2 million for the six months ended June 30, 2017. The favorable period-over-period change primarily resulted from changes in the effect of applying the intraperiod tax allocation rules to our results of operations and related tax expense.

COMMODITY MARGIN BY SEGMENT

We use Commodity Margin 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 less costs from our fuel and purchased energy expenses, commodity transmission and transportation expenses, environmental compliance expenses and ancillary retail expense. We believe that Commodity Margin is a useful tool for assessing the performance of our core operations and is a key operational measure of profit reviewed by our chief operating decision maker. See Note 13 of the Notes to Consolidated Condensed Financial Statements for a reconciliation of Commodity Margin to income (loss) from operations by segment.

During the first quarter of 2018, we altered the composition of our segments to report the results associated with our retail business as a separate segment. This change reflects the manner in which our segment information is presented internally to our chief operating decision maker associated with the strategic utilization of our retail business subsequent to the consummation of the Merger. Thus, beginning in the first quarter of 2018, our geographic reportable segments for our wholesale business are West (including geothermal), Texas and East (including Canada) and we have a separate reportable segment for our retail business. The tables below have been updated to present our segments on this revised basis for all periods.

Commodity Margin by Segment for the Three Months Ended June 30, 2018 and 2017

The following tables show our Commodity Margin by segment and related operating performance metrics by regional segment for our wholesale business for the three months ended June 30, 2018 and 2017 (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 regional 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:	2018			2017			Change			% Change
Commodity Margin (in millions)	$	241		$	214		$	27		13
Commodity Margin per MWh generated	$	61.29		$	59.07		$	2.22		4

MWh generated (in thousands)	3,932			3,623			309			9
Average availability	78.3		%	72.5		%	5.8		%	8
Average total MW in operation	7,425			7,425			—			—
Average capacity factor, excluding peakers	25.6		%	23.8		%	1.8		%	8
Steam Adjusted Heat Rate	7,533			7,547			14			—

West — Commodity Margin in our West segment increased by $27 million, or 13%, for the three months ended June 30, 2018 compared to the three months ended June 30, 2017, primarily resulting from the positive effect of new PPAs associated with our Metcalf and Sutter Energy Centers which became effective in 2018.



Texas:	2018			2017			Change			% Change
Commodity Margin (in millions)	$	151		$	136		$	15		11
Commodity Margin per MWh generated	$	13.11		$	12.58		$	0.53		4

MWh generated (in thousands)	11,519			10,809			710			7
Average availability	86.2		%	84.2		%	2.0		%	2
Average total MW in operation	8,850			8,791			59			1
Average capacity factor, excluding peakers	55.7		%	56.3		%	(0.6		)%	(1	)
Steam Adjusted Heat Rate	7,124			7,058			(66		)	(1	)

Texas — Commodity Margin in our Texas segment increased by $15 million, or 11%, for the three months ended June 30, 2018 compared to the three months ended June 30, 2017, primarily due to higher market Spark Spreads predominately in May 2018 and higher contribution from hedges in the second quarter of 2018 compared to the same period in 2017.



East:	2018			2017			Change			% Change
Commodity Margin (in millions)	$	225		$	190		$	35		18
Commodity Margin per MWh generated	$	37.50		$	25.62		$	11.88		46

MWh generated (in thousands)	6,000			7,417			(1,417		)	(19	)
Average availability	77.1		%	87.4		%	(10.3		)%	(12	)
Average total MW in operation	8,878			8,912			(34		)	—
Average capacity factor, excluding peakers	39.0		%	50.3		%	(11.3		)%	(22	)
Steam Adjusted Heat Rate	7,832			7,646			(186		)	(2	)

East — Commodity Margin in our East segment increased by $35 million, or 18%, for the three months ended June 30, 2018 compared to the three months ended June 30, 2017, primarily due to higher regulatory capacity revenue in PJM and ISO-NE. The increase in Commodity Margin was partially offset by lower contribution from hedges during the second quarter of 2018 compared to the same period in 2017.



Retail:	2018		2017		Change			% Change
Commodity Margin (in millions)	$	77	$	107	$	(30	)	(28	)

Retail — Commodity Margin in our retail segment decreased by $30 million, or 28%, for the three months ended June 30, 2018 compared to the three months ended June 30, 2017, primarily due to higher power supply costs in Texas in the second quarter of 2018 compared to the same period in 2017.

Commodity Margin by Segment for the Six Months Ended June 30, 2018 and 2017

The following tables show our Commodity Margin by segment and related operating performance metrics by regional segment for our wholesale business for the six months ended June 30, 2018 and 2017 (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 regional 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:	2018			2017			Change			% Change
Commodity Margin (in millions)	$	426		$	417		$	9		2
Commodity Margin per MWh generated	$	47.12		$	45.97		$	1.15		3

MWh generated (in thousands)	9,041			9,072			(31		)	—
Average availability	82.6		%	79.4		%	3.2		%	4
Average total MW in operation	7,425			7,425			—			—
Average capacity factor, excluding peakers	29.5		%	30.0		%	(0.5		)%	(2	)
Steam Adjusted Heat Rate	7,345			7,410			65			1

West — Commodity Margin in our West segment increased by $9 million, or 2%, for the six months ended June 30, 2018 compared to the six months ended June 30, 2017, primarily resulting from higher market Spark Spreads and the positive effect of new PPAs associated with our Metcalf and Sutter Energy Centers which became effective in 2018. The increase in Commodity Margin was partially offset by lower contribution from hedges.



Texas:	2018			2017			Change			% Change
Commodity Margin (in millions)	$	317		$	261		$	56		21
Commodity Margin per MWh generated	$	14.98		$	12.92		$	2.06		16

MWh generated (in thousands)	21,166			20,207			959			5
Average availability	85.7		%	85.6		%	0.1		%	—
Average total MW in operation	8,850			8,858			(8		)	—
Average capacity factor, excluding peakers	52.5		%	52.5		%	—		%	—
Steam Adjusted Heat Rate	7,121			7,086			(35		)	—

Texas — Commodity Margin in our Texas segment increased by $56 million, or 21%, for the six months ended June 30, 2018 compared to the six months ended June 30, 2017, primarily due to higher market Spark Spreads predominately in January and May 2018 and higher revenue associated with the sale of environmental credits in the first quarter of 2018 with no similar activity in the same period in 2017.



East:	2018			2017			Change			% Change
Commodity Margin (in millions)	$	409		$	332		$	77		23
Commodity Margin per MWh generated	$	33.96		$	24.79		$	9.17		37

MWh generated (in thousands)	12,044			13,394			(1,350		)	(10	)
Average availability	83.9		%	88.0		%	(4.1		)%	(5	)
Average total MW in operation	8,895			8,919			(24		)	—
Average capacity factor, excluding peakers	40.1		%	45.9		%	(5.8		)%	(13	)
Steam Adjusted Heat Rate	7,780			7,678			(102		)	(1	)

East — Commodity Margin in our East segment increased by $77 million, or 23%, for the six months ended June 30, 2018 compared to the six months ended June 30, 2017, primarily due to higher regulatory capacity revenue in PJM and ISO-NE and the positive effect of colder than normal weather resulting in higher power prices in January 2018 compared to the same period in 2017. Commodity Margin also increased resulting from a gain associated with the cancellation of a PPA recorded during the first quarter of 2018. The increase in Commodity Margin was partially offset by lower contribution from hedges during the six months ended June 30, 2018, compared to the six months ended June 30, 2017.



Retail:	2018		2017		Change			% Change
Commodity Margin (in millions)	$	154	$	195	$	(41	)	(21	)

Retail — Commodity Margin in our retail segment decreased by $41 million, or 21%, for the six months ended June 30, 2018 compared to the six months ended June 30, 2017, primarily due to colder than normal weather in January 2018 and higher purchased energy and capacity supply costs in Texas and the Northeast during the six months ended June 30, 2018 compared to the same period in 2017.

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, 2018 and December 31, 2017 (in millions):



	June 30, 2018		December 31, 2017
Cash and cash equivalents, corporate⁽¹⁾	$	139	$	228
Cash and cash equivalents, non-corporate	62		56
Total cash and cash equivalents	201		284
Restricted cash	133		159
Corporate Revolving Facility availability⁽²⁾	614		1,161
CDHI letter of credit facility availability	33		56
Short Term Credit Facility availability⁽³⁾	300		—
Other facilities availability⁽⁴⁾	4		—
Total current liquidity availability⁽⁵⁾	$	1,285	$	1,660

____________


(1)	Includes $41 million and $4 million of margin deposits posted with us by our counterparties at June 30, 2018 and December 31, 2017, respectively. See Note 8 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. The availability under our Corporate Revolving Facility decreased primarily due to payments associated with the consummation of the Merger on March 8, 2018 and an increase in collateral requirements during the six months ended June 30, 2018 as discussed below. On May 18, 2018, we amended our Corporate Revolving Facility to increase the capacity by approximately $220 million from $1.47 billion to approximately $1.69 billion.


(3)	On April 11, 2018, we executed our Short Term Credit Facility which allows us unrestricted access to an additional $300 million in liquidity until August 31, 2018. See Note 5 of the Notes to Consolidated Condensed Financial Statements for further information related to our Short Term Credit Facility.


(4)	During the second quarter of 2018, we executed two unsecured $50 million letter of credit facilities with third party financial institutions, each maturing on June 20, 2020. On July 26, 2018, we upsized one of the letter of credit facilities to $100 million.

(5)

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.

In addition to funding our operations, our principal uses of liquidity and capital resources include, but are not limited to, collateral requirements to support our commercial hedging and optimization activities. During the first half of 2018, forward wholesale power prices in ERCOT improved meaningfully, requiring us to post incremental cash collateral and letters of credit with hedging counterparties. In order to meet the need for additional collateral while maintaining sufficient liquidity for other uses, we executed a $300 million Short Term Credit Facility on April 11, 2018. A significant portion of the incremental collateral postings will be short-term in nature because, as our Summer 2018 hedge positions liquidate, the collateral will be returned to us.

See Note 5 of the Notes to our Consolidated Condensed Financial Statements for further information related to our Short Term Credit Facility.

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, asset sales, 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, 2018, an increase of $1/MMBtu in natural gas prices would result in a increase of collateral required by approximately $348 million. If natural gas prices decreased by $1/MMBtu, we estimate that our collateral requirements would decrease by approximately $264 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, 2018, an increase of 500 Btu/KWh in the Market Heat Rate would result in an increase in collateral required by approximately $131 million. If Market Heat Rates were to fall at a similar rate, we estimate that our collateral required would decrease by approximately $133 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 2018 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, 2018 and December 31, 2017 (in millions):



	June 30, 2018		December 31, 2017
Corporate Revolving Facility⁽¹⁾	$	800	$	629
CDHI	267		244
Various project financing facilities	217		196
Other corporate facilities⁽²⁾	96		—
Total	$	1,380	$	1,069

____________


(1)	The Corporate Revolving Facility represents our primary revolving facility.


(2)	During the second quarter of 2018, we executed two unsecured $50 million letter of credit facilities with third party financial institutions, each maturing on June 20, 2020. On July 26, 2018, we upsized one of the letter of credit facilities to $100 million.

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, 2017, our consolidated federal NOLs totaled approximately $6.6 billion. Under federal and state income tax law, our NOL carryforwards can be utilized to reduce future taxable income subject to certain new limitations including after undergoing our ownership change as defined by Section 382 of the Internal Revenue Code and similar state provisions. See Note 9 of the Notes to Consolidated Condensed Financial Statements for further discussion of our NOLs.

Cash Flow Activities

The following table summarizes our cash flow activities for the six months ended June 30, 2018 and 2017 (in millions):



	2018			2017
Beginning cash and cash equivalents	$	443		$	606
Net cash provided by (used in):
Operating activities	56			264
Investing activities	(234		)	(106		)
Financing activities	69			(337		)
Net decrease in cash, cash equivalents and restricted cash	(109		)	(179		)
Ending cash, cash equivalents and restricted cash	$	334		$	427

Net Cash Provided By Operating Activities

Cash provided by operating activities for the six months ended June 30, 2018, was $56 million compared to $264 million for the six months ended June 30, 2017. The decrease was primarily due to:

•

Income from operations — Income from operations, adjusted for non-cash items, increased by $142 million for the six months ended June 30, 2018, compared to the same period in 2017. Non-cash items consist primarily of depreciation and amortization, income from unconsolidated investments in subsidiaries, gain on sale of assets and mark-to-market activity. The increase in income from operations was primarily driven by a $94 million increase in Commodity revenue, net of Commodity expense, excluding non-cash amortization and a $67 million decrease in operating and maintenance expense. See “Results of Operations for the Six months ended June 30, 2018 and 2017” above for further discussion of these changes.

•

Working capital employed — Working capital employed increased by $359 million for the six months ended June 30, 2018 compared to the same period in 2017 after adjusting for changes in debt extinguishment costs and mark-to-market related balances which did not impact cash provided by operating activities. This change was primarily due to an increase in net collateral margining requirements on our commodity hedging activities following a meaningful increase in forward commodity prices during the period ended June 30, 2018 as well as an increase in the purchase of both environmental products inventory and parts inventory necessary to manage business requirements.

Net Cash Used In Investing Activities

Cash used in investing activities for the six months ended June 30, 2018, was $234 million compared to $106 million for the six months ended June 30, 2017. The increase was primarily due to:


•	Capital expenditures — Capital expenditures for the six months ended June 30, 2018, were $231 million, an increase of $44 million over the six month period ended June 30, 2017. The increase was primarily due to additional capitalization of seasonal maintenance outage costs during 2018 when compared to 2017.


•	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. There were no similar acquisitions or divestitures during the six months ended June 30, 2018.

Net Cash Provided By (Used In) Financing Activities

Cash provided by financing activities for the six months ended June 30, 2018, was $69 million compared to cash used in financing activities of $337 million for the six months ended June 30, 2017. 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. There were no similar activities during the six months ended June 30, 2018.


•	Corporate Revolving Facility — During the six months ended June 30, 2018, we borrowed $275 million under our Corporate Revolving Facility. There were no borrowings under our Corporate Revolving Facility during the six months ended June 30, 2017.


•	Stock Repurchases — During the six months ended June 30, 2018, we repurchased $79 million of our equity classified share-based awards on the effective date of the Merger. There was no similar activity during the first half of 2017.

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 2017 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 3 and 6 of the Notes to Consolidated Financial Statements in our 2017 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, OMEC, Johanna Energy Center and Calpine Receivables.

SDG&E holds a call option to purchase OMEC for $377 million, which is exercisable through October 2018. If the call option period to purchase OMEC expires without the call option being exercised, we will evaluate the fair market value of the facility which, accordingly, could result in a write down of the carrying value of OMEC. See Note 4 of the Notes to Consolidated Condensed Financial Statements for further information regarding the call option on OMEC.

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 portfolio has been established to provide an additional source of liquidity for our generation fleet as we hedge retail load from our wholesale generation assets as appropriate.

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 2018 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 7 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 increased to approximately $472 million at June 30, 2018, when compared to approximately $392 million at December 31, 2017, and our derivative liabilities have increased to approximately $438 million at June 30, 2018, when compared to approximately $316 million at December 31, 2017. The fair value of our level 3 derivative assets and liabilities at June 30, 2018 represents approximately 37% and 20% of our total assets and liabilities measured at fair value, respectively. See Note 6 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, 2018, through June 30, 2018, is summarized in the table below (in millions):



	Commodity Instruments			Interest Rate Hedging Instruments			Total
Fair value of contracts outstanding at January 1, 2018	$	81		$	(5	)	$	76
Items recognized or otherwise settled during the period⁽¹⁾⁽²⁾	(26		)	9			(17		)
Fair value attributable to new contracts⁽³⁾	60			—			60
Changes in fair value attributable to price movements	(141		)	56			(85		)
Fair value of contracts outstanding at June 30, 2018⁽⁴⁾	$	(26	)	$	60		$	34

__________

(1)

Commodity contract settlements consist of the realization of previously recognized gains on contracts not designated as hedging instruments of $(13) million (represents a portion of Commodity revenue and Commodity expense as reported on our Consolidated Condensed Statements of Operations) and $13 million related to current period losses from other changes in derivative assets and liabilities not reflected in OCI or earnings.


(2)	Interest rate settlements consist of $8 million related to realized losses from settlements of designated cash flow hedges and $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 $12 million and nil of fair value related to commodity contracts and interest rate hedging instruments, respectively, which are not reflected in OCI or earnings.

(4)

We netted all amounts allowed under the derivative accounting guidance on the Consolidated Condensed Balance Sheet, which includes derivative transactions under enforceable master netting arrangements and related cash collateral. Net commodity and interest rate derivative assets and liabilities reported in Notes 6 and 7 of the Notes to Consolidated Condensed Financial Statements are shown net of collateral paid to and received from counterparties under legally enforceable master netting arrangements..

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, net of allocated collateral, at June 30, 2018, based on price source and the period during which the instruments will mature, are summarized in the table below (in millions):



Fair Value Source	2018			2019-2020			2021-2022		After 2022		Total
Prices actively quoted	$	—		$	—		$	—	$	—	$	—
Prices provided by other external sources	(59		)	(105		)	6		1		(157		)
Prices based on models and other valuation methods	(15		)	114			20		12		131
Total fair value	$	(74	)	$	9		$	26	$	13	$	(26	)

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, 2018 and 2017 (in millions):



	2018		2017
Three months ended June 30:
High	$	45	$	22
Low	$	24	$	16
Average	$	33	$	19

Six months ended June 30:
High	$	45	$	22
Low	$	19	$	16
Average	$	30	$	19
As of June 30	$	34	$	21

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 8 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. For example, our wholesale business currently has contracts with the three investor owned California utilities which could be affected should they be found liable for recent wildfires in California and, accordingly, incur substantial costs associated with the wildfires. We cannot predict the ultimate outcome of this matter and continue to monitor the proceedings.

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), net of allocated collateral, at June 30, 2018, and the period during which the instruments will mature are summarized in the table below (in millions):



Credit Quality (Based on Credit Ratings as of June 30, 2018)	2018			2019-2020			2021-2022			After 2022			Total
Investment grade	$	(76	)	$	(57	)	$	17		$	(1	)	$	(117	)
Non-investment grade	(9		)	1			(11		)	1			(18		)
No external ratings⁽¹⁾	11			65			20			13			109
Total fair value	$	(74	)	$	9		$	26		$	13		$	(26	)

__________


(1)	Primarily comprised of the fair value of derivative instruments held with customers that are not rated by third party credit agencies due to the nature and size of the customers.

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 $(31) million at June 30, 2018.

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 2017 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 2018, 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

Various risk factors could have a negative effect on our business. These include the following risk factor, in addition to the risk factors previously disclosed in Part I, Item 1A “Risk Factors” of our 2017 Form 10-K:

Failures in our systems or a cyber attack or breach of our IT systems or technology could significantly disrupt our business operations or result in sensitive customer information being compromised, which would negatively materially affect our reputation and/or results of operations.

Our IT systems contain personal, financial and other information that is entrusted to us by our customers and employees as well as financial, proprietary and other confidential information related to our business, which makes us a target of cyber attacks on our systems. We rely on electronic networks, computers, systems, including our gateways, programs to run our business and operations, our employees and third party technology and IT infrastructure providers and, as a result, are potentially exposed to the risk of security breaches, computer or other malware, viruses, social engineering or general hacking, industrial espionage, employee or third party error or malfeasance, or other irregularities or compromises on our systems or those to third parties, which could result in the loss or misappropriation of sensitive data or other disruption to our operations.

We depend on computer and telecommunications systems we do not own or control. We have entered into agreements with third parties for hardware, software, telecommunications and other information technology services in connection with the operation of our power plants. In addition, we have developed proprietary software systems, management techniques and other information technologies incorporating software licensed from third parties. We also rely on software systems owned and operated by third parties, such as ISOs and RTOs, to be functioning in order to be able to transmit the electricity produced by our power plants to our customers. It is possible that we, or a third party that we rely on, could incur interruptions from a loss of communications, hardware or software failures, a cyber attack or a breach of our IT systems or technology, computer viruses or malware. We believe that we have positive relations with our vendors and maintain adequate anti-virus and malware software and controls; however, any interruptions to our arrangements with third parties, to our computing and communications infrastructure, or to our information systems or any of those operated by a third party that we rely on could significantly disrupt our business operations.

A cyber attack on our systems or networks that impairs our information technology systems could disrupt our business operations and result in loss of service to customers. We have a comprehensive cybersecurity program designed to protect and preserve the integrity of our information technology systems. We have experienced and expect to continue to experience actual or attempted cyber attacks on our IT systems or networks; however, none of these actual or attempted cyber attacks has had a material effect on our operations or financial condition. Even when a security breach is detected, the full extent of the breach may not be determined for some time. The risk of a security breach or disruption, particularly through a cyber attack or a cyber intrusion, including by computer hackers, foreign governments and cyber terrorists, has magnified as the number, intensity and sophistication of attempted attacks and intrusions from around the world has increased. An increasing number of companies have disclosed security breaches of their IT systems and networks, some of which have involved sophisticated and highly targeted attacks. We believe such incidents are likely to continue, and we are unable to predict the direct or indirect effect of any future attacks on our business.

Additionally, our retail subsidiaries require access to sensitive customer information in the ordinary course of business. If a significant data breach occurred, the reputation of our retail subsidiaries may be adversely affected, customer confidence may be diminished, and our retail subsidiaries may become subject to legal claims, any of which may contribute to the loss of customers and have a material adverse effect on our retail subsidiaries.

Revenue may be reduced significantly upon expiration or termination of our PPAs.

Some of the capacity from our existing portfolio is sold under long-term PPAs that expire at various times. We seek to sell any capacity not sold under long-term PPAs, on a short-term basis as market opportunities arise. Our non-contracted capacity is generally sold on the spot market at current market prices as merchant energy. When the terms of each of our various PPAs expire, it is possible that the price paid to us for the generation of power under subsequent arrangements or in short-term markets may be significantly less than the price that had been paid to us under the PPA. Without the benefit of long-term PPAs, we may not be able to sell any or all of the capacity from these power plants at commercially attractive rates and these power plants may not be able to operate profitably. Certain of our PPAs have values in excess of current market prices. If a counterparty to a PPA were to seek bankruptcy protection under Chapter 11 or liquidation under Chapter 7 of the U.S. Bankruptcy Code, they may be

able to terminate the PPA. We are at risk of loss of margins to the extent that these contracts expire or are terminated and we are unable to replace them on comparable terms.

For example, our wholesale business currently has contracts with the three investor owned California utilities which could be affected should they be found liable for recent wildfires in California and, accordingly, incur substantial costs associated with the wildfires. We cannot predict the ultimate outcome of this matter and continue to monitor the proceedings. However, should the outcome in the matter be unfavorable, our business may be adversely affected.


Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds

None.


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

4.1		Stockholders Agreement, dated March 8, 2018, by and between Calpine Corporation and CPN Management, LP (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on From 8-K filed with the SEC on March 8, 2018).

10.1		Amended and Restated Limited Partnership Agreement of CPN Management, LP a Delaware Limited Partnership, dated March 8, 2018.†

10.2		Amendment No. 8 to the Credit Agreement, dated as of May 18, 2018, among Calpine Corporation, as borrower, the guarantors party thereto, The Bank of Tokyo-Mitsubishi UFJ Ltd, as administrative agent, MUFG Union Bank, N.A., as collateral agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on From 8-K filed with the SEC on May 21, 2018).

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.



CALPINE CORPORATION
(Registrant)

By:		/s/ ZAMIR RAUF
		Zamir Rauf Executive Vice President and Chief Financial Officer (Principal Financial Officer)

Date: August 8, 2018

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Calpine (CPNLQ) 10-Q2018 Q2 Quarterly report

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