CALPINE CORP - FORM 10-Q

Attached files

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EX-32.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER - CALPINE CORP	cpn_exhibit321x06302016.htm
EX-31.2 - SECTION 302 CERTIFICATION OF CHIEF FINANCIAL OFFICER - CALPINE CORP	cpn_exhibit312x06302016.htm
EX-31.1 - SECTION 302 CERTIFICATION OF CHIEF EXECUTIVE OFFICER - CALPINE CORP	cpn_exhibit311x06302016.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

____________________

Form 10-Q

(Mark One)



[X]		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
		OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2016

		Or

[ ]		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
		OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File No. 001-12079

______________________

Calpine Corporation

(A Delaware Corporation)

I.R.S. Employer Identification No. 77-0212977

717 Texas Avenue, Suite 1000, Houston, Texas 77002

Telephone: (713) 830-2000

Not Applicable

(Former Address)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [X] No [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting 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	[ ]

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: 359,139,572 shares of common stock, par value $0.001, were outstanding as of July 27, 2016.

CALPINE CORPORATION AND SUBSIDIARIES

REPORT ON FORM 10-Q

For the Quarter Ended June 30, 2016

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, 2016 and 2015	1
Consolidated Condensed Statements of Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2016 and 2015	2
Consolidated Condensed Balance Sheets at June 30, 2016 and December 31, 2015	3
Consolidated Condensed Statements of Cash Flows for the Six Months Ended June 30, 2016 and 2015	4
Notes to Consolidated Condensed Financial Statements	6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Forward-Looking Information	28
Introduction and Overview	28
Results of Operations	32
Commodity Margin and Adjusted EBITDA	36
Liquidity and Capital Resources	43
Risk Management and Commodity Accounting	49
Application of Critical Accounting Policies	53
New Accounting Standards and Disclosure Requirements	53
Item 3. Quantitative and Qualitative Disclosures About Market Risk	54
Item 4. Controls and Procedures	54

PART II – OTHER INFORMATION

Item 1. Legal Proceedings	55
Item 1A. Risk Factors	55
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	55
Item 3. Defaults Upon Senior Securities	55
Item 4. Mine Safety Disclosures	55
Item 5. Other Information	55
Item 6. Exhibits	56
Signatures	57

DEFINITIONS

As used in this report for the quarter ended June 30, 2016 (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
2015 Form 10-K		Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2015, filed with the SEC on February 12, 2016

2019 First Lien Term Loan		The $835 million first lien senior secured term loan, dated October 9, 2012, among Calpine Corporation, as borrower, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent, repaid on May 31, 2016

2020 First Lien Term Loan		The $390 million first lien senior secured term loan, dated October 23, 2013, among Calpine Corporation, as borrower, the lenders party thereto, Citibank, N.A., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent, repaid on May 31, 2016

2022 First Lien Notes		The $750 million aggregate principal amount of 6.0% senior secured notes due 2022, issued October 31, 2013

2022 First Lien Term Loan		The $1.6 billion first lien senior secured term loan, dated May 28, 2015, among Calpine Corporation, as borrower, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent

2023 First Lien Term Loan		The $550 million first lien senior secured term loan, dated December 15, 2015, among Calpine Corporation, as borrower, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent

2023 First Lien Term Loans		Collectively, the 2023 First Lien Term Loan and the New 2023 First Lien Term Loan

2023 First Lien Notes		The $1.2 billion aggregate principal amount of 7.875% senior secured notes due 2023, issued January 14, 2011, and partially repaid in a series of transactions on November 7, 2012, December 2, 2013, December 4, 2014, February 3, 2015 and December 7, 2015

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

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

2026 First Lien Notes		The $625 million aggregate principal amount of 5.25% senior unsecured notes due 2026, issued May 31, 2016

Adjusted EBITDA		EBITDA as adjusted for the effects of (a) impairment charges, (b) major maintenance expense, (c) operating lease expense, (d) gains or losses on commodity derivative mark-to-market activity, (e) adjustments to reflect only the Adjusted EBITDA from our unconsolidated investments, (f) adjustments to exclude the Adjusted EBITDA related to the noncontrolling interest, (g) stock-based compensation expense, (h) gains or losses on sales, dispositions or retirements of assets, (i) non-cash gains and losses from foreign currency translations, (j) gains or losses on the repurchase, modification or extinguishment of debt, (k) non-cash GAAP-related adjustments to levelize revenues from tolling agreements and (l) other unusual or non-recurring items



ABBREVIATION		DEFINITION

AOCI		Accumulated Other Comprehensive Income

Average availability		Represents the total hours during the period that our plants were in-service or available for service as a percentage of the total hours in the period

Average capacity factor, excluding peakers		A measure of total actual power generation as a percent of total potential power generation. It is calculated by dividing (a) total MWh generated by our power plants, excluding peakers, by (b) the product of multiplying (i) the average total MW in operation, excluding peakers, during the period by (ii) the total hours in the period

Btu		British thermal unit(s), a measure of heat content

CAISO		California Independent System Operator

Calpine Equity Incentive Plans		Collectively, the Director Plan and the Equity Plan, which provide for grants of equity awards to Calpine non-union employees and non-employee members of Calpine’s Board of Directors

Cap-and-Trade		A government imposed emissions reduction program that would place a cap on the amount of emissions that can be emitted from certain sources, such as power plants. In its simplest form, the cap amount is set as a reduction from the total emissions during a base year and for each year over a period of years the cap amount would be reduced to achieve the targeted overall reduction by the end of the period. Allowances or credits for emissions in an amount equal to the cap would be issued or auctioned to companies with facilities, permitting them to emit up to a certain amount of emissions during each applicable period. After allowances have been distributed or auctioned, they can be transferred or traded

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

CCFC Term Loans		Collectively, the $900 million first lien senior secured term loan and the $300 million first lien senior secured term loan entered into on May 3, 2013, and the $425 million first lien senior secured term loan entered into on February 26, 2014, between CCFC, as borrower, and Goldman Sachs Lending Partners, LLC, as administrative agent and as collateral agent, and the lenders party thereto

CDHI		Calpine Development Holdings, Inc., an indirect, wholly-owned subsidiary of Calpine

CFTC		Commodities Futures Trading Commission

Champion Energy		Champion Energy Marketing, LLC, which owns a retail electric provider that serves residential, governmental, commercial and industrial customers in deregulated electricity markets in Texas, Illinois, Pennsylvania, Ohio, New Jersey, Maryland, Massachusetts, New York, Delaware, Maine and the District of Columbia

CO₂		Carbon dioxide

COD		Commercial operations date

Cogeneration		Using a portion or all of the steam generated in the power generating process to supply a customer with steam for use in the customer’s operations

Commodity expense		The sum of our expenses from fuel and purchased energy expense, fuel transportation expense, transmission expense, environmental compliance expense and realized settlements from our marketing, hedging and optimization activities including natural gas and fuel oil transactions hedging future power sales, but excludes our mark-to-market activity

Commodity Margin		Non-GAAP financial measure that includes power and steam revenues, sales of purchased power and physical natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, environmental compliance expense, and realized settlements from our marketing, hedging, optimization and trading activities, but excludes our mark-to-market activity and other revenues

iii



ABBREVIATION		DEFINITION
Commodity revenue		The sum of our revenues from power and steam sales, sales of purchased power and physical natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue and realized settlements from our marketing, hedging, optimization and trading activities, but excludes our mark-to-market activity

Company		Calpine Corporation, a Delaware corporation, and its subsidiaries

Corporate Revolving Facility		The $1.7 billion aggregate amount revolving credit facility credit agreement, dated as of December 10, 2010, as amended on June 27, 2013, July 30, 2014 and February 8, 2016, among Calpine Corporation, the Bank of Tokyo-Mitsubishi UFJ, Ltd., as successor administrative agent, MUFG Union Bank, N.A., as successor collateral agent, the lenders party thereto and the other parties thereto

CPUC		California Public Utilities Commission

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

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

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

ERCOT		Electric Reliability Council of Texas

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

FASB		Financial Accounting Standards Board

FDIC		U.S. Federal Deposit Insurance Corporation

FERC		U.S. Federal Energy Regulatory Commission

First Lien Notes		Collectively, the 2022 First Lien Notes, the 2023 First Lien Notes, the 2024 First Lien Notes and the 2026 First Lien Notes

First Lien Term Loans		Collectively, the 2019 First Lien Term Loan, the 2020 First Lien Term Loan, the 2022 First Lien Term Loan and the 2023 First Lien Term Loans

Geysers Assets		Our geothermal power plant assets, including our steam extraction and gathering assets, located in northern California consisting of 14 operating power plants

GHG(s)		Greenhouse gas(es), primarily carbon dioxide (CO2), and including methane (CH4), nitrous oxide (N2O), sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs) and perfluorocarbons (PFCs)

Greenfield LP		Greenfield Energy Centre LP, a 50% partnership interest between certain of our subsidiaries and a third party which operates the Greenfield Energy Centre, a 1,038 MW natural gas-fired, combined-cycle power plant in Ontario, Canada

Heat Rate(s)		A measure of the amount of fuel required to produce a unit of power

IPP(s)		Independent Power Producers

IPP Peers		Dynegy Inc., NRG Energy, Inc. and Talen Energy Corporation

IRS		U.S. Internal Revenue Service

ISO(s)		Independent System Operator(s)

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



ABBREVIATION		DEFINITION

LIBOR		London Inter-Bank Offered Rate

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

MMBtu		Million Btu

MW		Megawatt(s), a measure of plant capacity

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

New 2023 First Lien Term Loan		The $562 million first lien senior secured term loan, dated May 31, 2016, among Calpine Corporation, as borrower, the lenders party thereto, Citibank, N.A., as administrative agent and MUFG Union Bank, N.A., as collateral agent

NOL(s)		Net operating loss(es)

NYMEX		New York Mercantile Exchange

OCI		Other Comprehensive Income

OTC		Over-the-Counter

PJM		PJM Interconnection is a RTO that coordinates the movement of wholesale electricity in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia

PPA(s)		Any term power purchase agreement or other contract for a physically settled sale (as distinguished from a financially settled future, option or other derivative or hedge transaction) of any power product, including power, capacity and/or ancillary services, in the form of a bilateral agreement or a written or oral confirmation of a transaction between two parties to a master agreement, including sales related to a tolling transaction in which the purchaser provides the fuel required by us to generate such power and we receive a variable payment to convert the fuel into power and steam

PUCT		Public Utility Commission of Texas

REC(s)		Renewable energy credit(s)

Risk Management Policy		Calpine’s policy applicable to all employees, contractors, representatives and agents, which defines the risk management framework and corporate governance structure for commodity risk, interest rate risk, currency risk and other risks

RTO(s)		Regional Transmission Organization(s)

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

SO₂		Sulfur dioxide

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

TSR		Total shareholder return



ABBREVIATION		DEFINITION

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. You are cautioned that any such forward-looking statements are not guarantees of future performance and that a number of risks and uncertainties could cause actual results to differ materially from those anticipated in the forward-looking statements. Such risks and uncertainties include, but are not limited to:


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


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


•	Our ability to manage our liquidity needs, access the capital markets when necessary and comply with covenants under our Senior Unsecured Notes, First Lien Notes, First Lien Term Loans, Corporate Revolving Facility, CCFC Term Loans and other existing financing obligations;


•	Risks associated with the operation, construction and development of power plants, including unscheduled outages or delays and plant efficiencies;

•

Risks related to our geothermal resources, including the adequacy of our steam reserves, unusual or unexpected steam field well and pipeline maintenance requirements, variables associated with the injection of water to the steam reservoir and potential regulations or other requirements related to seismicity concerns that may delay or increase the cost of developing or operating geothermal resources;


•	Competition, including from renewable sources of power, interference by states in competitive power markets through subsidies or similar support for new or existing power plants, and other risks associated with marketing and selling power in the evolving energy markets;


•	Structural changes in the supply and demand of power, resulting from the development of new fuels or technologies and demand-side management tools (such as distributed generation, power storage and other technologies);


•	The expiration or early termination of our PPAs and the related results on revenues;


•	Future capacity revenue may not occur at expected levels;


•	Natural disasters, such as hurricanes, earthquakes, droughts, wildfires and floods, acts of terrorism or cyber attacks that may impact our power plants or the markets our power plants or retail operations serve and our corporate headquarters;


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


•	Our ability to manage our customer and counterparty 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 2015 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,
		2016			2015			2016			2015
	(in millions, except share and per share amounts)
Operating revenues:
Commodity revenue		$	1,551		$	1,407		$	3,136		$	3,045
Mark-to-market gain (loss)		(391		)	31			(366		)	34
Other revenue		4			4			9			9
Operating revenues		1,164			1,442			2,779			3,088
Operating expenses:
Fuel and purchased energy expense:
Commodity expense		897			734			1,903			1,811
Mark-to-market (gain) loss		(355		)	32			(235		)	(35		)
Fuel and purchased energy expense		542			766			1,668			1,776
Plant operating expense		271			272			526			532
Depreciation and amortization expense		162			160			342			318
Sales, general and other administrative expense		35			30			73			67
Other operating expenses		17			20			37			40
Total operating expenses		1,027			1,248			2,646			2,733
(Income) from unconsolidated investments in power plants		(3		)	(7		)	(10		)	(12		)
Income from operations		140			201			143			367
Interest expense		157			158			314			312
Interest (income)		(1		)	(1		)	(2		)	(2		)
Debt modification and extinguishment costs		15			13			15			32
Other (income) expense, net		7			5			13			7
Income (loss) before income taxes		(38		)	26			(197		)	18
Income tax expense (benefit)		(14		)	5			21			4
Net income (loss)		(24		)	21			(218		)	14
Net income attributable to the noncontrolling interest		(5		)	(2		)	(9		)	(5		)
Net income (loss) attributable to Calpine		$	(29	)	$	19		$	(227	)	$	9

Basic earnings (loss) per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands)		354,066			366,975			353,784			369,938
Net income (loss) per common share attributable to Calpine — basic		$	(0.08	)	$	0.05		$	(0.64	)	$	0.02

Diluted earnings (loss) per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands)		354,066			369,946			353,784			373,404
Net income (loss) per common share attributable to Calpine — diluted		$	(0.08	)	$	0.05		$	(0.64	)	$	0.02

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,
	2016			2015			2016			2015
	(in millions)
Net income (loss)	$	(24	)	$	21		$	(218	)	$	14
Cash flow hedging activities:
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income (loss)	(17		)	2			(40		)	(16		)
Reclassification adjustment for loss on cash flow hedges realized in net income (loss)	11			12			22			24
Foreign currency translation gain (loss)	—			4			12			(8		)
Income tax expense	—			—			—			—
Other comprehensive income (loss)	(6		)	18			(6		)	—
Comprehensive income (loss)	(30		)	39			(224		)	14
Comprehensive (income) attributable to the noncontrolling interest	(5		)	(4		)	(7		)	(6		)
Comprehensive income (loss) attributable to Calpine	$	(35	)	$	35		$	(231	)	$	8

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,
	2016			2015
	(in millions, except share and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents ($69 and $118 attributable to VIEs)	$	215		$	906
Accounts receivable, net of allowance of $4 and $2	720			644
Inventories	522			475
Margin deposits and other prepaid expense	193			137
Restricted cash, current ($96 and $132 attributable to VIEs)	148			216
Derivative assets, current	1,231			1,698
Current assets held for sale	206			—
Other current assets	53			19
Total current assets	3,288			4,095
Property, plant and equipment, net ($3,993 and $4,062 attributable to VIEs)	13,341			13,012
Restricted cash, net of current portion ($20 and $11 attributable to VIEs)	20			12
Investments in power plants	74			79
Long-term derivative assets	369			313
Long-term assets held for sale	—			130
Other assets ($115 and $119 attributable to VIEs)	887			1,040
Total assets	$	17,979		$	18,681
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	531		$	552
Accrued interest payable	130			129
Debt, current portion ($164 and $166 attributable to VIEs)	197			221
Derivative liabilities, current	1,360			1,734
Other current liabilities	355			412
Total current liabilities	2,573			3,048
Debt, net of current portion ($3,031 and $3,096 attributable to VIEs)	11,644			11,716
Long-term derivative liabilities	512			473
Other long-term liabilities	298			277
Total liabilities	15,027			15,514

Commitments and contingencies (see Note 11)
Stockholders’ equity:
Preferred stock, $0.001 par value per share; authorized 100,000,000 shares, none issued and outstanding	—			—
Common stock, $0.001 par value per share; authorized 1,400,000,000 shares, 359,662,911 and 356,755,747 shares issued, respectively, and 359,139,948 and 356,662,004 shares outstanding, respectively	—			—
Treasury stock, at cost, 522,963 and 93,743 shares, respectively	(7		)	(1		)
Additional paid-in capital	9,611			9,594
Accumulated deficit	(6,532		)	(6,305		)
Accumulated other comprehensive loss	(183		)	(179		)
Total Calpine stockholders’ equity	2,889			3,109
Noncontrolling interest	63			58
Total stockholders’ equity	2,952			3,167
Total liabilities and stockholders’ equity	$	17,979		$	18,681

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,
	2016			2015
	(in millions)
Cash flows from operating activities:
Net income (loss)	$	(218	)	$	14
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization⁽¹⁾	459			342
Debt extinguishment costs	15			—
Income taxes	11			3
Mark-to-market activity, net	130			(70		)
(Income) from unconsolidated investments in power plants	(10		)	(12		)
Return on unconsolidated investments in power plants	18			13
Stock-based compensation expense	17			12
Other	(1		)	2
Change in operating assets and liabilities, net of effect of acquisition:
Accounts receivable	(78		)	29
Derivative instruments, net	(69		)	(36		)
Other assets	(116		)	(118		)
Accounts payable and accrued expenses	(90		)	(205		)
Other liabilities	52			45
Net cash provided by operating activities	120			19
Cash flows from investing activities:
Purchases of property, plant and equipment	(223		)	(279		)
Purchase of Granite Ridge Energy Center	(526		)	—
Decrease in restricted cash	60			34
Other	13			(1		)
Net cash used in investing activities	(676		)	(246		)
Cash flows from financing activities:
Borrowings under First Lien Term Loans	556			1,592
Repayment of CCFC Term Loans and First Lien Term Loans	(1,209		)	(1,613		)
Borrowings under Senior Unsecured Notes	—			650
Borrowings under First Lien Notes	625			—
Repurchase of First Lien Notes	—			(147		)
Repayments of project financing, notes payable and other	(81		)	(85		)
Financing costs	(26		)	(17		)
Stock repurchases	—			(454		)
Other	—			6
Net cash used in financing activities	(135		)	(68		)
Net decrease in cash and cash equivalents	(691		)	(295		)
Cash and cash equivalents, beginning of period	906			717
Cash and cash equivalents, end of period	$	215		$	422

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,
	2016		2015
	(in millions)
Cash paid during the period for:
Interest, net of amounts capitalized	$	289	$	322
Income taxes	$	8	$	17

Supplemental disclosure of non-cash investing and financing activities:
Change in capital expenditures included in accounts payable	$	24	$	(20	)
Additions to property, plant and equipment through capital lease	$	—	$	9

____________


(1)	Includes amortization recorded in Commodity revenue and Commodity expense associated with intangible assets and amortization recorded in interest expense associated with debt issuance costs and discounts.

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

CALPINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

June 30, 2016

(Unaudited)


1.	Basis of Presentation and Summary of Significant Accounting Policies

We are a power generation company engaged in the ownership and operation of primarily natural gas-fired and geothermal power plants in North America. We have a significant presence in major competitive wholesale power markets in California (included in our West segment), Texas (included in our Texas segment) and the Northeast and Mid-Atlantic regions (included in our East segment) of the U.S. We sell power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities and other governmental entities, power marketers as well as retail commercial, industrial, governmental and residential customers. We 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 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, 2015, included in our 2015 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, timing of major maintenance expense, variations resulting from the application of the method to calculate the provision for income tax for interim periods, volatility of commodity prices and mark-to-market gains and losses from commodity and interest rate derivative contracts.

Use of Estimates in Preparation of Financial Statements — The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures included in our Consolidated Condensed Financial Statements. Actual results could differ from those estimates.

Cash and Cash Equivalents — We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have cash and cash equivalents held in non-corporate accounts relating to certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts. These accounts have been pledged as security in favor of the lenders under such project finance facilities, and the use of certain cash balances on deposit in such accounts is limited, at least temporarily, to the operations of the respective projects.

Restricted Cash — Certain of our debt agreements, lease agreements or other operating agreements require us to establish and maintain segregated cash accounts, the use of which is restricted, making these cash funds unavailable for general use. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent and major maintenance or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Condensed Balance Sheets and Statements of Cash Flows.

The table below represents the components of our restricted cash as of June 30, 2016 and December 31, 2015 (in millions):



	June 30, 2016						December 31, 2015
	Current		Non-Current		Total		Current		Non-Current		Total
Debt service	$	34	$	8	$	42	$	28	$	8	$	36
Construction/major maintenance	36		9		45		50		2		52
Security/project/insurance	75		2		77		136		—		136
Other	3		1		4		2		2		4
Total	$	148	$	20	$	168	$	216	$	12	$	228

Business Interruption Proceeds — We record business interruption insurance proceeds when they are realizable and recorded approximately $8 million of business interruption proceeds in operating revenues during the three and six months ended June 30, 2016. We did not record any business interruption proceeds during the three and six months ended June 30, 2015.

Property, Plant and Equipment, Net — At June 30, 2016 and December 31, 2015, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):



	June 30, 2016		December 31, 2015		Depreciable Lives
Buildings, machinery and equipment	$	16,712	$	16,294	3 – 46 Years
Geothermal properties	1,368		1,319		13 – 58 Years
Other	230		208		3 – 46 Years
	18,310		17,821
Less: Accumulated depreciation	5,652		5,377
	12,658		12,444
Land	121		120
Construction in progress	562		448
Property, plant and equipment, net	$	13,341	$	13,012

Capitalized Interest — The total amount of interest capitalized was $5 million and $4 million for the three months ended June 30, 2016 and 2015, respectively, and $9 million during each of the six months ended June 30, 2016 and 2015.

Impairment Evaluation of Long-Lived Assets (Including Intangibles and Investments)

We evaluate our long-lived assets, such as property, plant and equipment, equity method investments and definite-lived intangible assets for impairment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Equipment assigned to each power plant is not evaluated for impairment separately; instead, we evaluate our operating power plants and related equipment as a whole unit. When we believe an impairment condition may have occurred, we are required to estimate the undiscounted future cash flows associated with a long-lived asset or group of long-lived assets at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities for long-lived assets that are expected to be held and used. We use a fundamental long-term view of the power market which is based on long-term production volumes, price curves and operating costs together with the regulatory and environmental requirements within each individual market to prepare our multi-year forecast. Since we manage and market our power sales as a portfolio rather than at the individual power plant level or customer level within each designated market, pool or segment, we group our power plants based upon the corresponding market for valuation purposes. If we determine that the undiscounted cash flows from an asset or group of assets to be held and used are less than the associated carrying amount, or if we have classified an asset as held for sale, we must estimate fair value to determine the amount of any impairment loss. All construction and development projects are reviewed for impairment whenever there is an indication of potential reduction in fair value. If it is determined that a construction or development project is no longer probable of completion and the capitalized costs will not be recovered through future operations, the carrying value of the project will be written down to its fair value.

In order to estimate future cash flows, we consider historical cash flows, existing contracts, capacity prices and PPAs, changes in the market environment and other factors that may affect future cash flows. To the extent applicable, the assumptions we use are consistent with forecasts that we are otherwise required to make (for example, in preparing our earnings forecasts). The use of this method involves inherent uncertainty. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.

When we determine that our assets meet the assets held-for-sale criteria, they are reported at the lower of their carrying amount or fair value less the cost to sell. We are also required to evaluate our equity method investments to determine whether or not they are impaired when the value is considered an “other than a temporary” decline in value.

Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. We will also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment including contract terms, tenor and credit risk of counterparties. We may also consider prices of similar assets, consult with brokers, or employ other valuation techniques. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs.

However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.

We did not record any material impairments during the three and six months ended June 30, 2016 and 2015.

New Accounting Standards and Disclosure Requirements

Revenue Recognition — In May 2014, the FASB issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers.” The comprehensive new revenue recognition standard will supersede all existing revenue recognition guidance. The core principle of the standard is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard also requires expanded disclosures surrounding revenue recognition. The standard is effective for fiscal periods beginning after December 15, 2016, including interim periods within that reporting period and allows for either full retrospective or modified retrospective adoption with early adoption being prohibited. In August 2015, the FASB deferred the effective date of Accounting Standards Update 2014-09 for public entities by one year, such that the standard will become effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2017. The standard permits entities to adopt early, but only as of the original effective date. In March 2016, the FASB issued Accounting Standards Update 2016-08 “Principal versus Agent Considerations (Reporting Revenue Gross versus Net)” which clarifies implementation guidance for principal versus agent considerations in the new revenue recognition standard. In May 2016, the FASB issued Accounting Standards Update 2016-12 “Narrow-Scope Improvements and Practical Expedients” which addresses assessing the collectability of a contract, the presentation of sales taxes and other taxes collected from customers, non-cash consideration and completed contracts and contract modifications at transition. We are currently assessing the potential impact the revenue recognition standard may have on our financial condition, results of operations or cash flows.

Consolidation — In February 2015, the FASB issued Accounting Standards Update 2015-02, “Amendments to the Consolidation Analysis.” This standard amends the consolidation model used in determining whether a reporting entity should consolidate the financial results of certain of its partially- and wholly-owned subsidiaries. All of our subsidiaries are subject to reevaluation under the revised consolidation model. Specifically, the amendments (i) modify the evaluation of whether limited partnerships and similar legal entities are voting interest entities or VIEs, (ii) eliminate the presumption that a general partner should consolidate the financial results of a limited partnership, (iii) affect the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships and (iv) provide an exception for certain types of entities. This standard became effective for fiscal periods beginning after December 15, 2015, including interim periods within that reporting period. We adopted Accounting Standards Update 2015-02 in the first quarter of 2016 which did not have a material impact on our financial condition, results of operations or cash flows.

Debt Issuance Costs — In April 2015, the FASB issued Accounting Standards Update 2015-03, “Simplifying the Presentation of Debt Issuance Costs.” The standard requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, which is consistent with the presentation of debt discounts. In August 2015, the FASB issued Accounting Standards Update 2015-15, “Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements” which allows an entity to present debt issuance costs associated with a line-of-credit arrangement as an asset regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The standards became effective for fiscal years beginning after December 15, 2015, including interim periods within that reporting period. We retrospectively adopted Accounting Standard Updates 2015-03 and 2015-15 in the first quarter of 2016 which resulted in a $152 million reclassification of debt issuance costs from other assets to debt, net of current portion on our Consolidated Condensed Balance Sheet at December 31, 2015.

Cloud Computing Arrangements — In April 2015, the FASB issued Accounting Standards Update 2015-05, “Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement.” This standard provides guidance regarding whether a cloud computing arrangement represents a software license or a service contract. The standard became effective for fiscal years beginning after December 15, 2015, including interim periods. We adopted Accounting Standards Update 2015-05 in the first quarter of 2016 which did not have a material impact on our financial condition, results of operations or cash flows.

Inventory — In July 2015, the FASB issued Accounting Standards Update 2015-11, “Simplifying the Measurement of Inventory.” This standard changes the inventory valuation method from the lower of cost or market to the lower of cost or net realizable value for inventory valued under the first-in, first-out or average cost methods. The standard is effective for fiscal years beginning after December 15, 2016, including interim periods and requires prospective adoption with early adoption permitted. We do not anticipate a material impact on our financial condition, results of operations or cash flows as a result of adopting this standard.

Leases — In February 2016, the FASB issued Accounting Standards Update 2016-02, “Leases.” The comprehensive new lease standard will supersede all existing lease guidance. The standard requires that a lessee should recognize a right-to-use asset and a lease liability for substantially all operating leases based on the present value of the minimum rental payments. Entities may make an accounting policy election to not recognize lease assets and liabilities for leases with a term of 12 months or less. For lessors, the accounting for leases remains substantially unchanged. The standard also requires expanded disclosures surrounding leases. The standard is effective for fiscal periods beginning after December 15, 2018, including interim periods within that reporting period and requires modified retrospective adoption with early adoption permitted. We are currently assessing the potential impact this standard may have on our financial condition, results of operations or cash flows.

Stock-Based Compensation — In March 2016, the FASB issued Accounting Standards Update 2016-09, “Improvements to Employee Share-Based Payment Accounting.” This standard applies to several aspects of accounting for stock-based compensation including the recognition of excess tax benefits and deficiencies and their related presentation in the statement of cash flows as well as accounting for forfeitures. The standard is effective for fiscal years beginning after December 15, 2016, including interim periods and allows for prospective, retrospective or modified retrospective adoption, depending on the area covered in the standard, with early adoption permitted. We do not anticipate a material impact on our financial condition, results of operations or cash flows as a result of adopting this standard.


2.	Acquisitions and Divestitures

Acquisition of Granite Ridge Energy Center

On February 5, 2016, we, through our indirect, wholly-owned subsidiary Calpine Granite Holdings, LLC, completed the purchase of Granite Ridge Energy Center, a power plant with a nameplate capacity of 745 MW (summer peaking capacity of 695 MW), from Granite Ridge Holdings, LLC, for approximately $500 million, excluding working capital and other adjustments. The addition of this modern, efficient, natural gas-fired, combined-cycle power plant increased capacity in our East segment, specifically the constrained New England market. Beginning operations in 2003, Granite Ridge Energy Center is located in Londonderry, New Hampshire and features two combustion turbines, two heat recovery steam generators and one steam turbine. We funded the acquisition with a combination of cash on hand and financing obtained in the fourth quarter of 2015, and the purchase price was primarily allocated to property, plant and equipment. The pro forma incremental impact of Granite Ridge Energy Center on our results of operations for each of the three and six months ended June 30, 2016 and 2015 is not material.

Acquisition of Champion Energy

On October 1, 2015, we, through our indirect, wholly-owned subsidiary Calpine Energy Services Holdco, LLC, completed the purchase of Champion Energy Marketing, LLC from a subsidiary of Crane Champion Holdco, LLC, which owned a 75% interest, and EDF Trading North America, LLC, which owned a 25% interest, for approximately $240 million, excluding working capital adjustments. The addition of this well-established retail sales organization is consistent with our stated goal of getting closer to our end-use customers and provides us a valuable sales channel for directly reaching a much greater portion of the load we seek to serve. The purchase price was funded with cash on hand and any excess of the purchase price over the fair values of Champion Energy’s assets and liabilities was recorded as goodwill; however, the goodwill we recorded as a result of this acquisition was immaterial. We did not record any material adjustments to the preliminary purchase price allocation during the three and six months ended June 30, 2016.

Sale of South Point Energy Center

On April 1, 2016, we entered into an asset sale agreement for the sale of substantially all of the assets comprising our South Point Energy Center to Nevada Power Company d/b/a NV Energy for approximately $76 million plus the assumption by the purchaser of existing transmission capacity contracts with a future net present value payment obligation of approximately $112 million, approximately $9 million in remaining tribal lease costs and approximately $21 million in near-term repairs, maintenance and capital improvements to restore the power plant to full capacity. The sale is subject to certain conditions precedent, as well as federal and state regulatory approvals, and is expected to close no later than the first quarter of 2017. The natural gas-fired, combined-cycle plant is located on the Fort Mojave Indian Reservation in Mohave Valley, Arizona, and features a summer peaking capacity of 504 MW. This transaction supports our effort to divest non-core assets outside our strategic concentration.

Sale of Osprey Energy Center

We executed an asset sale agreement in the fourth quarter of 2014 for the sale of our Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million, excluding working capital and other adjustments, which will be consummated in January 2017 upon the conclusion of a PPA with a term of 27 months. The sale has received FERC and state regulatory approvals and represents a strategic disposition of a power plant in a wholesale power market dominated by regulated utilities.

Assets Held for Sale

The assets of Osprey Energy Center and South Point Energy Center, which are part of our East and West segments, respectively, are reported as current assets held for sale on our Consolidated Condensed Balance Sheet at June 30, 2016 and consist of property, plant and equipment, net.


3.	Variable Interest Entities and Unconsolidated Investments

We consolidate all of our VIEs where we have determined that we are the primary beneficiary. There were no changes to our determination of whether we are the primary beneficiary of our VIEs for the six months ended June 30, 2016. See Note 5 in our 2015 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 10,266 MW at both June 30, 2016 and December 31, 2015. 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, 2016 and 2015.

Unconsolidated VIEs and Investments in Power Plants

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.

We account for these entities under the equity method of accounting and include our net equity interest in investments in power plants on our Consolidated Condensed Balance Sheets. At June 30, 2016 and December 31, 2015, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):



	Ownership Interest as of June 30, 2016	June 30, 2016		December 31, 2015
Greenfield LP	50%	$	67	$	65
Whitby	50%	7		14
Total investments in power plants		$	74	$	79

Our risk of loss related to our unconsolidated VIEs is limited to our investment balance. Holders of the debt of our unconsolidated investments do not have recourse to Calpine Corporation and its other subsidiaries; therefore, the debt of our unconsolidated investments is not reflected on our Consolidated Condensed Balance Sheets. At June 30, 2016 and December 31, 2015, equity method investee debt was approximately $279 million and $269 million, respectively, and based on our pro rata share of each of the investments, our share of such debt would be approximately $139 million and $135 million at June 30, 2016 and December 31, 2015, respectively.

Our equity interest in the net income from Greenfield LP and Whitby for the three and six months ended June 30, 2016 and 2015, is recorded in (income) from unconsolidated investments in power plants. The following table sets forth details of our (income) from unconsolidated investments in power plants for the periods indicated (in millions):



	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Greenfield LP	$	(1	)	$	(4	)	$	(5	)	$	(6	)
Whitby	(2		)	(3		)	(5		)	(6		)
Total	$	(3	)	$	(7	)	$	(10	)	$	(12	)

Distributions from Greenfield LP were $5 million during each of the three and six months ended June 30, 2016, and nil during each of the three and six months ended June 30, 2015. Distributions from Whitby were $13 million during each of the three and six months ended June 30, 2016 and 2015.

Significant Unconsolidated Subsidiaries — Greenfield LP and Whitby met the criteria of significant unconsolidated subsidiaries for the six months ended June 30, 2015, based upon the relationship of our equity income from our investment to our consolidated net income before taxes. Aggregated summarized financial data for the six months ended June 30, 2016 and 2015 are set forth below (in millions):

Condensed Combined Statements of Operations

of Our Unconsolidated Subsidiaries

(Unaudited)



	Six Months Ended June 30,
	2016		2015
Revenues	$	75	$	98
Operating expenses	43		66
Income from operations	32		32
Interest expense, net of interest income	8		10
Other (income) expense, net	3		(1		)
Net income	$	21	$	23


4.	Debt

We retrospectively adopted Accounting Standards Update 2015-03 in the first quarter of 2016. As a result, we recast our Consolidated Condensed Balance Sheet at December 31, 2015 resulting in a $152 million reclassification of debt issuance costs from other assets to debt, net of current portion. Our debt at June 30, 2016 and December 31, 2015, was as follows (in millions):



	June 30, 2016		December 31, 2015
Senior Unsecured Notes	$	3,409	$	3,406
First Lien Term Loans	2,642		3,277
First Lien Notes	2,407		1,789
Project financing, notes payable and other	1,643		1,715
CCFC Term Loans	1,559		1,565
Capital lease obligations	181		185
Subtotal	11,841		11,937
Less: Current maturities	197		221
Total long-term debt	$	11,644	$	11,716

Our effective interest rate on our consolidated debt, excluding the impacts of capitalized interest and mark-to-market gains (losses) on interest rate hedging instruments, decreased to 5.5% for the six months ended June 30, 2016, from 5.7% for the same period in 2015. The issuance of our New 2023 First Lien Term Loan in May 2016, our 2024 Senior Unsecured Notes in February 2015 and our 2022 First Lien Term Loan in May 2015 allowed us to reduce our overall cost of debt by replacing a portion of our First Lien Term Loans and First Lien Notes with debt carrying lower interest rates.

Senior Unsecured Notes

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



	June 30, 2016		December 31, 2015
2023 Senior Unsecured Notes	$	1,236	$	1,235
2024 Senior Unsecured Notes	642		641
2025 Senior Unsecured Notes	1,531		1,530
Total Senior Unsecured Notes	$	3,409	$	3,406

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, 2016		December 31, 2015
2019 First Lien Term Loan	$	—	$	795
2020 First Lien Term Loan	—		378
2022 First Lien Term Loan	1,565		1,571
2023 First Lien Term Loan	531		533
New 2023 First Lien Term Loan	546		—
Total First Lien Term Loans	$	2,642	$	3,277

On May 31, 2016, we entered into a $562 million first lien senior secured term loan which bears interest, at our option, at either (i) the Base Rate, equal to the highest of (a) the Federal Funds Effective Rate plus 0.50% per annum, (b) the Prime Rate or (c) the Eurodollar Rate for a one month interest period plus 1.0% (in each case, as such terms are defined in the New 2023 First Lien Term Loan credit agreement), plus an applicable margin of 2.00%, or (ii) LIBOR plus 3.00% per annum (with no LIBOR floor) and matures on May 31, 2023. We paid an upfront fee of an amount equal to 1.0% of the aggregate principal amount of the New 2023 First Lien Term Loan, which is structured as original issue discount and recorded approximately $11 million in deferred financing costs during the three months ended June 30, 2016 related to the issuance of our New 2023 First Lien Term Loan. The New 2023 First Lien Term Loan contains substantially similar covenants, qualifications, exceptions and limitations as the First Lien Term Loans and the First Lien Notes.

We used the proceeds from the New 2023 First Lien Term Loan and the 2026 First Lien Notes, discussed below, to repay the 2019 and 2020 First Lien Term Loans and recorded $15 million in debt extinguishment costs during the three months ended June 30, 2016 associated with the repayment.

First Lien Notes

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



	June 30, 2016		December 31, 2015
2022 First Lien Notes	$	738	$	737
2023 First Lien Notes	569		568
2024 First Lien Notes	484		484
2026 First Lien Notes	616		—
Total First Lien Notes	$	2,407	$	1,789

On May 31, 2016, we issued $625 million in aggregate principal amount of 5.25% senior secured notes due 2026 in a private placement. Our 2026 First Lien Notes bear interest at 5.25% payable semi-annually on June 1 and December 1 of each year, beginning on December 1, 2016. Our 2026 First Lien Notes mature on June 1, 2026 and contain substantially similar covenants, qualifications, exceptions and limitations as our First Lien Notes. We recorded approximately $9 million in deferred financing costs during the three months ended June 30, 2016 related to the issuance of our 2026 First Lien Notes.

Corporate Revolving Facility and Other Letter of Credit Facilities

The table below represents amounts issued under our letter of credit facilities at June 30, 2016 and December 31, 2015 (in millions):



	June 30, 2016		December 31, 2015
Corporate Revolving Facility⁽¹⁾	$	304	$	316
CDHI	261		241
Various project financing facilities	212		198
Total	$	777	$	755

____________


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

On February 8, 2016, we amended our Corporate Revolving Facility, extending the maturity by two years to June 27, 2020, and increasing the capacity by an additional $178 million to $1,678 million through June 27, 2018, reverting back to $1,520 million through the maturity date. Further, we increased the letter of credit sublimit by $250 million to $1.0 billion and extended the maturity by two years to June 27, 2020.

Fair Value of Debt

We record our debt instruments based on contractual terms, net of any applicable premium or discount. The following table details the fair values and carrying values of our debt instruments at June 30, 2016 and December 31, 2015 (in millions):



	June 30, 2016				December 31, 2015
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Unsecured Notes	$	3,357	$	3,409	$	3,063	$	3,406
First Lien Term Loans	2,662		2,642		3,197		3,277
First Lien Notes	2,531		2,407		1,885		1,789
Project financing, notes payable and other⁽¹⁾	1,595		1,551		1,653		1,608
CCFC Term Loans	1,537		1,559		1,494		1,565
Total	$	11,682	$	11,568	$	11,292	$	11,645

____________


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

We measure the fair value of our Senior Unsecured Notes, First Lien Term Loans, First Lien Notes and CCFC Term Loans using market information, including quoted market prices or dealer quotes for the identical liability when traded as an asset (categorized as level 2). We measure the fair value of our project financing, notes payable and other debt instruments using discounted cash flow analyses based on our current borrowing rates for similar types of borrowing arrangements (categorized as level 3). We do not have any debt instruments with fair value measurements categorized as level 1 within the fair value hierarchy.


5.	Assets and Liabilities with Recurring Fair Value Measurements

Cash Equivalents — Highly liquid investments which meet the definition of cash equivalents, primarily investments in money market accounts, 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. Our cash equivalents are classified within level 1 of the fair value hierarchy.

Margin Deposits and Margin Deposits Posted with Us by Our Counterparties — Margin deposits and margin deposits posted with us by our counterparties represent cash collateral paid between our counterparties and us to support our commodity contracts. Our margin deposits and margin deposits posted with us by our counterparties are generally cash and cash equivalents and 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 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 the impact of credit enhancements, if any. We have also recorded credit reserves in the determination of fair value based on our expectation of how market participants would determine fair value. Such valuation adjustments are generally based on market evidence, if available, or our best estimate.

Our level 1 fair value derivative instruments primarily consist of power and natural gas swaps, futures and options traded on the NYMEX or Intercontinental Exchange.

Our level 2 fair value derivative instruments primarily consist of interest rate hedging instruments and OTC power and natural gas forwards for which market-based pricing inputs in the principal or most advantageous market are representative of executable prices for market participants. These inputs are observable at commonly quoted intervals for substantially the full term of the instruments. In certain instances, our level 2 derivative instruments may utilize models to measure fair value. These models are industry-standard models that incorporate various assumptions, including quoted interest rates, correlation, volatility, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Our level 3 fair value derivative instruments may consist of OTC power and natural gas forwards and options where pricing inputs are unobservable, as well as other complex and structured transactions. 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 impact on the measurement of fair value, the instrument is categorized in level 3. Our valuation models may incorporate historical correlation information and extrapolate available broker and other information to future periods. OTC options are valued using industry-standard models, including the Black-Scholes option-pricing model. At each balance sheet date, we perform an analysis of all instruments subject to fair value measurement and include in level 3 all of those whose fair value is based on significant unobservable inputs.

For a definition of the different levels in the fair value hierarchy, see Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Application of Critical Accounting Policies — Fair Value Measurements” in our 2015 Form 10-K.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect our estimate of the fair value of our assets and liabilities and their placement within the fair value hierarchy levels. The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2016 and December 31, 2015, by level within the fair value hierarchy:



	Assets and Liabilities with Recurring Fair Value Measures as of June 30, 2016
	Level 1		Level 2		Level 3		Total
	(in millions)
Assets:
Cash equivalents⁽¹⁾	$	383	$	—	$	—	$	383
Margin deposits	134		—		—		134
Commodity instruments:
Commodity exchange traded futures and swaps contracts	1,316		—		—		1,316
Commodity forward contracts⁽²⁾	—		232		43		275
Interest rate hedging instruments	—		9		—		9
Total assets	$	1,833	$	241	$	43	$	2,117
Liabilities:
Margin deposits posted with us by our counterparties	$	9	$	—	$	—	$	9
Commodity instruments:
Commodity exchange traded futures and swaps contracts	1,248		—		—		1,248
Commodity forward contracts⁽²⁾	—		422		106		528
Interest rate hedging instruments	—		96		—		96
Total liabilities	$	1,257	$	518	$	106	$	1,881



	Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2015
	Level 1		Level 2		Level 3		Total
	(in millions)
Assets:
Cash equivalents⁽¹⁾	$	1,134	$	—	$	—	$	1,134
Margin deposits	89		—		—		89
Commodity instruments:
Commodity exchange traded futures and swaps contracts	1,736		—		—		1,736
Commodity forward contracts⁽²⁾	—		220		54		274
Interest rate hedging instruments	—		1		—		1
Total assets	$	2,959	$	221	$	54	$	3,234
Liabilities:
Margin deposits posted with us by our counterparties	$	35	$	—	$	—	$	35
Commodity instruments:
Commodity exchange traded futures and swaps contracts	1,604		—		—		1,604
Commodity forward contracts⁽²⁾	—		413		100		513
Interest rate hedging instruments	—		90		—		90
Total liabilities	$	1,639	$	503	$	100	$	2,242

___________


(1)	As of June 30, 2016 and December 31, 2015, we had cash equivalents of $215 million and $906 million included in cash and cash equivalents and $168 million and $228 million included in restricted cash, respectively.


(2)	Includes OTC swaps and options.

At June 30, 2016 and December 31, 2015, 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, 2016 and December 31, 2015:



	Quantitative Information about Level 3 Fair Value Measurements
	June 30, 2016
	Fair Value, Net Asset				Significant Unobservable
	(Liability)			Valuation Technique	Input	Range
	(in millions)
Power Contracts	$	(80	)	Discounted cash flow	Market price (per MWh)	$9.09 — $104.83/MWh
Power Congestion Products	$	17		Discounted cash flow	Market price (per MWh)	$(11.47) — $11.76/MWh

	December 31, 2015
	Fair Value, Net Asset				Significant Unobservable
	(Liability)			Valuation Technique	Input	Range
	(in millions)
Power Contracts	$	(54	)	Discounted cash flow	Market price (per MWh)	$6.72 — $83.25/MWh
Power Congestion Products	$	8		Discounted cash flow	Market price (per MWh)	$(11.47) — $12.19/MWh

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,
	2016			2015			2016			2015
Balance, beginning of period	$	(65	)	$	203		$	(46	)	$	85
Realized and mark-to-market gains (losses):
Included in net income (loss):
Included in operating revenues⁽¹⁾	(174		)	45			(181		)	176
Included in fuel and purchased energy expense⁽²⁾	165			—			155			2
Purchases and settlements:
Purchases	4			2			5			4
Settlements	(1		)	(10		)	(4		)	(21		)
Transfers in and/or out of level 3⁽³⁾:
Transfers into level 3⁽⁴⁾	—			—			—			—
Transfers out of level 3⁽⁵⁾	8			3			8			(3		)
Balance, end of period	$	(63	)	$	243		$	(63	)	$	243
Change in unrealized gains (losses) relating to instruments still held at end of period	$	(9	)	$	45		$	(26	)	$	178

___________


(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, 2016 and 2015.


(4)	There were no transfers out of level 2 into level 3 for each of the three and six months ended June 30, 2016 and 2015.


(5)	We had $(8) million and $(3) million in losses transferred out of level 3 into level 2 for the three months ended June 30, 2016 and 2015, respectively, and $(8) million in losses and $3 million in gains transferred out of level 3 into level 2 for the six months ended June 30, 2016 and 2015, respectively, due to changes in market liquidity in various power markets.


6.	Derivative Instruments

Types of Derivative Instruments and Volumetric Information

Commodity Instruments — We are exposed to changes in prices for the purchase and sale of power, natural gas, fuel oil, environmental products and other energy commodities. We use derivatives, which include physical commodity contracts and financial commodity instruments such as OTC and exchange traded swaps, futures, options, forward agreements and instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) or instruments that settle on power price relationships between delivery points for the purchase and sale of power and natural gas to attempt to maximize the risk-adjusted returns by economically hedging a portion of the commodity price risk associated with our assets. By entering into these transactions, we are able to economically hedge a portion of our Spark Spread at estimated generation and prevailing price levels.

We also engage in limited trading activities related to our commodity derivative portfolio as authorized by our Board of Directors and monitored by our Chief Risk Officer and Risk Management Committee of senior management. These transactions are executed primarily for the purpose of providing improved price and price volatility discovery, greater market access, and profiting from our market knowledge, all of which benefit our asset hedging activities. Our trading gains and losses were not material for each of the three and six months ended June 30, 2016 and 2015.

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, 2016, the maximum length of time over which we were hedging using interest rate hedging instruments designated as cash flow hedges was 7 years.

As of June 30, 2016 and December 31, 2015, the net forward notional buy (sell) position of our outstanding commodity and interest rate hedging instruments that did not qualify or were not designated under the normal purchase normal sale exemption were as follows (in millions):



Derivative Instruments	Notional Amounts
Derivative Instruments	June 30, 2016				December 31, 2015
Power (MWh)	(48		)		(41		)
Natural gas (MMBtu)	1,038				996
Environmental credits (Tonnes)	18				8
Interest rate hedging instruments	$	3,798		⁽¹⁾	$	1,320

___________


(1)	We entered into interest rate hedging instruments during the second quarter of 2016 to hedge approximately $2.5 billion of variable rate corporate debt for 2017 through 2019 which effectively places a ceiling on LIBOR at rates varying from 1.44% to 1.8125% for hedged interest payments. See Note 4 for a further discussion of our First Lien Term Loans.

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. Currently, we do not believe that it is probable that any additional collateral posted as a result of a one credit notch downgrade from its current level would be material. The aggregate fair value of our derivative liabilities with credit risk-related contingent provisions as of June 30, 2016, was $129 million for which we have posted collateral of $14 million by posting margin deposits or granting additional first priority liens on the assets currently subject to first priority liens under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. However, if our credit rating were downgraded by one notch from its current level, we estimate that additional collateral of $8 million would be required and that no counterparty could request immediate, full settlement.

Accounting for Derivative Instruments

We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Condensed Statements of Operations until the period of delivery. Revenues and expenses derived from instruments that qualified for hedge accounting or represent an economic hedge are recorded in the same financial statement line item as the item being hedged. Hedge accounting requires us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting. We present the cash flows from our derivatives in the same category as the item being hedged (or economically

hedged) within operating activities on our Consolidated Condensed Statements of Cash Flows unless they contain an other-than-insignificant financing element in which case their cash flows are classified within financing activities.

Cash Flow Hedges — We only apply hedge accounting to our interest rate hedging instruments. We report the effective portion of the mark-to-market gain or loss on our interest rate hedging instruments designated and qualifying as a cash flow hedging instrument as a component of OCI and reclassify such gains and losses into earnings in the same period during which the hedged forecasted transaction affects earnings. Gains and losses due to ineffectiveness on interest rate hedging instruments are recognized currently in earnings as a component of interest expense. If it is determined that the forecasted transaction is no longer probable of occurring, then hedge accounting will be discontinued prospectively and future changes in fair value are recorded in earnings. If the hedging instrument is terminated or de-designated prior to the occurrence of the hedged forecasted transaction, the net accumulated gain or loss associated with the changes in fair value of the hedge instrument remains deferred in AOCI until such time as the forecasted transaction impacts 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 power and Heat Rate swaps and options) and fuel and purchased energy expense (for natural gas, power, environmental product and fuel oil contracts, swaps and options). Changes in fair value of interest rate derivatives not designated as hedging instruments are recognized currently in earnings as interest expense.

Derivatives Included on Our Consolidated Condensed Balance Sheets

The following tables present the fair values of our derivative instruments recorded on our Consolidated Condensed Balance Sheets by location and hedge type at June 30, 2016 and December 31, 2015 (in millions):



	June 30, 2016
	Commodity Instruments			Interest Rate Hedging Instruments			Total Derivative Instruments
Balance Sheet Presentation
Current derivative assets	$	1,231		$	—		$	1,231
Long-term derivative assets	360			9			369
Total derivative assets	$	1,591		$	9		$	1,600

Current derivative liabilities	$	1,323		$	37		$	1,360
Long-term derivative liabilities	453			59			512
Total derivative liabilities	$	1,776		$	96		$	1,872
Net derivative assets (liabilities)	$	(185	)	$	(87	)	$	(272	)



	December 31, 2015
	Commodity Instruments			Interest Rate Hedging Instruments			Total Derivative Instruments
Balance Sheet Presentation
Current derivative assets	$	1,698		$	—		$	1,698
Long-term derivative assets	312			1			313
Total derivative assets	$	2,010		$	1		$	2,011

Current derivative liabilities	$	1,697		$	37		$	1,734
Long-term derivative liabilities	420			53			473
Total derivative liabilities	$	2,117		$	90		$	2,207
Net derivative assets (liabilities)	$	(107	)	$	(89	)	$	(196	)



	June 30, 2016				December 31, 2015
	Fair Value of Derivative Assets		Fair Value of Derivative Liabilities		Fair Value of Derivative Assets		Fair Value of Derivative Liabilities
Derivatives designated as cash flow hedging instruments:
Interest rate hedging instruments	$	9	$	96	$	1	$	90
Total derivatives designated as cash flow hedging instruments	$	9	$	96	$	1	$	90

Derivatives not designated as hedging instruments:
Commodity instruments	$	1,591	$	1,776	$	2,010	$	2,117
Total derivatives not designated as hedging instruments	$	1,591	$	1,776	$	2,010	$	2,117
Total derivatives	$	1,600	$	1,872	$	2,011	$	2,207

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

The tables below set forth our net exposure to derivative instruments after offsetting amounts subject to a master netting arrangement with the same counterparty at June 30, 2016 and December 31, 2015 (in millions):



	June 30, 2016
	Gross Amounts Not Offset on the Consolidated Condensed Balance Sheets
	Gross Amounts Presented on our Consolidated Condensed Balance Sheets			Derivative Asset (Liability) not Offset on the Consolidated Condensed Balance Sheets			Margin/Cash (Received) Posted⁽¹⁾			Net Amount
Derivative assets:
Commodity exchange traded futures and swaps contracts	$	1,316		$	(1,237	)	$	(79	)	$	—
Commodity forward contracts	275			(232		)	(2		)	41
Interest rate hedging instruments	9			—			—			9
Total derivative assets	$	1,600		$	(1,469	)	$	(81	)	$	50
Derivative (liabilities):
Commodity exchange traded futures and swaps contracts	$	(1,248	)	$	1,237		$	11		$	—
Commodity forward contracts	(528		)	232			12			(284		)
Interest rate hedging instruments	(96		)	—			—			(96		)
Total derivative (liabilities)	$	(1,872	)	$	1,469		$	23		$	(380	)
Net derivative assets (liabilities)	$	(272	)	$	—		$	(58	)	$	(330	)



	December 31, 2015
	Gross Amounts Not Offset on the Consolidated Condensed Balance Sheets
	Gross Amounts Presented on our Consolidated Condensed Balance Sheets			Derivative Asset (Liability) not Offset on the Consolidated Condensed Balance Sheets			Margin/Cash (Received) Posted⁽¹⁾			Net Amount
Derivative assets:
Commodity exchange traded futures and swaps contracts	$	1,736		$	(1,602	)	$	(134	)	$	—
Commodity forward contracts	274			(202		)	(3		)	69
Interest rate hedging instruments	1			—			—			1
Total derivative assets	$	2,011		$	(1,804	)	$	(137	)	$	70
Derivative (liabilities):
Commodity exchange traded futures and swaps contracts	$	(1,604	)	$	1,602		$	2		$	—
Commodity forward contracts	(513		)	202			3			(308		)
Interest rate hedging instruments	(90		)	—			—			(90		)
Total derivative (liabilities)	$	(2,207	)	$	1,804		$	5		$	(398	)
Net derivative assets (liabilities)	$	(196	)	$	—		$	(132	)	$	(328	)

____________

(1)

Negative balances represent margin deposits posted with us by our counterparties related to our derivative activities that are subject to a master netting arrangement. Positive balances reflect margin deposits and natural gas and power prepayments posted by us with our counterparties related to our derivative activities that are subject to a master netting arrangement. See Note 7 for a further discussion of our collateral.

Derivatives Included on Our Consolidated Condensed Statements of Operations

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

The following tables detail the components of our total activity for both the net realized gain (loss) and the net mark-to-market gain (loss) recognized from our derivative instruments in earnings and where these components were recorded on our Consolidated Condensed Statements of Operations for the periods indicated (in millions):



	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Realized gain (loss)⁽¹⁾⁽²⁾
Commodity derivative instruments	$	63		$	104		$	181		$	163
Total realized gain (loss)	$	63		$	104		$	181		$	163

Mark-to-market gain (loss)⁽³⁾
Commodity derivative instruments	$	(36	)	$	(1	)	$	(131	)	$	69
Interest rate hedging instruments	—			—			1			1
Total mark-to-market gain (loss)	$	(36	)	$	(1	)	$	(130	)	$	70
Total activity, net	$	27		$	103		$	51		$	233

___________


(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 derivative activity related to the acquisition of Champion Energy.


(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,
	2016			2015			2016			2015
Realized and mark-to-market gain (loss)
Derivatives contracts included in operating revenues⁽¹⁾⁽²⁾	$	(272	)	$	115		$	(68	)	$	234
Derivatives contracts included in fuel and purchased energy expense⁽¹⁾⁽²⁾	299			(12		)	118			(2		)
Interest rate hedging instruments included in interest expense⁽³⁾	—			—			1			1
Total activity, net	$	27		$	103		$	51		$	233

___________


(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 derivative activity related to the acquisition of Champion Energy.


(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.

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⁾
	2016			2015		2016			2015			Affected Line Item on the Consolidated Condensed Statements of Operations
Interest rate hedging instruments⁽¹⁾⁽²⁾	$	(6	)	$	14	$	(11	)	$	(12	)	Interest expense



	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⁾
	2016			2015		2016			2015			Affected Line Item on the Consolidated Condensed Statements of Operations
Interest rate hedging instruments⁽¹⁾⁽²⁾	$	(18	)	$	8	$	(22	)	$	(24	)	Interest expense

____________


(1)	We did not record any material gain (loss) on hedge ineffectiveness related to our interest rate hedging instruments designated as cash flow hedges during the three and six months ended June 30, 2016 and 2015.


(2)	We recorded an income tax expense of nil for each of the three and six months ended June 30, 2016 and 2015, 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 $143 million and $127 million at June 30, 2016 and December 31, 2015, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $13 million and $11 million at June 30, 2016 and December 31, 2015, respectively.

We estimate that pre-tax net losses of $42 million would be reclassified from AOCI into interest expense during the next 12 months as the hedged transactions settle; however, the actual amounts that will be reclassified will likely vary based on changes in interest rates. Therefore, we are unable to predict what the actual reclassification from AOCI into earnings (positive or negative) will be for the next 12 months.


7.	Use of Collateral

We use margin deposits, prepayments and letters of credit as credit support with and from our counterparties for commodity procurement and risk management activities. In addition, we have granted additional first priority liens on the assets currently subject to first priority liens under various debt agreements as collateral under certain of our power and natural gas agreements

and certain of our interest rate hedging instruments in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to the counterparties under such agreements. The counterparties under such agreements share the benefits of the collateral subject to such first priority liens pro rata with the lenders under our various debt agreements.

The table below summarizes the balances outstanding under margin deposits, natural gas and power prepayments, and exposure under letters of credit and first priority liens for commodity procurement and risk management activities as of June 30, 2016 and December 31, 2015 (in millions):



	June 30, 2016		December 31, 2015
Margin deposits⁽¹⁾	$	134	$	89
Natural gas and power prepayments	35		34
Total margin deposits and natural gas and power prepayments with our counterparties⁽²⁾	$	169	$	123

Letters of credit issued	$	622	$	600
First priority liens under power and natural gas agreements⁽³⁾	231		382
First priority liens under interest rate hedging instruments	97		92
Total letters of credit and first priority liens with our counterparties	$	950	$	1,074

Margin deposits posted with us by our counterparties⁽¹⁾⁽⁴⁾	$	9	$	35
Letters of credit posted with us by our counterparties	23		24
Total margin deposits and letters of credit posted with us by our counterparties	$	32	$	59

___________

(1)

Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated Condensed Balance Sheets. We do not offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation, and we do not offset amounts recognized for the right to reclaim, or the obligation to return, cash collateral with corresponding derivative instrument fair values. See Note 6 for further discussion of our derivative instruments subject to master netting arrangements.


(2)	At June 30, 2016 and December 31, 2015, $159 million and $101 million, respectively, were included in margin deposits and other prepaid expense and $10 million and $22 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets.


(3)	Includes $203 million and $345 million related to first priority liens under power supply contracts associated with our retail hedging activities at June 30, 2016 and December 31, 2015, respectively.


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

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


8.	Income Taxes

Income Tax Expense (Benefit)

The table below shows our consolidated income tax expense (benefit) from continuing operations (excluding noncontrolling interest) and our effective tax rates for the periods indicated (in millions):



	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Income tax expense (benefit)	$	(14	)	$	5		$	21		$	4
Effective tax rate	33		%	21		%	(10		)%	31		%

Our income tax rates do not bear a customary relationship to statutory income tax rates primarily as a result of the impact of our NOLs, changes in unrecognized tax benefits and valuation allowances. For the three and six months ended June 30, 2016 and 2015, 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. See Note 10 in our 2015 Form 10-K for further information regarding our NOLs.

Income Tax Audits — We remain subject to periodic audits and reviews by taxing authorities; however, we do not expect these audits will have a material effect on our tax provision. Any NOLs we claim in future years to reduce taxable income could be subject to IRS examination regardless of when the NOLs occurred. Any adjustment of state or federal returns would likely result in a reduction of deferred tax assets rather than a cash payment of income taxes in tax jurisdictions where we have NOLs.

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, 2016, we had unrecognized tax benefits of $58 million. If recognized, $18 million of our unrecognized tax benefits could impact the annual effective tax rate and $40 million, related to deferred tax assets, could be offset against the recorded valuation allowance resulting in no impact on our effective tax rate. We had accrued interest and penalties of $13 million for income tax matters at June 30, 2016. 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 $18 million in unrecognized tax benefits could occur within the next twelve months.


9.	Earnings (Loss) per Share

We include restricted stock units for which no future service is required as a condition to the delivery of the underlying common stock in our calculation of weighted average shares outstanding. As we incurred a net loss for each of the three and six months ended June 30, 2016, diluted loss per share for both periods is computed on the same basis as basic loss per share, as the inclusion of any other potential shares outstanding would be anti-dilutive. Reconciliations of the amounts used in the basic and diluted earnings (loss) per common share computations for the three and six months ended June 30, 2016 and 2015 are as follows (shares in thousands):



	Three Months Ended June 30,		Six Months Ended June 30,
	2016	2015	2016	2015
Diluted weighted average shares calculation:
Weighted average shares outstanding (basic)	354,066	366,975	353,784	369,938
Share-based awards	—	2,971	—	3,466
Weighted average shares outstanding (diluted)	354,066	369,946	353,784	373,404

We excluded the following items from diluted earnings (loss) per common share for the three and six months ended June 30, 2016 and 2015, because they were anti-dilutive (shares in thousands):



	Three Months Ended June 30,		Six Months Ended June 30,
	2016	2015	2016	2015
Share-based awards	3,335	5,042	3,294	5,042


10.	Stock-Based Compensation

Equity Classified Share-Based Awards

Stock-based compensation expense recognized for our equity classified share-based awards was $8 million and $7 million for the three months ended June 30, 2016 and 2015, respectively, and $15 million and $16 million for the six months ended June 30, 2016 and 2015, respectively. We did not record any significant tax benefits related to stock-based compensation expense in any period as we are not benefiting from a significant portion of our deferred tax assets, including deductions related to stock-based compensation expense. In addition, we did not capitalize any stock-based compensation expense as part of the cost of an asset for the six months ended June 30, 2016 and 2015. At June 30, 2016, there was unrecognized compensation cost of $38 million related

to restricted stock which is expected to be recognized over a weighted average period of 1.7 years. We issue new shares from our share reserves set aside for the Calpine Equity Incentive Plans when stock options are exercised and for other share-based awards.

A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the six months ended June 30, 2016, is as follows:



	Number of Restricted Stock Awards	Weighted Average Grant-Date Fair Value
Nonvested — December 31, 2015	3,528,270	$	19.91
Granted	2,941,831	$	12.40
Forfeited	166,018	$	16.32
Vested	1,275,797	$	19.01
Nonvested — June 30, 2016	5,028,286	$	15.86

The total fair value of our restricted stock and restricted stock units that vested during the six months ended June 30, 2016 and 2015 was approximately $16 million and $33 million, respectively.

Liability Classified Share-Based Awards

During the first quarter of 2016, our Board of Directors approved the award of performance share units to certain senior management employees. These performance share units will be settled in cash with payouts based on the relative performance of Calpine’s TSR over the three-year performance period of January 1, 2016 through December 31, 2018 compared with the TSR performance of the S&P 500 companies over the same period, as modified by the IPP Sector Modifier which may either increase or decrease the payout based on Calpine’s TSR within its IPP Peers. The performance share units vest on the last day of the performance period and will be settled in cash; thus, these awards are liability classified and are measured at fair value using a Monte Carlo simulation model at each reporting date until settlement. Stock-based compensation expense recognized related to our liability classified share-based awards was nil and $(6) million for the three months ended June 30, 2016 and 2015, respectively, and $2 million and $(4) million for the six months ended June 30, 2016 and 2015, respectively.

A summary of our performance share unit activity for the six months ended June 30, 2016, is as follows:



	Number of Performance Share Units	Weighted Average Grant-Date Fair Value
Nonvested — December 31, 2015	517,906	$	23.36
Granted	657,807	$	14.81
Vested⁽¹⁾	3,249	$	23.91
Nonvested — June 30, 2016	1,172,464	$	18.56

___________


(1)	In accordance with the applicable performance share unit agreements, performance share units granted to employees who meet the retirement eligibility requirements stipulated in the Equity Plan are fully vested upon the later of the date on which the employee becomes eligible to retire or one-year anniversary of the grant date.

For a further discussion of the Calpine Equity Incentive Plans, see Note 12 in our 2015 Form 10-K.


11.	Commitments and Contingencies

Litigation

We are party to various litigation matters, including regulatory and administrative proceedings arising out of the normal course of business. At the present time, we do not expect that the outcome of any of these proceedings, individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.

On a quarterly basis, we review our litigation activities and determine if an unfavorable outcome to us is considered “remote,” “reasonably possible” or “probable” as defined by U.S. GAAP. Where we determine an unfavorable outcome is probable and is reasonably estimable, we accrue for potential litigation losses. The liability we may ultimately incur with respect to such

litigation matters, in the event of a negative outcome, may be in excess of amounts currently accrued, if any; however, we do not expect that the reasonably possible outcome of these litigation matters would, individually or in the aggregate, have a material adverse effect on our financial condition, results of operations or cash flows. Where we determine an unfavorable outcome is not probable or reasonably estimable, we do not accrue for any potential litigation loss. The ultimate outcome of these litigation matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated. As a result, we give no assurance that such litigation matters would, individually or in the aggregate, not have a material adverse effect on our financial condition, results of operations or cash flows.

Environmental Matters

We are subject to complex and stringent environmental laws and regulations related to the operation of our power plants. On occasion, we may incur environmental fees, penalties and fines associated with the operation of our power plants. At the present time, we do not have environmental violations or other matters that would have a material impact on our financial condition, results of operations or cash flows or that would significantly change our operations.

Bay Area Air Quality Management District (“BAAQMD”). On March 13, 2014, the Hearing Board of the BAAQMD entered into a stipulated conditional order for abatement agreed to by Russell City Energy Company, LLC (“RCEC”), our indirect, majority-owned subsidiary, and the BAAQMD concerning a violation of the vendor-guaranteed water droplet drift rate for RCEC’s cooling tower discovered during initial performance testing. RCEC installed additional drift eliminators and came into compliance with its water droplet drift rate on April 17, 2014. The BAAQMD issued a notice of violation for this event on April 24, 2015. We have reached a resolution of this issue with the BAAQMD, which will not have a material impact on our financial condition, results of operations or cash flows.


12.	Segment Information

We assess our business on a regional basis due to the impact on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors impacting supply and demand. At June 30, 2016, our reportable segments were West (including geothermal), Texas and East (including Canada). We continue to evaluate the optimal manner in which we assess our performance including our segments and future changes may result in changes to the composition of our geographic segments. Commodity Margin is a key operational measure reviewed by our chief operating decision maker to assess the performance of our segments. The tables below show our financial data for our segments for the periods indicated (in millions).



	Three Months Ended June 30, 2016
	West			Texas		East			Consolidation and Elimination			Total
Revenues from external customers	$	211		$	530	$	423		$	—		$	1,164
Intersegment revenues	1			4		4			(9		)	—
Total operating revenues	$	212		$	534	$	427		$	(9	)	$	1,164
Commodity Margin	$	254		$	160	$	243		$	—		$	657
Add: Mark-to-market commodity activity, net and other⁽¹⁾	(62		)	7		28			(8		)	(35		)
Less:
Plant operating expense	98			85		96			(8		)	271
Depreciation and amortization expense	56			53		53			—			162
Sales, general and other administrative expense	8			14		12			1			35
Other operating expenses	7			2		10			(2		)	17
(Income) from unconsolidated investments in power plants	—			—		(3		)	—			(3		)
Income from operations	23			13		103			1			140
Interest expense, net of interest income												156
Debt extinguishment costs and other (income) expense, net												22
Loss before income taxes												$	(38	)



	Three Months Ended June 30, 2015
	West			Texas		East			Consolidation and Elimination			Total
Revenues from external customers	$	421		$	570	$	451		$	—		$	1,442
Intersegment revenues	—			5		2			(7		)	—
Total operating revenues	$	421		$	575	$	453		$	(7	)	$	1,442
Commodity Margin	$	240		$	170	$	247		$	—		$	657
Add: Mark-to-market commodity activity, net and other⁽¹⁾	(14		)	10		30			(7		)	19
Less:
Plant operating expense	120			82		77			(7		)	272
Depreciation and amortization expense	65			50		45			—			160
Sales, general and other administrative expense	6			15		9			—			30
Other operating expenses	10			2		8			—			20
(Income) from unconsolidated investments in power plants	—			—		(7		)	—			(7		)
Income from operations	25			31		145			—			201
Interest expense, net of interest income												157
Debt modification costs and other (income) expense, net												18
Income before income taxes												$	26



	Six Months Ended June 30, 2016
	West			Texas			East			Consolidation and Elimination			Total
Revenues from external customers	$	635		$	1,062		$	1,082		$	—		$	2,779
Intersegment revenues	3			7			7			(17		)	—
Total operating revenues	$	638		$	1,069		$	1,089		$	(17	)	$	2,779
Commodity Margin	$	451		$	313		$	473		$	—		$	1,237
Add: Mark-to-market commodity activity, net and other⁽²⁾	(16		)	(103		)	7			(14		)	(126		)
Less:
Plant operating expense	189			171			180			(14		)	526
Depreciation and amortization expense	125			106			111			—			342
Sales, general and other administrative expense	18			30			24			1			73
Other operating expenses	15			4			20			(2		)	37
(Income) from unconsolidated investments in power plants	—			—			(10		)	—			(10		)
Income (loss) from operations	88			(101		)	155			1			143
Interest expense, net of interest income													312
Debt extinguishment costs and other (income) expense, net													28
Loss before income taxes													$	(197	)



	Six Months Ended June 30, 2015
	West		Texas		East			Consolidation and Elimination			Total
Revenues from external customers	$	936	$	1,151	$	1,001		$	—		$	3,088
Intersegment revenues	2		8		4			(14		)	—
Total operating revenues	$	938	$	1,159	$	1,005		$	(14	)	$	3,088
Commodity Margin	$	458	$	319	$	415		$	—		$	1,192
Add: Mark-to-market commodity activity, net and other⁽²⁾	105		51		(22		)	(14		)	120
Less:
Plant operating expense	226		171		149			(14		)	532
Depreciation and amortization expense	132		99		87			—			318
Sales, general and other administrative expense	16		32		19			—			67
Other operating expenses	20		4		16			—			40
(Income) from unconsolidated investments in power plants	—		—		(12		)	—			(12		)
Income from operations	169		64		134			—			367
Interest expense, net of interest income											310
Debt modification and extinguishment costs and other (income) expense, net											39
Income before income taxes											$	18

_________


(1)	Includes $(20) million and $(18) million of lease levelization and $27 million and $3 million of amortization expense for the three months ended June 30, 2016 and 2015, respectively.


(2)	Includes $(42) million and $(42) million of lease levelization and $54 million and $7 million of amortization expense for the six months ended June 30, 2016 and 2015, 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

We are one of the largest power generators in the U.S. measured by power produced. We own and operate primarily natural gas-fired and geothermal power plants in North America and have a significant presence in major competitive wholesale power markets in California (included in our West segment), Texas (included in our Texas segment) and the Northeast and Mid-Atlantic regions (included in our East segment) of the U.S. We sell power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities and other governmental entities, power marketers as well as retail commercial, industrial, governmental and residential customers. We have invested in clean power generation to become a recognized leader in developing, constructing, owning and operating an environmentally responsible portfolio of flexible and reliable power plants.

In order to manage our various physical assets and contractual obligations, we execute commodity and commodity transportation agreements within the guidelines of our Risk Management Policy. We purchase primarily natural gas and some fuel oil as fuel for our power plants and engage in related natural gas transportation and storage transactions. We purchase electric transmission rights to deliver power to our customers. We also enter into natural gas, power, environmental product, fuel oil and other physical and financial commodity contracts to hedge certain business risks and optimize our portfolio of power plants. Seasonality and weather can have a significant impact on our results of operations and are also considered in our hedging and optimization activities.

Our capital allocation philosophy seeks to maximize levered cash returns to equity while maintaining a strong balance sheet. We strive to enhance shareholder value through the combination of investing for growth at attractive returns, managing the balance sheet through debt pay down and returning capital to shareholders. We view our stock as an attractive investment opportunity, and we use the projected returns from share repurchases as the benchmark against which all other investment decisions are measured. We are committed to remaining fiscally disciplined and balanced in our capital allocation decisions.

Our goal is to be recognized as the premier power generation company in the U.S. as measured by our employees, shareholders, customers and policy-makers as well as the communities in which our facilities are located. We seek to achieve sustainable growth through financially disciplined power plant development, construction, acquisition, operation and ownership, and by pursuing opportunities to improve our fleet performance and reduce operating costs. We continue to make significant progress to deliver financially disciplined growth, to enhance shareholder value through disciplined capital allocation including the return of capital to shareholders and to manage the balance sheet for future growth and success with the following achievements during 2016:


•	We produced approximately 51 million MWh of electricity during the six months ended June 30, 2016.


•	Our employees achieved a total recordable incident rate of 0.86 recordable injuries per 100 employees during the first half of 2016 which places us in the first quartile performance for power generation companies with 1,000 or more employees.


•	Our entire fleet achieved a starting reliability of 97.5% during the six months ended June 30, 2016.

•

On February 5, 2016, we completed the purchase of Granite Ridge Energy Center, a power plant with a nameplate capacity of 745 MW (summer peaking capacity of 695 MW), for approximately $500 million, excluding working capital and other adjustments. The addition of this modern, efficient, natural gas-fired, combined-cycle power plant increased capacity in our East segment, specifically the constrained New England market.

•


•	On April 1, 2016, we entered into an asset sale agreement for the sale of substantially all of the assets comprising our South Point Energy Center to Nevada Power Company d/b/a NV Energy for approximately $76 million plus the

assumption by the purchaser of existing transmission capacity contracts with a future net present value payment obligation of approximately $112 million, approximately $9 million in remaining tribal lease costs and approximately $21 million in near-term repairs, maintenance and capital improvements to restore the power plant to full capacity. The sale is subject to certain conditions precedent, as well as federal and state regulatory approvals, and is expected to close no later than the first quarter of 2017. This transaction supports our effort to divest non-core assets outside our strategic concentration.


•	In May 2016, we repaid our 2019 and 2020 First Lien Term Loans with the proceeds from our New 2023 First Lien Term Loan and 2026 First Lien Notes which extended the maturity on approximately $1.2 billion of corporate debt.

•

We successfully originated new contracts with customers in our East segment related to our Morgan and RockGen Energy Centers and announced an expansion of the service territory for Champion Energy. We also satisfied final regulatory approval requirements for a 20-year PPA, which will facilitate a 345 MW expansion of our Mankato Power Plant, and received final regulatory approval for a ten-year PPA associated with our Geysers Assets.

Our portfolio, including partnership interests, consists of 84 power plants, including one under construction, located throughout 19 states in the U.S. and in Canada, with an aggregate current generation capacity of 27,282 MW and 760 MW under construction. Our fleet, including projects under construction, consists of 68 natural gas-fired combustion turbine-based plants, one fuel oil-fired steam-based plant, 14 geothermal steam turbine-based plants and one photovoltaic solar plant. Our segments have an aggregate generation capacity of 7,425 MW in the West, 9,427 MW in Texas and 10,430 MW with an additional 760 MW under construction in the East.

Legislative and Regulatory Update

We are subject to complex and stringent energy, environmental and other laws and regulations at the federal, state and local levels as well as rules within the ISO and RTO markets in which we participate. Federal and state legislative and regulatory actions, including those by ISO/RTOs, continue to change how our business is regulated. We are actively participating in these debates at the federal, regional, state and ISO/RTO levels. Significant updates are discussed below. For a further discussion of the environmental and other governmental regulations that affect us, see “— Governmental and Regulatory Matters” in Part I, Item 1 of our 2015 Form 10-K.

CAISO

The CPUC and CAISO continue to evaluate capacity procurement policies and products for the California power market. With the expectation of significant increases in renewables, both entities are evaluating the need for operational flexibility, including the ability to start and ramp quickly as well as the ability to operate efficiently at low output levels or cycle off. We are an active participant in these discussions and support products and policies that would provide appropriate compensation for the required attributes. As these proceedings are ongoing, we cannot predict the ultimate impact on our financial condition, results of operations or cash flows, although we believe our fleet offers many features that can, and do, provide operational flexibility to the power markets.

In July 2016, we filed a protest with the FERC in response to a complaint filed against the CAISO on June 17, 2016 by the owner of a natural gas-fired power plant located in Kern County, California. Our protest requests the FERC to reject the relief sought in the complaint as a one-off solution to a larger problem and, rather, to convene a technical conference to consider whether the California wholesale power market allows modern, efficient natural gas-fired power plants that are needed for reliability and flexibility to recover their costs, including a return of, and on, capital and to consider necessary changes to the market structure to ensure revenue adequacy.

ERCOT

The PUCT is considering changes regarding its approach to resource adequacy, including price formation and scarcity pricing as operating reserves decline. ERCOT successfully launched the Operating Reserve Demand Curve (“ORDC”) functionality on June 1, 2014. This application produces a price “adder” to the clearing price of energy that increases as reserve capacity declines. The PUCT requested a review of the effectiveness of the ORDC and requested input from ERCOT and market participants, including any recommendations to improve the ORDC. The PUCT continues to consider the appropriate reliability standard that should be used to set ERCOT’s planning reserve margin. As these proceedings are ongoing and the timing of these changes is uncertain, we cannot predict the ultimate impact on our financial condition, results of operations or cash flows.

PJM

On April 4, 2016, the Governor of Maryland signed into law the Reauthorization of the Greenhouse Gas Emissions Reduction Act which builds on the 2009 Greenhouse Gas Emissions Reduction Act that required a 25% reduction of GHG emissions from 2006 levels by 2020. The legislation requires the Maryland Department of the Environment (“MDE”), in coordination with other Maryland agencies, to develop plans, adopt regulations and implement programs to reduce GHGs. The legislation includes several “off ramps” designed to protect manufacturers and electric generators. Under the bill, the State must demonstrate MDE’s compliance plans will have a positive impact on Maryland’s economy and will protect existing manufacturing jobs.

Over significant opposition, on March 31, 2016, the Ohio Public Utility Commission voted unanimously to approve two out-of-market PPAs – one between American Electric Power, Inc. (“AEP”) and its generation affiliate and a second between FirstEnergy Corp. (“FE”) and its generation affiliate. It is expected that the Ohio Public Utility Commission decision will be appealed to the Ohio Supreme Court. Separately, three complaints regarding the AEP and FE PPAs were filed with the FERC. On April 27, 2016, the FERC ruled on two of these complaints, rescinding certain waivers granted in the past to AEP and FE and finding that the AEP and FE PPAs are subject to FERC review and approval prior to transacting under them. AEP and FE were directed to file to modify their market-based rate tariffs to clarify that the affiliate sales restrictions will apply to the PPAs. A rehearing proceeding is in process at the Ohio Public Utility Commission where FE is seeking to recast the PPA in a manner that would obviate the need for FERC review. The hearings commenced on July 11, 2016, and the outcome remains uncertain. Neither AEP nor FE has filed at the FERC for approval of their PPAs.

Beginning several years ago, New Jersey and Maryland each directed their load serving entities to issue requests for proposals (“RFP”) for the construction of new natural gas-fired generation plants in their respective states and to enter into long term capacity contracts with the generators selected in the RFP process. Several generators and load serving entities challenged the New Jersey and Maryland actions in federal court and prevailed in their challenges against the states in federal district court and before the Third and Fourth Circuits of the U.S. Courts of Appeals, respectively. The states and one of the winning generators filed petitions for certiorari with the U.S. Supreme Court. On October 19, 2015, the U.S. Supreme Court granted certiorari for the appeal of the Fourth Circuit decision. On April 19, 2016, the U.S. Supreme Court issued a decision affirming the Fourth Circuit’s ruling and on April 25, 2016, dismissed the petitions for certiorari of the Third Circuit decision.

We believe the current competitive construct of the PJM power market whereby new construction of power generation facilities is determined by forward price signals and not ratepayer guaranteed rate recovery is the most efficient mechanism for incentivizing the construction of new power plants.

ISO-NE

ISO-NE continues to propose refinements to various aspects of its tariff that may affect overall market opportunities. Most recently, the FERC approved changes to the operation of the Forward Capacity Market in the New England Power Pool involving the use of revised demand curve parameters. The likelihood and potential impact of any pending proposals on our business is currently unknown.

Several New England states have regulations in place or are considering legislation that would allow their investor owned utilities to enter into long-term contracts for transportation capacity on new interstate pipelines and/or agreements for new Canadian hydro imports. We cannot predict at this time whether any of these state-sponsored initiatives will come to fruition. Thus, the impact these efforts may have on our business is currently unknown.

Independent Electricity System Operator (“IESO”)

Ontario is implementing a new GHG law with an associated Cap-and-Trade program which will become effective January 1, 2017. The result of this program will require power generators to either acquire related CO₂ allowances on their own behalf or, in most cases, the natural gas pipeline supplying the power generation facility will be required to procure such allowances and bill the power generator in the form of a CO₂ surcharge on its natural gas transportation invoice. Greenfield LP has a long-term Clean Energy Supply Contract with the IESO, successor to the Ontario Power Authority. We believe the contract contemplates and provides for the pass-through of CO₂ cost, although there has been some communications from the IESO which may indicate an alternative view. Greenfield LP is currently negotiating to remedy this matter prior to the January 1, 2017 effective date. As this issue is ongoing, we cannot predict the ultimate impact on our financial condition, results of operations or cash flows.

On a related note, Whitby has a PPA with the Ontario Electricity Financial Corporation, successor to Ontario Hydro and is also determining its position related to CO₂ cost.

Mercury and Air Toxics Standards (“MATS”) and Cross-State Air Pollution Rule (“CSAPR”)

MATS and CSAPR have been heavily litigated since their promulgation. On June 13, 2016, the U.S. Supreme Court denied a request to stay MATS which effectively ends the legal challenges to stop MATS from being implemented. CSAPR took effect on January 1, 2015 and there are no remaining substantive judicial challenges which could abrogate CSAPR. On April 25, 2016, the EPA published in the Federal Register the final, revised “necessary and appropriate” determination to address the narrow issue for which the U.S. Supreme Court, and subsequently the U.S. Court of Appeals for the District of Columbia Circuit (“D.C. Circuit”), had remanded the MATS rule to the EPA for further action. This effectively addresses previous litigation related to MATS, although this action itself is now the subject of further litigation.

MATS and CSAPR primarily impact coal-fired power plants; therefore, these rules do not directly affect our power plants. However, we believe that well-founded regulations protecting health and the environment could benefit our competitive position by better recognizing the value of our investments in clean power generation technology.

Clean Power Plan

The Clean Power Plan requires a reduction in GHG emissions from existing power plants of 32% from 2005 levels by 2030. Litigation challenging the Clean Power Plan is currently ongoing with oral arguments scheduled for September 27, 2016 in the D.C. Circuit. On February 9, 2016, the U.S. Supreme Court issued a stay of the Clean Power Plan until the D.C. Circuit issues a ruling on the merits and through final determination in any further appeal to the U.S. Supreme Court from the D.C. Circuit decision. Overall, we support the Clean Power Plan and believe we are well positioned to comply with its provisions. We expect the Clean Power Plan to be beneficial to Calpine.

Regional Haze

On July 15, 2016, the United States Court of Appeals for the Fifth Circuit issued a stay of the Federal Implementation Plan the EPA imposed on the state of Texas that would require installation of SO₂ emission controls on 16 units at nine coal-fired power plants in Texas and also denied the EPA’s motion to transfer the case to the D.C. Circuit. While this will not directly affect our fleet, it does have the potential to affect the power market in Texas because the affected facilities would either have to further reduce emissions or retire.

The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 ( the“Dodd-Frank Act”)

In June 2016, as mandated by the Dodd-Frank Act, the SEC adopted final rules requiring resource extraction issuers to report, on an annual basis, any payments made by the issuer to the U.S. Federal Government or a foreign government for the purpose of the commercial development of oil, natural gas or minerals. The annual disclosure filing of these payments must be made with the SEC for fiscal years ending after September 30, 2018.Therefore, for calendar year end companies, such as Calpine, the initial information must be provided to the SEC by May 30, 2019. We anticipate that we will be required to file a report disclosing the total amount of payments made to the U.S. Federal Government in conjunction with our geothermal leases from which we extract steam for our Geysers Assets.

RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED JUNE 30, 2016 AND 2015

Below are our results of operations for the three months ended June 30, 2016 as compared to the same period in 2015 (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.



	2016			2015			Change			% Change
Operating revenues:
Commodity revenue	$	1,551		$	1,407		$	144		10
Mark-to-market gain (loss)	(391		)	31			(422		)	#
Other revenue	4			4			—			—
Operating revenues	1,164			1,442			(278		)	(19	)
Operating expenses:
Fuel and purchased energy expense:
Commodity expense	897			734			(163		)	(22	)
Mark-to-market (gain) loss	(355		)	32			387			#
Fuel and purchased energy expense	542			766			224			29
Plant operating expense	271			272			1			—
Depreciation and amortization expense	162			160			(2		)	(1	)
Sales, general and other administrative expense	35			30			(5		)	(17	)
Other operating expenses	17			20			3			15
Total operating expenses	1,027			1,248			221			18
(Income) from unconsolidated investments in power plants	(3		)	(7		)	(4		)	(57	)
Income from operations	140			201			(61		)	(30	)
Interest expense	157			158			1			1
Interest (income)	(1		)	(1		)	—			—
Debt modification and extinguishment costs	15			13			(2		)	(15	)
Other (income) expense, net	7			5			(2		)	(40	)
Income (loss) before income taxes	(38		)	26			(64		)	#
Income tax expense (benefit)	(14		)	5			19			#
Net income (loss)	(24		)	21			(45		)	#
Net income attributable to the noncontrolling interest	(5		)	(2		)	(3		)	#
Net income (loss) attributable to Calpine	$	(29	)	$	19		$	(48	)	#



	2016		2015		Change		% Change
Operating Performance Metrics:
MWh generated (in thousands)⁽¹⁾⁽²⁾	26,355		26,954		(599	)	(2	)
Average availability⁽²⁾	85.6	%	86.0	%	(0.4	)%	—
Average total MW in operation⁽¹⁾	26,502		25,757		745		3
Average capacity factor, excluding peakers	50.2	%	53.4	%	(3.2	)%	(6	)
Steam Adjusted Heat Rate⁽²⁾	7,313		7,329		16		—

__________


#	Variance of 100% or greater


(1)	Represents generation and capacity from power plants that we both consolidate and operate and excludes Greenfield LP, Whitby, Freeport Energy Center, 21.5% of Hidalgo Energy Center and 25% each of Freestone Energy Center and Russell City Energy Center.


(2)	Generation, average availability and Steam Adjusted Heat Rate exclude power plants and units that are inactive.

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

Commodity revenue, net of Commodity expense, decreased $19 million for the three months ended June 30, 2016, compared to the same period in 2015, primarily due to:



(in millions)
$	40		A natural gas pipeline transportation billing credit received in the West segment
13			The impact of our portfolio management activities, including a full quarter of energy and capacity revenue associated with the operation of our 695 MW Granite Ridge Energy Center, which was acquired on February 5, 2016, and two additional months of energy and capacity revenue associated with the operation of our 309 MW Garrison Energy Center, which commenced commercial operations in June 2015
(53		)	Lower energy margins due to a decrease in generation and lower realized Spark Spreads primarily in our West segment, resulting from an increase in hydroelectric generation in the region and the expirations of the Pastoria Energy Center PPA and the Greenleaf operating lease, partially offset by the positive impact of a new PPA at our Morgan Energy Center in the East segment and an increase in generation in the Texas segment driven by higher market Spark Spreads and lower natural gas prices
(19		)	Contract amortization, lease levelization related to tolling contracts and other⁽¹⁾
$	(19	)

__________

(1)

Commodity Margin and Adjusted EBITDA exclude amortization expense related to contracts recorded at fair value, non-cash GAAP-related adjustments to levelize revenues from tolling agreements, Commodity revenue and Commodity expense attributable to the noncontrolling interest and other unusual or non-recurring items. See “Commodity Margin and Adjusted EBITDA” for a description of these Non-GAAP financial measures.

Mark-to-market gain/loss from hedging our future generation, retail activities and fuel needs had an unfavorable variance of $35 million primarily driven by increasing forward power and natural gas prices during the three months ended June 30, 2016.

Our normal, recurring plant operating expense decreased by $7 million for the three months ended June 30, 2016 compared to the same period in 2015 after excluding a $12 million increase attributable to power plant portfolio changes and our acquisition of Champion Energy, a $10 million decrease in major maintenance expense resulting from our plant outage schedule net of cost from scrap parts related to outages and a $4 million increase in stock-based compensation expense and other miscellaneous items.

Sales, general and other administrative expense increased by $5 million for the three months ended June 30, 2016, compared to the same period in 2015, primarily due to a decrease in fair value of our performance share units during the three months ended June 30, 2015.

Income from unconsolidated investments in power plants decreased by $4 million for the three months ended June 30, 2016, compared to the same period in 2015, primarily due to higher major maintenance costs at Greenfield LP associated with a planned outage during the second quarter of 2016.

Debt extinguishment costs for the three months ended June 30, 2016, consisted of $15 million from the write-off of deferred financing costs in connection with the repayment of our 2019 and 2020 First Lien Term Loans in May 2016. Debt modification costs for the three months ended June 30, 2015 consisted of $13 million in costs related to the issuance of our 2022 First Lien Term Loan in May 2015.

During the three months ended June 30, 2016, we recorded an income tax benefit of $14 million compared to an income tax expense of $5 million for the three months ended June 30, 2015. The favorable period-over-period change primarily resulted from our pre-tax loss during the three months ended June 30, 2016 compared to our pre-tax income in the same period in 2015.

RESULTS OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2016 AND 2015

Below are our results of operations for the six months ended June 30, 2016 as compared to the same period in 2015 (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.



	2016			2015			Change			% Change
Operating revenues:
Commodity revenue	$	3,136		$	3,045		$	91		3
Mark-to-market gain (loss)	(366		)	34			(400		)	#
Other revenue	9			9			—			—
Operating revenues	2,779			3,088			(309		)	(10	)
Operating expenses:
Fuel and purchased energy expense:
Commodity expense	1,903			1,811			(92		)	(5	)
Mark-to-market (gain)	(235		)	(35		)	200			#
Fuel and purchased energy expense	1,668			1,776			108			6
Plant operating expense	526			532			6			1
Depreciation and amortization expense	342			318			(24		)	(8	)
Sales, general and other administrative expense	73			67			(6		)	(9	)
Other operating expenses	37			40			3			8
Total operating expenses	2,646			2,733			87			3
(Income) from unconsolidated investments in power plants	(10		)	(12		)	(2		)	(17	)
Income from operations	143			367			(224		)	(61	)
Interest expense	314			312			(2		)	(1	)
Interest (income)	(2		)	(2		)	—			—
Debt modification and extinguishment costs	15			32			17			53
Other (income) expense, net	13			7			(6		)	86
Income (loss) before income taxes	(197		)	18			(215		)	#
Income tax expense	21			4			(17		)	#
Net income (loss)	(218		)	14			(232		)	#
Net income attributable to the noncontrolling interest	(9		)	(5		)	(4		)	(80	)
Net income (loss) attributable to Calpine	$	(227	)	$	9		$	(236	)	#



	2016		2015		Change		% Change
Operating Performance Metrics:
MWh generated (in thousands)⁽¹⁾⁽²⁾	50,480		52,521		(2,041	)	(4	)
Average availability⁽²⁾	87.8	%	87.7	%	0.1	%	—
Average total MW in operation⁽¹⁾	26,370		25,763		607		2
Average capacity factor, excluding peakers	48.8	%	52.7	%	(3.9	)%	(7	)
Steam Adjusted Heat Rate⁽²⁾	7,289		7,296		7		—

__________


#	Variance of 100% or greater


(1)	Represents generation and capacity from power plants that we both consolidate and operate and excludes Greenfield LP, Whitby, Freeport Energy Center, 21.5% of Hidalgo Energy Center and 25% each of Freestone Energy Center and Russell City Energy Center.


(2)	Generation, average availability and Steam Adjusted Heat Rate exclude power plants and units that are inactive.

Commodity revenue, net of Commodity expense, decreased $1 million for the six months ended June 30, 2016, compared to the same period in 2015, primarily due to:



(in millions)
$	40		A natural gas pipeline transportation billing credit received in the West segment
24			The impact of our portfolio management activities, including approximately five months of energy and capacity revenue associated with both our 695 MW Granite Ridge Energy Center, which was acquired on February 5, 2016, and our 309 MW Garrison Energy Center, which commenced commercial operations in June 2015
14			Higher regulatory capacity revenue primarily in PJM and ISO-NE at our power plants which were fully operational period-over-period
(33		)	Lower energy margins due to a decrease in generation and lower realized Spark Spreads primarily in our West segment, resulting from an increase in hydroelectric generation in the region and the expirations of the Pastoria Energy Center PPA and the Greenleaf operating lease, partially offset by the positive impact of a new PPA associated with our Morgan Energy Center in the East segment and increased contribution from hedging activity, including retail
(46		)	Contract amortization, lease levelization related to tolling contracts and other⁽¹⁾
$	(1	)

__________

(1)

Mark-to-market gain/loss from hedging our future generation, retail activities and fuel needs had an unfavorable variance of $200 million primarily driven by increasing forward power and natural gas prices during the six months ended June 30, 2016.

Our normal, recurring plant operating expense decreased by $10 million for the six months ended June 30, 2016 compared to the same period in 2015 after excluding a $22 million increase attributable to power plant portfolio changes and our acquisition of Champion Energy, a $24 million decrease in major maintenance expense resulting from our plant outage schedule net of cost from scrap parts related to outages and a $6 million increase in stock-based compensation expense and other miscellaneous items.

Depreciation and amortization expense increased by $24 million for the six months ended June 30, 2016, compared to the same period in 2015, primarily due to a $22 million increase resulting from the acquisitions of Granite Ridge Energy Center and Champion Energy as well as the commencement of commercial operations at our Garrison Energy Center in June 2015.

Sales, general and other administrative expense increased by $6 million for the six months ended June 30, 2016, compared to the same period in 2015, primarily due to a $4 million decrease associated with the a decrease in fair value of our performance share units during the six months ended June 30, 2015.

Debt extinguishment costs for the six months ended June 30, 2016, consisted of $15 million from the write-off of deferred financing costs in connection with the repayment of our 2019 and 2020 First Lien Term Loans in May 2016. Debt modification and extinguishment costs for the six months ended June 30, 2015, consisted of $19 million in connection with the repurchase of approximately $147 million of our 2023 First Lien Notes, which comprised of $18 million of prepayment penalties and $1 million associated with the write-off of deferred financing costs, and $13 million in costs related to the issuance of our 2022 First Lien Term Loan in May 2015.

Other (income) expense, net increased by $6 million for the six months ended June 30, 2016, compared to the same period in 2015, due to a $3 million increase related to credit fees associated with our retail operations and a $3 million increase resulting from a foreign currency translation loss related to our Canadian subsidiaries in the six months ended June 30, 2016.

During the six months ended June 30, 2016, we recorded an income tax expense of $21 million compared to $4 million for the six months ended June 30, 2015. The unfavorable period-over-period change primarily resulted from estimated state income tax expense in jurisdictions where we do not have NOLs and estimated foreign tax expense.

COMMODITY MARGIN AND ADJUSTED EBITDA

Management’s Discussion and Analysis of Financial Condition and Results of Operations includes financial information prepared in accordance with U.S. GAAP, as well as the non-GAAP financial measures, Commodity Margin and Adjusted EBITDA, discussed below, which we use as measures of our performance. Generally, a non-GAAP financial measure is a numerical measure of financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with U.S. GAAP.

We use Commodity Margin, a non-GAAP financial measure, to assess our performance by our reportable segments. Commodity Margin includes our power and steam revenues, sales of purchased power and physical natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, environmental compliance expense, and realized settlements from our marketing, hedging, optimization and trading activities, but excludes mark-to-market activity and other revenues. We believe that Commodity Margin is a useful tool for assessing the performance of our core operations and is a key operational measure reviewed by our chief operating decision maker. Commodity Margin is not a measure calculated in accordance with U.S. GAAP and should be viewed as a supplement to and not a substitute for our results of operations presented in accordance with U.S. GAAP. Commodity Margin does not intend to represent income from operations, the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. See Note 12 of the Notes to Consolidated Condensed Financial Statements for a reconciliation of Commodity Margin to income (loss) from operations by segment.

Commodity Margin by Segment for the Three Months Ended June 30, 2016 and 2015

The following tables show our Commodity Margin and related operating performance metrics by segment for the three months ended June 30, 2016 and 2015 (exclusive of the noncontrolling interest). In the comparative tables below, favorable variances are shown without brackets while unfavorable variances are shown with brackets. The MWh generated by segment below represent generation from power plants that we both consolidate and operate. Generation, average availability and Steam Adjusted Heat Rate exclude power plants and units that are inactive.



West:	2016			2015			Change			% Change
Commodity Margin (in millions)	$	254		$	240		$	14		6
Commodity Margin per MWh generated	$	50.45		$	28.47		$	21.98		77

MWh generated (in thousands)	5,035			8,430			(3,395		)	(40	)
Average availability	85.6		%	82.8		%	2.8		%	3
Average total MW in operation	7,425			7,524			(99		)	(1	)
Average capacity factor, excluding peakers	33.1		%	54.7		%	(21.6		)%	(39	)
Steam Adjusted Heat Rate	7,316			7,325			9			—

West — Commodity Margin in our West segment increased by $14 million, or 6%, for the three months ended June 30, 2016 compared to the three months ended June 30, 2015, primarily due to the receipt of a natural gas transportation pipeline billing credit during the second quarter of 2016. The increase in Commodity Margin was partially offset by a decrease in generation and lower realized Spark Spreads resulting from an increase in hydroelectric generation in California and the Pacific Northwest, lower realized power prices at our Geysers Assets due to lower natural gas prices, the expiration of a PPA at our Pastoria Energy Center in December 2015 and the expiration of the operating lease related to the Greenleaf power plants in June 2015.



Texas:	2016			2015			Change			% Change
Commodity Margin (in millions)	$	160		$	170		$	(10	)	(6	)
Commodity Margin per MWh generated	$	12.92		$	15.19		$	(2.27	)	(15	)

MWh generated (in thousands)	12,387			11,194			1,193			11
Average availability	88.9		%	87.7		%	1.2		%	1
Average total MW in operation	9,191			9,191			—			—
Average capacity factor, excluding peakers	61.7		%	55.8		%	5.9		%	11
Steam Adjusted Heat Rate	7,138			7,078			(60		)	(1	)

Texas — Commodity Margin in our Texas segment decreased by $10 million, or 6%, for the three months ended June 30, 2016 compared to the three months ended June 30, 2015, primarily due to lower contribution from hedges, partially offset by higher contribution from our retail hedging activity and an increase in generation driven by higher Spark Spreads and lower natural gas prices.



East:	2016			2015			Change			% Change
Commodity Margin (in millions)	$	243		$	247		$	(4	)	(2	)
Commodity Margin per MWh generated	$	27.20		$	33.70		$	(6.50	)	(19	)

MWh generated (in thousands)	8,933			7,330			1,603			22
Average availability	82.4		%	87.0		%	(4.6		)%	(5	)
Average total MW in operation	9,886			9,042			844			9
Average capacity factor, excluding peakers	51.7		%	48.7		%	3.0		%	6
Steam Adjusted Heat Rate	7,570			7,738			168			2

East — Commodity Margin in our East segment decreased by $4 million, or 2%, for the three months ended June 30, 2016 compared to the three months ended June 30, 2015, primarily due to lower market Spark Spreads resulting from cooler weather in April 2016 and local natural gas price differentials. The decrease in Commodity Margin was partially offset by a full quarter of operation of our 695 MW Granite Ridge Energy Center, which was acquired on February 5, 2016, two additional months of operation of our 309 MW Garrison Energy Center, which commenced commercial operations in June 2015, higher contribution from our retail hedging activity and the positive impact of a new PPA associated with our Morgan Energy Center which became effective in February 2016.

Commodity Margin by Segment for the Six Months Ended June 30, 2016 and 2015

The following tables show our Commodity Margin and related operating performance metrics by segment for the six months ended June 30, 2016 and 2015 (exclusive of the noncontrolling interest). In the comparative tables below, favorable variances are shown without brackets while unfavorable variances are shown with brackets. The MWh generated by segment below represent generation from power plants that we both consolidate and operate. Generation, average availability and Steam Adjusted Heat Rate exclude power plants and units that are inactive.



West:	2016			2015			Change			% Change
Commodity Margin (in millions)	$	451		$	458		$	(7	)	(2	)
Commodity Margin per MWh generated	$	39.38		$	29.20		$	10.18		35

MWh generated (in thousands)	11,453			15,683			(4,230		)	(27	)
Average availability	88.0		%	85.6		%	2.4		%	3
Average total MW in operation	7,425			7,524			(99		)	(1	)
Average capacity factor, excluding peakers	38.0		%	51.2		%	(13.2		)%	(26	)
Steam Adjusted Heat Rate	7,324			7,314			(10		)	—

West — Commodity Margin in our West segment decreased by $7 million, or 2%, for the six months ended June 30, 2016 compared to the six months ended June 30, 2015, primarily due to a decrease in generation and lower realized Spark Spreads

resulting from an increase in hydroelectric generation in California and the Pacific Northwest, lower realized power prices at our Geysers Assets due to lower natural gas prices, the expiration of a PPA at our Pastoria Energy Center in December 2015 and the expiration of the operating lease related to the Greenleaf power plants in June 2015. The decrease in Commodity Margin was partially offset by the receipt of a natural gas transportation pipeline billing credit during the second quarter of 2016.



Texas:	2016			2015			Change			% Change
Commodity Margin (in millions)	$	313		$	319		$	(6	)	(2	)
Commodity Margin per MWh generated	$	13.24		$	14.03		$	(0.79	)	(6	)

MWh generated (in thousands)	23,636			22,738			898			4
Average availability	87.8		%	87.9		%	(0.1		)%	—
Average total MW in operation	9,191			9,191			—			—
Average capacity factor, excluding peakers	58.9		%	57.0		%	1.9		%	3
Steam Adjusted Heat Rate	7,095			7,087			(8		)	—

Texas — Commodity Margin in our Texas segment decreased by $6 million, or 2%, for the six months ended June 30, 2016 compared to the six months ended June 30, 2015, primarily due to lower contribution from hedges, partially offset by higher contribution from our retail hedging activity.



East:	2016			2015			Change			% Change
Commodity Margin (in millions)	$	473		$	415		$	58		14
Commodity Margin per MWh generated	$	30.73		$	29.43		$	1.30		4

MWh generated (in thousands)	15,391			14,100			1,291			9
Average availability	87.7		%	89.3		%	(1.6		)%	(2	)
Average total MW in operation	9,754			9,048			706			8
Average capacity factor, excluding peakers	46.3		%	48.3		%	(2.0		)%	(4	)
Steam Adjusted Heat Rate	7,581			7,629			48			1

East — Commodity Margin in our East segment increased by $58 million, or 14%, for the six months ended June 30, 2016 compared to the six months ended June 30, 2015, primarily due to higher contribution from hedges, including retail, and approximately five months of operation at both our 695 MW Granite Ridge Energy Center, which was acquired on February 5, 2016, and our 309 MW Garrison Energy Center, which commenced commercial operations in June 2015. Also contributing to the period-over-period increase in Commodity Margin was the positive impact of a new PPA associated with our Morgan Energy Center which became effective in February 2016 and higher regulatory capacity revenue in PJM and ISO-NE. The increase in Commodity Margin was partially offset by a decrease in generation at our power plants which were fully operational period-over-period due to lower market Spark Spreads primarily driven by milder weather in the first quarter of 2016.

Adjusted EBITDA

We define Adjusted EBITDA, a non-GAAP financial measure, as EBITDA adjusted for certain items described below and presented in the accompanying reconciliation. Adjusted EBITDA is not a measure calculated in accordance with U.S. GAAP, and should be viewed as a supplement to, and not a substitute for, our results of operations presented in accordance with U.S. GAAP. Adjusted EBITDA is not intended to represent cash flows from operations or net income (loss) as defined by U.S. GAAP as an indicator of operating performance. Furthermore, Adjusted EBITDA is not necessarily comparable to similarly-titled measures reported by other companies.

We believe Adjusted EBITDA is useful to investors and other users of our financial statements in evaluating our operating performance because it provides them with an additional tool to compare business performance across companies and across periods. We believe that EBITDA is widely used by investors to measure a company’s operating performance without regard to items such as interest expense, taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired.

Additionally, we believe that investors commonly adjust EBITDA information to eliminate the effect of restructuring and other expenses, which vary widely from company to company and impair comparability. As we define it, Adjusted EBITDA represents EBITDA adjusted for the effects of impairment losses, gains or losses on sales, dispositions or retirements of assets,

any mark-to-market gains or losses from accounting for derivatives, adjustments to exclude the Adjusted EBITDA related to the noncontrolling interest, stock-based compensation expense, operating lease expense, non-cash gains and losses from foreign currency translations, major maintenance expense, gains or losses on the repurchase, modification or extinguishment of debt, non-cash GAAP-related adjustments to levelize revenues from tolling agreements and any unusual or non-recurring items plus adjustments to reflect the Adjusted EBITDA from our unconsolidated investments. We adjust for these items in our Adjusted EBITDA as our management believes that these items would distort their ability to efficiently view and assess our core operating trends.

In summary, our management uses Adjusted EBITDA as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with our Board of Directors, shareholders, creditors, analysts and investors concerning our financial performance.

The tables below provide a reconciliation of Adjusted EBITDA to our income (loss) from operations on a segment basis and to net income (loss) attributable to Calpine on a consolidated basis for the periods indicated (in millions).



	Three Months Ended June 30, 2016
	West			Texas			East			Consolidation and Elimination			Total
Net loss attributable to Calpine													$	(29	)
Net income attributable to the noncontrolling interest													5
Income tax (benefit)													(14		)
Debt extinguishment costs and other (income) expense, net													22
Interest expense, net of interest income													156
Income from operations	$	23		$	13		$	103		$	1		$	140
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs⁽¹⁾	54			53			53			—			160
Major maintenance expense	23			27			29			—			79
Operating lease expense	—			—			7			—			7
Mark-to-market (gain) loss on commodity derivative activity	90			(21		)	(33		)	—			36
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest⁽²⁾	(5		)	—			12			—			7
Stock-based compensation expense	3			2			3			—			8
Loss on dispositions of assets	—			1			2			—			3
Contract amortization	1			21			5			—			27
Other	(17		)	2			1			(1		)	(15		)
Total Adjusted EBITDA	$	172		$	98		$	182		$	—		$	452



	Three Months Ended June 30, 2015
	West			Texas			East			Consolidation and Elimination		Total
Net income attributable to Calpine												$	19
Net income attributable to the noncontrolling interest												2
Income tax expense												5
Debt modification costs and other (income) expense, net												18
Interest expense, net of interest income												157
Income from operations	$	25		$	31		$	145		$	—	$	201
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs⁽¹⁾	65			49			45			—		159
Major maintenance expense	41			24			25			—		90
Operating lease expense	1			—			7			—		8
Mark-to-market (gain) loss on commodity derivative activity	40			(3		)	(36		)	—		1
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest⁽²⁾	(4		)	—			8			—		4
Stock-based compensation expense	1			—			—			—		1
Loss on dispositions of assets	—			2			—			—		2
Contract amortization	—			—			3			—		3
Other	(18		)	1			5			—		(12		)
Total Adjusted EBITDA	$	151		$	104		$	202		$	—	$	457



	Six Months Ended June 30, 2016
	West			Texas			East			Consolidation and Elimination			Total
Net loss attributable to Calpine													$	(227	)
Net income attributable to the noncontrolling interest													9
Income tax expense													21
Debt extinguishment costs and other (income) expense, net													28
Interest expense, net of interest income													312
Income (loss) from operations	$	88		$	(101	)	$	155		$	1		$	143
Add:
Adjustments to reconcile income (loss) from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs⁽¹⁾	122			106			111			—			339
Major maintenance expense	40			49			54			—			143
Operating lease expense	—			—			13			—			13
Mark-to-market (gain) loss on commodity derivative activity	67			76			(12		)	—			131
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest⁽²⁾	(9		)	—			21			—			12
Stock-based compensation expense	6			6			5			—			17
Loss on dispositions of assets	—			2			3			—			5
Contract amortization	1			42			11			—			54
Other	(30		)	2			(2		)	(1		)	(31		)
Total Adjusted EBITDA	$	285		$	182		$	359		$	—		$	826



	Six Months Ended June 30, 2015
	West			Texas			East		Consolidation and Elimination		Total
Net income attributable to Calpine											$	9
Net income attributable to the noncontrolling interest											5
Income tax expense											4
Debt modification and extinguishment costs and other (income) expense, net											39
Interest expense, net of interest income											310
Income from operations	$	169		$	64		$	134	$	—	$	367
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs⁽¹⁾	130			99			87		—		316
Major maintenance expense	66			55			47		—		168
Operating lease expense	4			—			13		—		17
Mark-to-market (gain) loss on commodity derivative activity	(47		)	(36		)	14		—		(69		)
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest⁽²⁾	(7		)	—			16		—		9
Stock-based compensation expense	5			5			2		—		12
Loss on dispositions of assets	—			2			1		—		3
Contract amortization	—			—			7		—		7
Other	(42		)	1			6		—		(35		)
Total Adjusted EBITDA	$	278		$	190		$	327	$	—	$	795

____________


(1)	Excludes depreciation and amortization expense attributable to the noncontrolling interest.


(2)	Adjustments to reflect Adjusted EBITDA from unconsolidated investments include (gain) loss on mark-to-market activity of nil for each of the three and six months ended June 30, 2016 and 2015.

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, 2016 and December 31, 2015 (in millions):



	June 30, 2016		December 31, 2015
Cash and cash equivalents, corporate⁽¹⁾	$	138	$	850
Cash and cash equivalents, non-corporate	77		56
Total cash and cash equivalents⁽²⁾	215		906
Restricted cash	168		228
Corporate Revolving Facility availability⁽³⁾	1,374		1,184
CDHI letter of credit facility availability	39		59
Total current liquidity availability⁽⁴⁾	$	1,796	$	2,377

____________


(1)	Includes $9 million and $35 million of margin deposits posted with us by our counterparties at June 30, 2016 and December 31, 2015, respectively. See Note 7 of the Notes to Consolidated Condensed Financial Statements for further information related to our collateral.


(2)	Cash and cash equivalents decreased during the six months ended June 30, 2016, primarily resulting from the acquisition of Granite Ridge Energy Center, payments to fund growth projects and other seasonal variations in working capital, which cause fluctuations in our cash and cash equivalents.

(3)

(4)

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, power transmission and natural gas transportation agreements.

Our principal source for future liquidity is cash flows generated from our operations. We believe that cash on hand and expected future cash flows from operations will be sufficient to meet our liquidity needs for our operations, both in the near and longer term. See “Cash Flow Activities” below for a further discussion of our change in cash and cash equivalents.

Our principal uses of liquidity and capital resources, outside of those required for our operations, include, but are not limited to, collateral requirements to support our commercial hedging and optimization activities, debt service obligations including principal and interest payments, and capital expenditures for construction, project development and other growth initiatives. In addition, we may use capital resources to opportunistically repurchase our shares of common stock. The ultimate decision to allocate capital to share repurchases will be based upon the expected returns compared to alternative uses of capital.

Cash Management — We manage our cash in accordance with our cash management system subject to the requirements of our Corporate Revolving Facility and requirements under certain of our project debt and lease agreements or by regulatory agencies. Our cash and cash equivalents, as well as our restricted cash balances, are invested in money market funds that are not FDIC insured. We place our cash, cash equivalents and restricted cash in what we believe to be creditworthy financial institutions.

We have never paid cash dividends on our common stock. Future cash dividends, if any, may be authorized at the discretion of our Board of Directors and will depend upon, among other things, our future operations and earnings, capital requirements,

general financial condition, contractual and financing restrictions and such other factors as our Board of Directors may deem relevant.

Liquidity Sensitivity

Significant changes in commodity prices and Market Heat Rates can have an impact on 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, 2016, an increase of $1/MMBtu in natural gas prices would result in an increase of collateral required by approximately $247 million. If natural gas prices decreased by $1/MMBtu, we estimate that our collateral requirements would decrease by approximately $140 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, 2016, an increase of 500 Btu/KWh in the Market Heat Rate would result in an increase in collateral required by approximately $80 million. If Market Heat Rates were to fall at a similar rate, we estimate that our collateral required would decrease by approximately $56 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 generation and natural gas portfolio mostly through power and natural gas forward physical and financial transactions; however, we currently remain susceptible to significant price movements for 2016 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 impact 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, 2016 and December 31, 2015 (in millions):



	June 30, 2016		December 31, 2015
Corporate Revolving Facility⁽¹⁾	$	304	$	316
CDHI	261		241
Various project financing facilities	212		198
Total	$	777	$	755

____________


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

Capital Management

In connection with our goals of enhancing long-term shareholder value, we have completed the following key capital management transaction during 2016, as further described below.

Corporate Revolving Facility

New 2023 First Lien Term Loan and 2026 First Lien Notes

In May 2016, we repaid our 2019 and 2020 First Lien Term Loans with the proceeds from our New 2023 First Lien Term Loan and 2026 First Lien Notes which extended the maturity on approximately $1.2 billion of corporate debt. See Note 4 of the Notes to Consolidated Condensed Financial Statements for a further description of our New 2023 First Lien Term Loan and 2026 First Lien Notes.

Managing and Growing our Portfolio

Our goal is to continue to grow our presence in core markets with an emphasis on acquisitions, expansions or modernizations of existing power plants. We intend to take advantage of favorable opportunities to continue to design, develop, acquire, construct and operate the next generation of highly efficient, operationally flexible and environmentally responsible power plants where such investment meets our rigorous financial hurdles, particularly if power contracts and financing are available and attractive returns are expected. Likewise, we actively seek to divest non-core assets where we can find opportunities to do so accretively. In addition, we believe that modernizations and expansions to our current assets offer proven and financially disciplined opportunities to improve our operations, capacity and efficiencies. Our significant projects under construction, growth initiatives, modernizations and strategic asset sales are discussed below.

Granite Ridge Energy Center — On February 5, 2016, we completed the purchase of Granite Ridge Energy Center, a power plant with a nameplate capacity of 745 MW (summer peaking capacity of 695 MW), for approximately $500 million, excluding working capital and other adjustments. The addition of this modern, efficient, natural gas-fired, combined-cycle power plant increased capacity in our East segment, specifically the constrained New England market.

York 2 Energy Center — York 2 Energy Center is a 760 MW dual-fuel, combined-cycle project that will be co-located with our York Energy Center in Peach Bottom Township, Pennsylvania. Once complete, the power plant will feature two combustion turbines, two heat recovery steam generators and one steam turbine. The project’s capacity cleared PJM’s last three base residual auctions. The project is now under construction, and we are targeting COD during the third quarter of 2017. PJM has completed the interconnection study process for an additional 68 MW of planned capacity at the York 2 Energy Center. This incremental 68 MW of planned capacity cleared the last two base residual auctions and we expect to receive the final air permit in the third quarter of 2016.

Mankato Power Plant Expansion — By order dated February 5, 2015, the Minnesota Public Utilities Commission concluded a competitive resource acquisition proceeding and selected a 345 MW expansion of our Mankato Power Plant, authorizing execution of a 20-year PPA between Calpine and Xcel Energy. The PPA was executed in April 2015 and satisfied final regulatory approval requirements in March 2016. Commercial operation of the expanded capacity is expected by June 1, 2019.

Guadalupe Peaking Energy Center — In April 2015, we executed an agreement with Guadalupe Valley Electric Cooperative (“GVEC”) that will facilitate the construction of a 418 MW natural gas-fired peaking power plant to be co-located with our Guadalupe Energy Center. Under the terms of the agreement, construction of the Guadalupe Peaking Energy Center (“GPEC”) may commence at our discretion, so long as the power plant reaches COD by June 1, 2019. When the power plant begins commercial operation, GVEC will purchase a 50% ownership interest in GPEC. Once built, GPEC will feature two fast-ramping combustion turbines capable of responding to peaks in power demand. This project represents a mutually beneficial response to our customer’s desire to have direct access to peaking generation resources, as it leverages the benefits of our existing site and development rights and our construction and operating expertise, as well as our customer’s ability to fund its investment at attractive rates, all while affording us the flexibility of timing the plant’s construction in response to market pricing signals.

PJM and ISO-NE Development Opportunities — We continue to evaluate development projects in the PJM and ISO-NE market areas that feature cost advantages such as existing infrastructure and favorable transmission queue positions. These projects continue to advance entitlements (such as permits, zoning and transmission) for potential future development when/if economic as compared to purchasing existing power plants in the region.

South Point Energy Center — On April 1, 2016, we entered into an asset sale agreement for the sale of substantially all of the assets comprising our South Point Energy Center to Nevada Power Company d/b/a NV Energy for approximately $76 million plus the assumption by the purchaser of existing transmission capacity contracts with a future net present value payment obligation of approximately $112 million, approximately $9 million in remaining tribal lease costs and approximately $21 million in near-term repairs, maintenance and capital improvements to restore the power plant to full capacity. The sale is subject to certain conditions precedent, as well as federal and state regulatory approvals, and is expected to close no later than the first quarter of 2017. The natural gas-fired, combined-cycle plant is located on the Fort Mojave Indian Reservation in Mohave Valley, Arizona, and features a summer peak capacity of 504 MW. This transaction supports our effort to divest non-core assets outside our strategic concentration.

Osprey Energy Center — We executed an asset sale agreement in the fourth quarter of 2014 for the sale of our Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million, excluding working capital and other adjustments, which will be consummated in January 2017 upon the conclusion of a PPA with a term of 27 months. The sale has received FERC and state regulatory approvals and represents a strategic disposition of a power plant in a wholesale power market dominated by regulated utilities.

Clear Lake Power Plant — We plan to file with ERCOT to retire our 400 MW Clear Lake Power Plant. Built in 1985, Clear Lake is an older technology. Due to growing maintenance costs and lack of adequate compensation in Texas, we have chosen to retire the power plant. We are working together with the facility’s bilateral counterparties to mutually agree on a date to cease commercial operations, which will take place no later than the summer of 2018.

Customer Relationships

We continue to focus on providing products and services that are beneficial to our customers. A summary of certain significant achievements and contracts entered into in 2016 are as follows:

Champion Energy


•	During the first quarter of 2016, Champion Energy expanded its New England service territory and now offers electricity service to commercial and industrial customers in Maine and Connecticut.

East


•	We entered into a new ten-year PPA with the Tennessee Valley Authority to provide 615 MW of energy and capacity from our Morgan Energy Center commencing in February 2016.


•	We satisfied final regulatory approval requirements for our 20-year PPA with Xcel Energy, which will facilitate a 345 MW expansion of our Mankato Power Plant.


•	We entered into a new five-year PPA with a third party to provide 50 MW of capacity from our RockGen Energy Center commencing in June 2017, which increases to 100 MW of capacity commencing in June 2019.

West


•	Our ten-year PPA with Southern California Edison for 50 MW of capacity and renewable energy from our Geysers Assets commencing in January 2018 was approved by the CPUC in the second quarter of 2016.

Wildfire at our Geysers Assets

In September 2015, a wildfire spread to our Geysers Assets in Lake and Sonoma counties, California. The wildfire affected five of our 14 power plants in the region, which sustained damage to ancillary structures such as cooling towers and communication/electric deliverability infrastructure. Our Geysers Assets are currently generating renewable power for our customers at approximately 95% of the normal operating capacity and should be restored to pre-fire levels by the end of 2016. We believe the repair and replacement costs, as well as our net revenue losses relating to the wildfire, will be limited to our insurance deductibles of approximately $36 million, all of which was recognized in 2015. Any losses incurred in 2016 related to the wildfire will be primarily offset by insurance proceeds, when such proceeds are realizable. We record insurance proceeds in the same financial statement line as the related loss is incurred and recorded approximately $8 million in business interruption proceeds in operating revenues during the three and six months ended June 30, 2016. We do not anticipate the wildfire or timing of insurance proceeds recovery to have a material impact on our financial condition, results of operations or cash flows.

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, 2015, our consolidated federal NOLs totaled approximately $6.9 billion.

Cash Flow Activities

The following table summarizes our cash flow activities for the six months ended June 30, 2016 and 2015 (in millions):



	2016			2015
Beginning cash and cash equivalents	$	906		$	717
Net cash provided by (used in):
Operating activities	120			19
Investing activities	(676		)	(246		)
Financing activities	(135		)	(68		)
Net decrease in cash and cash equivalents	(691		)	(295		)
Ending cash and cash equivalents	$	215		$	422

Net Cash Provided By Operating Activities

Cash provided by operating activities for the six months ended June 30, 2016, was $120 million compared to $19 million for the six months ended June 30, 2015. The increase was primarily due to:

•

Income from operations — Income from operations, adjusted for non-cash items, increased by $89 million for the six months ended June 30, 2016, compared to the same period in 2015. Non-cash items consist primarily of depreciation and amortization, income from unconsolidated investments in power plants and mark-to-market activity. The increase in income from operations was primarily driven by a $92 million increase in Commodity revenue, net of Commodity expense, excluding non-cash amortization of purchased intangible assets. See “Results of Operations for the Six Months Ended June 30, 2016 and 2015” above for further discussion of these changes.

•

Working capital employed — Working capital employed increased by $65 million for the six months ended June 30, 2016, compared to the same period in 2015, after adjusting for changes in debt, restricted cash and mark-to-market related balances which did not impact cash provided by operating activities. The increase was primarily due to the change in net margining requirements for the six months ended June 30, 2016, compared to the same period in 2015.


•	Interest paid — Cash paid for interest decreased by $33 million to $289 million for the six months ended June 30, 2016, from $322 million for the six months ended June 30, 2015. The decrease was primarily due to our refinancing activities and timing of interest payments.

•

Debt modification & extinguishment payments — During the six months ended June 30, 2015, we made cash payments of $18 million related to repurchase penalties for a portion of the 2023 First Lien Notes and cash payments of $13 million related to the debt modification costs associated with the issuance of the 2022 First Lien Term Loan. There was no similar activity for the six months ended June 30, 2016.

Net Cash Used In Investing Activities

Cash used in investing activities for the six months ended June 30, 2016, was $676 million compared to $246 million for the six months ended June 30, 2015. The increase was primarily due to:


•	Purchase of Granite Ridge Energy Center — During the six months ended June 30, 2016, we purchased a natural gas-fired, combined-cycle power plant located in Londonderry, New Hampshire for $526 million. There were no acquisitions during the six months ended June 30, 2015.


•	Capital expenditures — Capital expenditures for the six months ended June 30, 2016, were $223 million, a decrease of $56 million, compared to expenditures of $279 million for the six months ended June 30, 2015. The decrease was primarily due to lower expenditures on construction projects and outages during the six months ended June 30, 2016, compared to the same period in 2015.


•	Restricted Cash — Restricted cash decreased $60 million for the six months ended June 30, 2016, compared to a decrease of $34 million for the six months ended June 30, 2015. The decrease was primarily attributed to the timing of funding the restricted accounts, maintenance and construction payments and debt payments.

Net Cash Used In Financing Activities

Cash used in financing activities for the six months ended June 30, 2016, was $135 million compared to $68 million for the six months ended June 30, 2015. The increase was primarily due to:

•

First Lien Term Loans, First Lien Notes and Senior Unsecured Notes — During the six months ended June 30, 2016, we utilized proceeds from the issuance of the New 2023 First Lien Term Loan and the 2026 First Lien Notes to repay the 2019 and 2020 First Lien Term Loans outstanding balance of $1.2 billion. During the six months ended June 30, 2015, we received proceeds of $650 million from the issuance of the 2024 Senior Unsecured Notes which were used to replenish cash on hand used for the acquisition of Fore River Energy Center in the fourth quarter of 2014, to repurchase $147 million of the 2023 First Lien Notes and for general corporate purposes. In addition, we utilized proceeds from the issuance of the 2022 First Lien Term Loan to repay the 2018 First Lien Term Loan of $1.6 billion.


•	Stock repurchases — During the six months ended June 30, 2016, we repurchased an immaterial amount of common stock as compared to $454 million paid to repurchase our common stock during the six months ended June 30, 2015.

•

Financing costs — During the six months ended June 30, 2016, we incurred finance costs of $26 million due to the issuances of the New 2023 First Lien Term Loan and 2026 First Lien Notes and amending the Corporate Revolving Facility. During the six months ended June 30, 2015, we incurred finance costs of $17 million due to the issuances of the 2024 Senior Unsecured Notes and the 2022 First Lien Term Loan and the re-pricing of the project debt for Los Esteros Critical Energy Facility, LLC.

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 2015 Form 10-K.

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, load sales, steam sales, buying and selling standard physical 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. We completed the acquisition of Champion Energy, a leading retail electric provider, on October 1, 2015, providing us with an additional outlet to transact hedging activities related to our wholesale power plant portfolio.

We conduct our hedging and optimization activities within a structured risk management framework based on controls, policies and procedures. We monitor these activities through active and ongoing management and oversight, defined roles and responsibilities, and daily risk estimates and reporting. Additionally, we seek to manage the associated risks through diversification, by controlling position sizes, by using portfolio position limits, and by entering into offsetting positions that lock in a margin. We also 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 power and Heat Rate swaps and options) and fuel and purchased energy expense (for natural gas, power, environmental product and fuel oil contracts, swaps and options). 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 mostly through power and natural gas forward physical and financial transactions; however, we currently remain susceptible to significant price movements for 2016 and beyond. When we elect to enter into these transactions, we are able to economically hedge a portion of our Spark Spread at pre-determined generation and price levels.

We have historically used interest rate hedging instruments to adjust the mix between our fixed and variable rate debt. To the extent eligible, our interest rate hedging instruments have been designated as cash flow hedges, and changes in fair value are recorded in OCI to the extent they are effective with gains and losses reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. See Note 6 of the Notes to Consolidated Condensed Financial Statements for further discussion of our derivative instruments.

The primary factors affecting our market risk and the fair value of our derivatives at any point in time are the volume of open derivative positions (MMBtu, MWh and $ notional amounts); changing commodity market prices, primarily for power and natural gas; our credit standing and that of our counterparties for energy commodity derivatives; and prevailing interest rates for our interest rate hedging instruments. Since prices for power and natural gas and interest rates are volatile, there may be material changes in the fair value of our derivatives over time, driven both by price volatility and the changes in volume of open derivative transactions. Our derivative assets have decreased to approximately $1.6 billion at June 30, 2016, when compared to approximately $2.0 billion at December 31, 2015, and our derivative liabilities have decreased to approximately $1.9 billion at June 30, 2016, when compared to approximately $2.2 billion at December 31, 2015. The fair value of our level 3 derivative assets and liabilities at June 30, 2016 represent a small portion of our total assets and liabilities measured at fair value (approximately 2% and 6%, respectively). See Note 5 of the Notes to Consolidated Condensed Financial Statements for further information related to our level 3 derivative assets and liabilities.

The change in fair value of our outstanding commodity and interest rate hedging instruments from January 1, 2016, through June 30, 2016, is summarized in the table below (in millions):



	Commodity Instruments			Interest Rate Hedging Instruments			Total
Fair value of contracts outstanding at January 1, 2016	$	(107	)	$	(89	)	$	(196	)
Items recognized or otherwise settled during the period⁽¹⁾⁽²⁾	(60		)	19			(41		)
Fair value attributable to new contracts	13			9			22
Changes in fair value attributable to price movements	(29		)	(26		)	(55		)
Changes in fair value attributable to nonperformance risk	(2		)	—			(2		)
Fair value of contracts outstanding at June 30, 2016⁽³⁾	$	(185	)	$	(87	)	$	(272	)

__________

(1)

Commodity contract settlements consist of the realization of previously recognized gains on contracts not designated as hedging instruments of $107 million (represents a portion of Commodity revenue and Commodity expense as reported on our Consolidated Condensed Statements of Operations) and $47 million related to current period gains from other changes in derivative assets and liabilities not reflected in OCI or earnings.


(2)	Interest rate settlements consist of $18 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)	Net commodity and interest rate derivative assets and liabilities reported in Notes 5 and 6 of the Notes to Consolidated Condensed Financial Statements.

The change since the last balance sheet date in the total value of the derivatives (both assets and liabilities) is reflected either in cash for option premiums paid or collected, in OCI, net of tax for cash flow hedges, or on our Consolidated Condensed Statements of Operations as a component (gain or loss) in earnings.



	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Realized gain (loss)⁽¹⁾⁽²⁾
Commodity derivative instruments	$	63		$	104		$	181		$	163
Total realized gain (loss)	$	63		$	104		$	181		$	163

Mark-to-market gain (loss)⁽³⁾
Commodity derivative instruments	$	(36	)	$	(1	)	$	(131	)	$	69
Interest rate hedging instruments	—			—			1			1
Total mark-to-market gain (loss)	$	(36	)	$	(1	)	$	(130	)	$	70
Total activity, net	$	27		$	103		$	51		$	233

___________


(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 derivative activity related to the acquisition of Champion Energy.


(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,
	2016			2015			2016			2015
Realized and mark-to-market gain (loss)
Derivatives contracts included in operating revenues⁽¹⁾⁽²⁾	$	(272	)	$	115		$	(68	)	$	234
Derivatives contracts included in fuel and purchased energy expense⁽¹⁾⁽²⁾	299			(12		)	118			(2		)
Interest rate hedging instruments included in interest expense⁽³⁾	—			—			1			1
Total activity, net	$	27		$	103		$	51		$	233

___________


(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 derivative activity related to the acquisition of Champion Energy.


(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.

Commodity Price Risk — Commodity price risks result from exposure to changes in spot prices, forward prices, price volatilities and correlations between the price of power, steam and natural gas. We manage the commodity price risk and the variability in future cash flows from forecasted sales of power and purchases of natural gas of our entire portfolio of generating assets and contractual positions by entering into various derivative and non-derivative instruments.

The net fair value of outstanding derivative commodity instruments at June 30, 2016, based on price source and the period during which the instruments will mature, are summarized in the table below (in millions):



Fair Value Source	2016			2017-2018			2019-2020			After 2020		Total
Prices actively quoted	$	32		$	33		$	3		$	—	$	68
Prices provided by other external sources	(109		)	(61		)	(13		)	—		(183		)
Prices based on models and other valuation methods	(27		)	(42		)	(1		)	—		(70		)
Total fair value	$	(104	)	$	(70	)	$	(11	)	$	—	$	(185	)

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, 2016 and 2015 (in millions):



	2016		2015
Three months ended June 30:
High	$	35	$	23
Low	$	14	$	17
Average	$	23	$	19

Six months ended June 30:
High	$	35	$	38
Low	$	14	$	17
Average	$	22	$	24
As of June 30	$	32	$	23

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 impact 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 impact 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. In order to mitigate the impacts of declining liquidity in the forward commodity markets, we completed the acquisition of Champion Energy, a leading retail electric provider, on October 1, 2015, providing 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. Increasing natural gas prices or Market Heat Rates can cause increased collateral requirements. Our liquidity management framework is intended to maximize liquidity access and minimize funding costs during times of rising prices. See further discussion regarding our uses of collateral as they relate to our commodity procurement and risk management activities in Note 7 of the Notes to Consolidated Condensed Financial Statements.

Credit Risk — Credit risk relates to the risk of loss resulting from nonperformance or non-payment by our counterparties related to their contractual obligations with us. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. We also have credit risk if counterparties 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’ 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 customers relating to our sales of power and steam and our hedging, optimization and trading activities. We believe that our credit policies and portfolio of transactions adequately monitor and diversify our credit risk, and currently our counterparties 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 credit quality associated with the net fair value of outstanding derivative commodity instruments is included in our derivative assets and (liabilities) at June 30, 2016, and the period during which the instruments will mature are summarized in the table below (in millions):



Credit Quality (Based on Standard & Poor’s Ratings as of June 30, 2016)	2016			2017-2018			2019-2020			After 2020		Total
Investment grade	$	(98	)	$	(75	)	$	(12	)	$	—	$	(185	)
Non-investment grade	(6		)	2			—			—		(4		)
No external ratings	—			3			1			—		4
Total fair value	$	(104	)	$	(70	)	$	(11	)	$	—	$	(185	)

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 $(5) million at June 30, 2016.

APPLICATION OF CRITICAL ACCOUNTING POLICIES

The preparation of financial statements in accordance with U.S. GAAP requires management to make certain estimates and assumptions which are inherently imprecise and may differ significantly from actual results achieved. We have updated the following critical accounting policy to provide addition detail on our process of testing for impairments of our power plants. Otherwise, there have been no changes to the critical accounting policies previously disclosed in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Application of Critical Accounting Policies” of our 2015 Form 10-K.

Impairment Evaluation of Long-Lived Assets (Including Intangibles and Investments)

We evaluate our long-lived assets, such as property, plant and equipment, equity method investments, turbine equipment and specifically identified intangibles, on an annual basis or when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Examples of such events or changes in circumstances are:


•	a significant decrease in the market price of a long-lived asset;


•	a significant adverse change in the manner an asset is being used or its physical condition;


•	an adverse action by a regulator or legislature or an adverse change in the business climate;


•	an accumulation of costs significantly in excess of the amount originally expected for the construction or acquisition of an asset;


•	a current-period loss combined with a history of losses or the projection of future losses; or


•	a change in our intent about an asset from an intent to hold to a greater than 50% likelihood that an asset will be sold or disposed of before the end of its previously estimated useful life.

When we believe an impairment condition on long-lived assets such as property, plant and equipment may have occurred, we are required to estimate the undiscounted future cash flows associated with a long-lived asset or group of long-lived assets at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities for long-lived assets that are expected to be held and used. We use a fundamental long-term view of the power market which is based on long-term production volumes, price curves and operating costs together with the regulatory and environmental requirements within each individual market to prepare our multi-year forecast. Since we manage and market our power sales as a portfolio rather than at the individual power plant level or customer level within each designated market, pool or segment, we group our power plants based upon the corresponding market for valuation purposes. If we determine that the undiscounted cash flows from an asset or group of assets to be held and used are less than the associated carrying amount, or if we have classified an asset as held for sale, we must estimate fair value to determine the amount of any impairment loss.

We have temporarily suspended operations at our Sutter Energy Center. While the long-term market forecasted cash flows continue to support the carrying value of the asset, if the forecasted cash flows further deteriorate, this could result in a permanent shut down of the facility and in the recognition of an impairment of our Sutter Energy Center and other plants within the respective market.

When we believe an impairment condition may exist on specifically identifiable finite-lived intangibles or an investment, we must estimate their fair value to determine the amount of any impairment loss. Significant judgment is required in determining fair value as discussed in our 2015 Form 10-K in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Application of Critical Accounting Policies — Fair Value Measurements.”

All construction and development projects are reviewed for impairment whenever there is an indication of potential reduction in fair value. If it is determined that it is no longer probable that the projects will be completed and all capitalized costs recovered through future operations, the carrying values of the projects would be written down to their fair value. When we determine that our assets meet the assets held-for-sale criteria, they are reported at the lower of the carrying amount or fair value less the cost to sell. We are also required to evaluate our equity method investments to determine whether or not they are impaired when the value is considered an “other than a temporary” decline in value.

See Note 2 of the Notes to Consolidated Financial Statements in our 2015 Form 10-K for further discussion of our impairment evaluation of long-lived assets.

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 2015 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 2016, 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, financial position, cash flows and results of operations. These include the following risk factor, in addition to the risk factors previously disclosed in Part I, Item 1A “Risk Factors” of our 2015 Form 10-K:

State legislative and regulatory action could adversely impact our competitive position and business.

Certain states have taken or are considering taking anticompetitive actions by subsidizing or otherwise providing economic support to existing, uneconomic power plants in a manner that could have an adverse impact on the deregulated power markets. We are actively participating in many of the legislative, regulatory and judicial processes challenging these actions at the state and federal levels. If these anticompetitive actions are ultimately upheld and implemented, they could have an adverse impact on capacity and energy prices in the deregulated electricity markets which in turn could have a material negative impact on our business prospects and financial results.


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

Repurchase of Equity Securities



Period	(a) Total Number of Shares Purchased⁽¹⁾	(b) Average Price Paid Per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs⁽²⁾	(d) Maximum Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs (in millions)⁽²⁾
April	1,620	$	14.86	—	$	307
May	5,105	$	14.94	—	$	307
June	1,068	$	14.81	—	$	307
Total	7,793	$	14.91	—	$	307

___________


(1)	To satisfy tax withholding obligations associated with the vesting of restricted stock awarded to employees during the second quarter of 2016, we withheld a total of 7,793 shares that are included in the total number of shares purchased.


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


Item 3.	Defaults Upon Senior Securities

None.


Item 4.	Mine Safety Disclosures

Not applicable.


Item 5.	Other Information

None.


Item 6.	Exhibits

EXHIBIT INDEX



Exhibit Number		Description

4.1		Indenture, dated as of May 31, 2016, for the senior secured notes due 2026 among each of Calpine Corporation, the guarantors party thereto and Wilmington Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed with the SEC on June 1, 2016).

10.1		Credit Agreement, dated May 31, 2016 among Calpine Corporation as borrower and the lenders party hereto, and Citibank, N.A., as administrative agent, MUFG Union Bank, N.A., as collateral agent (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the SEC on June 1, 2016).

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.

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: July 28, 2016

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