CALPINE CORP - FORM 10-Q - April 28, 2016

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EX-10.2 - PSU AWARD AGREEMENT BETWEEN THE COMPANY AND CERTAIN SENIOR EMPLOYEES - CALPINE CORP	cpn_exhibit102xpsuequityag.htm
EX-10.1 - PSU AWARD AGREEMENT BETWEEN THE COMPANY AND W. THAD MILLER - CALPINE CORP	cpn_exhibit101xpsuequityag.htm
EX-32.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER - CALPINE CORP	cpn_exhibit321x03312016.htm
EX-31.1 - SECTION 302 CERTIFICATION OF CHIEF EXECUTIVE OFFICER - CALPINE CORP	cpn_exhibit311x03312016.htm
EX-31.2 - SECTION 302 CERTIFICATION OF CHIEF FINANCIAL OFFICER - CALPINE CORP	cpn_exhibit312x03312016.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

____________________

Form 10-Q

(Mark One)



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

For the quarterly period ended March 31, 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: 359,026,393 shares of common stock, par value $0.001, were outstanding as of April 27, 2016.

CALPINE CORPORATION AND SUBSIDIARIES

REPORT ON FORM 10-Q

For the Quarter Ended March 31, 2016

INDEX




	Page

Definitions	ii

Forward-Looking Statements	vi

Where You Can Find Other Information	vii

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements	1
Consolidated Condensed Statements of Operations for the Three Months Ended March 31, 2016 and 2015	1
Consolidated Condensed Statements of Comprehensive Loss for the Three Months Ended March 31, 2016 and 2015	2
Consolidated Condensed Balance Sheets at March 31, 2016 and December 31, 2015	3
Consolidated Condensed Statements of Cash Flows for the Three Months Ended March 31, 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	25
Forward-Looking Information	25
Introduction and Overview	25
Results of Operations	28
Commodity Margin and Adjusted EBITDA	29
Liquidity and Capital Resources	34
Risk Management and Commodity Accounting	40
New Accounting Standards and Disclosure Requirements	44
Item 3. Quantitative and Qualitative Disclosures About Market Risk	44
Item 4. Controls and Procedures	44

PART II – OTHER INFORMATION

Item 1. Legal Proceedings	45
Item 1A. Risk Factors	45
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	45
Item 3. Defaults Upon Senior Securities	45
Item 4. Mine Safety Disclosures	45
Item 5. Other Information	45
Item 6. Exhibits	46
Signatures	47

DEFINITIONS

As used in this report for the quarter ended March 31, 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

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

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 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 and December 7, 2015

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 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

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 extraordinary, unusual or non-recurring items

AOCI		Accumulated Other Comprehensive Income

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



ABBREVIATION		DEFINITION
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

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

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

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

CFTC		Commodities Futures Trading Commission

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

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

iii



ABBREVIATION		DEFINITION

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 and the 2024 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 Loan

GE		General Electric International, Inc.

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

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

NOL(s)		Net operating loss(es)



ABBREVIATION		DEFINITION
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

RPS		Renewable Portfolio Standard

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

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

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.

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.

vii

PART I — FINANCIAL INFORMATION


Item 1.	Financial Statements

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)



		Three Months Ended March 31,
		2016			2015
	(in millions, except share and per share amounts)
Operating revenues:
Commodity revenue		$	1,585		$	1,638
Mark-to-market gain		25			3
Other revenue		5			5
Operating revenues		1,615			1,646
Operating expenses:
Fuel and purchased energy expense:
Commodity expense		1,006			1,077
Mark-to-market (gain) loss		120			(67		)
Fuel and purchased energy expense		1,126			1,010
Plant operating expense		255			260
Depreciation and amortization expense		180			158
Sales, general and other administrative expense		38			37
Other operating expenses		20			20
Total operating expenses		1,619			1,485
(Income) from unconsolidated investments in power plants		(7		)	(5		)
Income from operations		3			166
Interest expense		157			154
Interest (income)		(1		)	(1		)
Debt extinguishment costs		—			19
Other (income) expense, net		6			2
Loss before income taxes		(159		)	(8		)
Income tax expense (benefit)		35			(1		)
Net loss		(194		)	(7		)
Net income attributable to the noncontrolling interest		(4		)	(3		)
Net loss attributable to Calpine		$	(198	)	$	(10	)

Basic and diluted loss per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands)		353,501			372,935
Net loss per common share attributable to Calpine — basic and diluted		$	(0.56	)	$	(0.03	)

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

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE LOSS

(Unaudited)



	Three Months Ended March 31,
	2016			2015
	(in millions)
Net loss	$	(194	)	$	(7	)
Cash flow hedging activities:
Loss on cash flow hedges before reclassification adjustment for cash flow hedges realized in net loss	(23		)	(18		)
Reclassification adjustment for loss on cash flow hedges realized in net loss	11			12
Foreign currency translation gain (loss)	12			(12		)
Income tax expense	—			—
Other comprehensive income (loss)	—			(18		)
Comprehensive loss	(194		)	(25		)
Comprehensive (income) attributable to the noncontrolling interest	(2		)	(2		)
Comprehensive loss attributable to Calpine	$	(196	)	$	(27	)

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

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited)



	March 31,			December 31,
	2016			2015
	(in millions, except share and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents ($48 and $118 attributable to VIEs)	$	244		$	906
Accounts receivable, net of allowance of $3 and $2	569			644
Inventories	490			475
Margin deposits and other prepaid expense	149			137
Restricted cash, current ($110 and $132 attributable to VIEs)	167			216
Derivative assets, current	1,853			1,698
Other current assets	303			19
Total current assets	3,775			4,095
Property, plant and equipment, net ($4,024 and $4,062 attributable to VIEs)	13,407			13,012
Restricted cash, net of current portion ($17 and $11 attributable to VIEs)	17			12
Investments in power plants	89			79
Long-term derivative assets	420			313
Long-term assets held for sale	—			130
Other assets ($107 and $166 attributable to VIEs)	951			1,040
Total assets	$	18,659		$	18,681
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	433		$	552
Accrued interest payable	124			129
Debt, current portion ($165 and $166 attributable to VIEs)	205			221
Derivative liabilities, current	1,975			1,734
Other current liabilities	348			412
Total current liabilities	3,085			3,048
Debt, net of current portion ($3,055 and $3,143 attributable to VIEs)	11,672			11,716
Long-term derivative liabilities	585			473
Other long-term liabilities	344			277
Total liabilities	15,686			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, 359,542,565 and 356,755,747 shares issued, respectively, and 359,027,395 and 356,662,004 shares outstanding, respectively	—			—
Treasury stock, at cost, 515,170 and 93,743 shares, respectively	(7		)	(1		)
Additional paid-in capital	9,602			9,594
Accumulated deficit	(6,503		)	(6,305		)
Accumulated other comprehensive loss	(177		)	(179		)
Total Calpine stockholders’ equity	2,915			3,109
Noncontrolling interest	58			58
Total stockholders’ equity	2,973			3,167
Total liabilities and stockholders’ equity	$	18,659		$	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)



	Three Months Ended March 31,
	2016			2015
	(in millions)
Cash flows from operating activities:
Net loss	$	(194	)	$	(7	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation and amortization⁽¹⁾	226			171
Income tax expense	35			—
Mark-to-market activity, net	94			(71		)
(Income) from unconsolidated investments in power plants	(7		)	(5		)
Stock-based compensation expense	9			11
Other	(4		)	(2		)
Change in operating assets and liabilities, net of effect of acquisition:
Accounts receivable	87			120
Derivative instruments, net	(12		)	(17		)
Other assets	(19		)	(28		)
Accounts payable and accrued expenses	(207		)	(204		)
Other liabilities	18			15
Net cash provided by (used in) operating activities	26			(17		)
Cash flows from investing activities:
Purchases of property, plant and equipment	(133		)	(162		)
Purchase of Granite Ridge Energy Center	(527		)	—
Decrease in restricted cash	43			35
Other	6			(1		)
Net cash used in investing activities	(611		)	(128		)
Cash flows from financing activities:
Repayment of CCFC Term Loans and First Lien Term Loans	(13		)	(11		)
Borrowings under Senior Unsecured Notes	—			650
Repurchase of First Lien Notes	—			(147		)
Repayments of project financing, notes payable and other	(56		)	(58		)
Distribution to noncontrolling interest holder	(2		)	—
Financing costs	(7		)	(11		)
Stock repurchases	—			(202		)
Proceeds from exercises of stock options	—			3
Other	1			—
Net cash provided by (used in) financing activities	(77		)	224
Net increase (decrease) in cash and cash equivalents	(662		)	79
Cash and cash equivalents, beginning of period	906			717
Cash and cash equivalents, end of period	$	244		$	796

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)



	Three Months Ended March 31,
	2016		2015
	(in millions)
Cash paid during the period for:
Interest, net of amounts capitalized	$	150	$	146
Income taxes	$	2	$	6

Supplemental disclosure of non-cash investing activities:
Change in capital expenditures included in accounts payable	$	15	$	(22	)

____________


(1)	Includes depreciation and amortization included in Commodity revenue, Commodity expense and interest expense on our Consolidated Condensed Statements of Operations.

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

CALPINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

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



	March 31, 2016						December 31, 2015
	Current		Non-Current		Total		Current		Non-Current		Total
Debt service	$	29	$	7	$	36	$	28	$	8	$	36
Construction/major maintenance	45		7		52		50		2		52
Security/project/insurance	91		1		92		136		—		136
Other	2		2		4		2		2		4
Total	$	167	$	17	$	184	$	216	$	12	$	228

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



	March 31, 2016		December 31, 2015		Depreciable Lives
Buildings, machinery and equipment	$	16,685	$	16,294	3 – 46 Years
Geothermal properties	1,327		1,319		13 – 58 Years
Other	219		208		3 – 46 Years
	18,231		17,821
Less: Accumulated depreciation	5,491		5,377
	12,740		12,444
Land	121		120
Construction in progress	546		448
Property, plant and equipment, net	$	13,407	$	13,012

Capitalized Interest — The total amount of interest capitalized was $4 million and $5 million for the three months ended March 31, 2016 and 2015, respectively.

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 addition, the FASB issued Accounting Standards Update 2016-08 “Principal versus Agent Considerations (Reporting Revenue Gross versus Net)” in March 2016 which clarifies implementation guidance for principal versus agent considerations in the new revenue recognition standard. We are currently assessing the future 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 is effective for fiscal periods beginning after December 15, 2015, including interim periods within that reporting period and allows for either full retrospective or modified retrospective adoption with early adoption permitted. 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 are effective for fiscal years beginning after December 15, 2015, including interim periods within that reporting period and require retrospective adoption with early adoption permitted. 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 is effective for fiscal years beginning after December 15, 2015, including interim periods and allows for either prospective or retrospective adoption with early adoption permitted. 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 future 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 update, with early adoption permitted. We are currently assessing the future impact this standard may have 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 months ended March 31, 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 months ended March 31, 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. 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.

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 classified as held for sale and are reported as other current assets on our Consolidated Condensed Balance Sheet at March 31, 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 three months ended March 31, 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 March 31, 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 months ended March 31, 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 March 31, 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 March 31, 2016	March 31, 2016		December 31, 2015
Greenfield LP	50%	$	71	$	65
Whitby	50%	18		14
Total investments in power plants		$	89	$	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 March 31, 2016 and December 31, 2015, equity method investee debt was approximately $284 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 $142 million and $135 million at March 31, 2016 and December 31, 2015, respectively.

Our equity interest in the net income from Greenfield LP and Whitby for the three months ended March 31, 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 March 31,
	2016			2015
Greenfield LP	$	(4	)	$	(2	)
Whitby	(3		)	(3		)
Total	$	(7	)	$	(5	)

Distributions from Greenfield LP and Whitby were nil during each of the three months ended March 31, 2016 and 2015.


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 March 31, 2016 and December 31, 2015, was as follows (in millions):



	March 31, 2016		December 31, 2015
Senior Unsecured Notes	$	3,408	$	3,406
First Lien Term Loans	3,271		3,277
First Lien Notes	1,790		1,789
Project financing, notes payable and other	1,665		1,715
CCFC Term Loans	1,562		1,565
Capital lease obligations	181		185
Subtotal	11,877		11,937
Less: Current maturities	205		221
Total long-term debt	$	11,672	$	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 swaps, decreased to 5.5% for the three months ended March 31, 2016, from 5.7% for the same period in 2015. The issuance of our 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 Notes and all of our 2018 First Lien Term Loans with debt carrying lower interest rates.

Senior Unsecured Notes

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



	March 31, 2016		December 31, 2015
2023 Senior Unsecured Notes	$	1,235	$	1,235
2024 Senior Unsecured Notes	642		641
2025 Senior Unsecured Notes	1,531		1,530
Total Senior Unsecured Notes	$	3,408	$	3,406

First Lien Term Loans

The amounts outstanding under our First Lien Term Loans are summarized in the table below (in millions):



	March 31, 2016		December 31, 2015
2019 First Lien Term Loan	$	794	$	795
2020 First Lien Term Loan	377		378
2022 First Lien Term Loan	1,568		1,571
2023 First Lien Term Loan	532		533
Total First Lien Term Loans	$	3,271	$	3,277

First Lien Notes

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



	March 31, 2016		December 31, 2015
2022 First Lien Notes	$	738	$	737
2023 First Lien Notes	568		568
2024 First Lien Notes	484		484
Total First Lien Notes	$	1,790	$	1,789

Corporate Revolving Facility and Other Letter of Credit Facilities

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



	March 31, 2016		December 31, 2015
Corporate Revolving Facility⁽¹⁾	$	314	$	316
CDHI	262		241
Various project financing facilities	178		198
Total	$	754	$	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 March 31, 2016 and December 31, 2015 (in millions):



	March 31, 2016				December 31, 2015
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Unsecured Notes	$	3,315	$	3,408	$	3,063	$	3,406
First Lien Term Loans	3,290		3,271		3,197		3,277
First Lien Notes	1,906		1,790		1,885		1,789
Project financing, notes payable and other⁽¹⁾	1,619		1,574		1,653		1,608
CCFC Term Loans	1,544		1,562		1,494		1,565
Total	$	11,674	$	11,605	$	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 swaps. 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 swaps 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.

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



	Assets and Liabilities with Recurring Fair Value Measures as of March 31, 2016
	Level 1		Level 2		Level 3		Total
	(in millions)
Assets:
Cash equivalents⁽¹⁾	$	376	$	—	$	—	$	376
Margin deposits	94		—		—		94
Commodity instruments:
Commodity exchange traded futures and swaps contracts	1,967		—		—		1,967
Commodity forward contracts⁽²⁾	—		250		55		305
Interest rate swaps	—		1		—		1
Total assets	$	2,437	$	251	$	55	$	2,743
Liabilities:
Margin deposits posted with us by our counterparties	$	22	$	—	$	—	$	22
Commodity instruments:
Commodity exchange traded futures and swaps contracts	1,874		—		—		1,874
Commodity forward contracts⁽²⁾	—		468		120		588
Interest rate swaps	—		98		—		98
Total liabilities	$	1,896	$	566	$	120	$	2,582



	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⁾	$	1,083	$	—	$	—	$	1,083
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 swaps	—		1		—		1
Total assets	$	2,908	$	221	$	54	$	3,183
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 swaps	—		90		—		90
Total liabilities	$	1,639	$	503	$	100	$	2,242

___________


(1)	As of March 31, 2016 and December 31, 2015, we had cash equivalents of $216 million and $880 million included in cash and cash equivalents and $160 million and $203 million included in restricted cash, respectively.


(2)	Includes OTC swaps and options.

At March 31, 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 March 31, 2016 and December 31, 2015:



	Quantitative Information about Level 3 Fair Value Measurements
	March 31, 2016
	Fair Value, Net Asset				Significant Unobservable
	(Liability)			Valuation Technique	Input	Range
	(in millions)
Power Contracts	$	(77	)	Discounted cash flow	Market price (per MWh)	$4.95 — $100.54/MWh
Power Congestion Products	$	12		Discounted cash flow	Market price (per MWh)	$(11.33) — $10.38/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 March 31,
	2016			2015
Balance, beginning of period	$	(46	)	$	85
Realized and mark-to-market gains (losses):
Included in net loss:
Included in operating revenues⁽¹⁾	(22		)	131
Included in fuel and purchased energy expense⁽²⁾	(14		)	3
Purchases and settlements:
Purchases	2			2
Settlements	(4		)	(10		)
Transfers in and/or out of level 3⁽³⁾:
Transfers into level 3⁽⁴⁾	—			(1		)
Transfers out of level 3⁽⁵⁾	19			(7		)
Balance, end of period	$	(65	)	$	203
Change in unrealized gains (losses) relating to instruments still held at end of period	$	(36	)	$	134

___________


(1)	For power contracts and other power-related products, included on our Consolidated Condensed Statements of Operations.


(2)	For natural gas contracts, swaps and options, included on our Consolidated Condensed Statements of Operations.


(3)	We transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no transfers into or out of level 1 for each of the three months ended March 31, 2016 and 2015.


(4)	There were no transfers out of level 2 into level 3 for the three months ended March 31, 2016. We had $1 million in losses transferred out of level 2 into level 3 for the three months ended March 31, 2015.


(5)	We had $(19) million in losses and $7 million in gains transferred out of level 3 into level 2 for the three months ended March 31, 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 the three months ended March 31, 2016 and 2015.

Interest Rate Swaps — A portion of our debt is indexed to base rates, primarily LIBOR. We have historically used interest rate swaps to adjust the mix between fixed and floating rate debt to hedge our interest rate risk for potential adverse changes in interest rates. As of March 31, 2016, the maximum length of time over which we were hedging using interest rate derivative instruments designated as cash flow hedges was 8 years.

As of March 31, 2016 and December 31, 2015, the net forward notional buy (sell) position of our outstanding commodity and interest rate swap contracts 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	March 31, 2016			December 31, 2015
Power (MWh)	(49		)	(41		)
Natural gas (MMBtu)	1,065			996
Environmental credits (Tonnes)	17			8
Interest rate swaps	$	1,308		$	1,320

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 March 31, 2016, was $57 million for which we have posted collateral of $7 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 $14 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 derivative instruments. We report the effective portion of the mark-to-market gain or loss on our interest rate swaps 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 March 31, 2016 and December 31, 2015 (in millions):



	March 31, 2016
	Commodity Instruments			Interest Rate Swaps			Total Derivative Instruments
Balance Sheet Presentation
Current derivative assets	$	1,853		$	—		$	1,853
Long-term derivative assets	419			1			420
Total derivative assets	$	2,272		$	1		$	2,273

Current derivative liabilities	$	1,938		$	37		$	1,975
Long-term derivative liabilities	524			61			585
Total derivative liabilities	$	2,462		$	98		$	2,560
Net derivative assets (liabilities)	$	(190	)	$	(97	)	$	(287	)



	December 31, 2015
	Commodity Instruments			Interest Rate Swaps			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	)



	March 31, 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 swaps	$	1	$	100		$	1	$	92
Total derivatives designated as cash flow hedging instruments	$	1	$	100		$	1	$	92

Derivatives not designated as hedging instruments:
Commodity instruments	$	2,272	$	2,462		$	2,010	$	2,117
Interest rate swaps	—		(2		)	—		(2		)
Total derivatives not designated as hedging instruments	$	2,272	$	2,460		$	2,010	$	2,115
Total derivatives	$	2,273	$	2,560		$	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 March 31, 2016 and December 31, 2015 (in millions):



	March 31, 2016
	Gross Amounts Not Offset on the Consolidated Condensed Balance Sheets
	Gross Amounts Presented on our Consolidated Condensed Balance Sheets			Derivative Asset (Liability) not Offset on the Consolidated Condensed Balance Sheets			Margin/Cash (Received) Posted⁽¹⁾			Net Amount
Derivative assets:
Commodity exchange traded futures and swaps contracts	$	1,967		$	(1,874	)	$	(93	)	$	—
Commodity forward contracts	305			(230		)	(7		)	68
Interest rate swaps	1			—			—			1
Total derivative assets	$	2,273		$	(2,104	)	$	(100	)	$	69
Derivative (liabilities):
Commodity exchange traded futures and swaps contracts	$	(1,874	)	$	1,874		$	—		$	—
Commodity forward contracts	(588		)	230			1			(357		)
Interest rate swaps	(98		)	—			—			(98		)
Total derivative (liabilities)	$	(2,560	)	$	2,104		$	1		$	(455	)
Net derivative assets (liabilities)	$	(287	)	$	—		$	(99	)	$	(386	)



	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 swaps	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 swaps	(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 March 31,
	2016			2015
Realized gain (loss)⁽¹⁾⁽²⁾
Commodity derivative instruments	$	118		$	59
Total realized gain (loss)	$	118		$	59

Mark-to-market gain (loss)⁽³⁾
Commodity derivative instruments	$	(95	)	$	70
Interest rate swaps	1			1
Total mark-to-market gain (loss)	$	(94	)	$	71
Total activity, net	$	24		$	130

___________


(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 March 31,
	2016			2015
Realized and mark-to-market gain (loss)
Derivatives contracts included in operating revenues⁽¹⁾	$	204		$	119
Derivatives contracts included in fuel and purchased energy expense⁽¹⁾	(181		)	10
Interest rate swaps included in interest expense	1			1
Total activity, net	$	24		$	130

___________


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

Derivatives Included in OCI and AOCI

The following table details the effect of our net derivative instruments that qualified for hedge accounting treatment and are included in OCI and AOCI for the periods indicated (in millions):



	Three Months Ended March 31,						Three Months Ended March 31,
	Gain (Loss) Recognized in OCI (Effective Portion)						Gain (Loss) Reclassified from AOCI into Income (Effective Portion)⁽³⁾
	2016			2015			2016			2015			Affected Line Item on the Consolidated Condensed Statements of Operations
Interest rate swaps⁽¹⁾⁽²⁾	$	(12	)	$	(6	)	$	(11	)	$	(12	)	Interest expense

____________


(1)	We did not record any material gain (loss) on hedge ineffectiveness related to our interest rate swaps designated as cash flow hedges during the three months ended March 31, 2016 and 2015.


(2)	We recorded an income tax expense of nil for each of the three months ended March 31, 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 $137 million and $127 million at March 31, 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 March 31, 2016 and December 31, 2015, respectively.

We estimate that pre-tax net losses of $41 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 swap agreements in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to the counterparties under such agreements. The counterparties under such agreements share the benefits of the collateral subject to such first priority liens pro rata with the lenders under our various debt agreements.

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



	March 31, 2016		December 31, 2015
Margin deposits⁽¹⁾	$	94	$	89
Natural gas and power prepayments	36		34
Total margin deposits and natural gas and power prepayments with our counterparties⁽²⁾	$	130	$	123

Letters of credit issued	$	629	$	600
First priority liens under power and natural gas agreements⁽³⁾	389		382
First priority liens under interest rate swap agreements	100		92
Total letters of credit and first priority liens with our counterparties	$	1,118	$	1,074

Margin deposits posted with us by our counterparties⁽¹⁾⁽⁴⁾	$	22	$	35
Letters of credit posted with us by our counterparties	39		24
Total margin deposits and letters of credit posted with us by our counterparties	$	61	$	59

___________

(1)

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


(2)	At March 31, 2016 and December 31, 2015, $116 million and $101 million, respectively, were included in margin deposits and other prepaid expense and $14 million and $22 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets.


(3)	Includes $364 million and $345 million related to first priority liens under power supply contracts associated with our retail hedging activities at March 31, 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 March 31,
	2016			2015
Income tax expense (benefit)	$	35		$	(1	)
Effective tax rate	(21		)%	9		%

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 months ended March 31, 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 March 31, 2016, we had unrecognized tax benefits of $57 million. If recognized, $17 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 $12 million for income tax matters at March 31, 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.	Loss per Share

We include restricted stock units for which no future service is required as a condition to the delivery of the underlying common stock in our calculation of weighted average shares outstanding. As we incurred a net loss for the three months ended March 31, 2016 and 2015, diluted loss per share for each period is computed on the same basis as basic loss per share, as the inclusion of any other potential shares outstanding would be anti-dilutive. We excluded the following items from diluted earnings per common share for the three months ended March 31, 2016 and 2015, because they were anti-dilutive (shares in thousands):


10.	Stock-Based Compensation

Equity Classified Share-Based Awards

Stock-based compensation expense recognized for our equity classified share-based awards was $7 million and $9 million for the three months ended March 31, 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 three months ended March 31, 2016 and 2015. At March 31, 2016, there was unrecognized compensation cost of $45 million related to restricted stock which is expected to be recognized over a weighted average period of 1.9 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 three months ended March 31, 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	2,836,587	$	12.30
Forfeited	64,334	$	16.73
Vested	1,214,161	$	19.02
Nonvested — March 31, 2016	5,086,362	$	15.92

The total fair value of our restricted stock and restricted stock units that vested during the three months ended March 31, 2016 and 2015 was approximately $15 million and $32 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 $2 million for each of the three months ended March 31, 2016 and 2015.

A summary of our performance share unit activity for the three months ended March 31, 2016, is as follows:



	Number of Performance Share Units	Weighted Average Grant-Date Fair Value
Nonvested — December 31, 2015	517,906	$	23.36
Granted	627,957	$	14.81
Vested⁽¹⁾	3,249	$	23.91
Nonvested — March 31, 2016	1,142,614	$	18.66

___________


(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. The BAAQMD continues to reserve its rights to assert any penalty claims associated with this violation and RCEC continues to reserve its rights to assert any defenses to such claims in future proceedings.


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 March 31, 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 March 31, 2016
	West		Texas			East			Consolidation and Elimination			Total
Revenues from external customers	$	424	$	532		$	659		$	—		$	1,615
Intersegment revenues	2		3			3			(8		)	—
Total operating revenues	$	426	$	535		$	662		$	(8	)	$	1,615
Commodity Margin	$	197	$	153		$	230		$	—		$	580
Add: Mark-to-market commodity activity, net and other⁽¹⁾	46		(110		)	(21		)	(6		)	(91		)
Less:
Plant operating expense	91		86			84			(6		)	255
Depreciation and amortization expense	69		53			58			—			180
Sales, general and other administrative expense	10		16			12			—			38
Other operating expenses	8		2			10			—			20
(Income) from unconsolidated investments in power plants	—		—			(7		)	—			(7		)
Income (loss) from operations	65		(114		)	52			—			3
Interest expense, net of interest income												156
Other (income) expense, net												6
Loss before income taxes												$	(159	)



	Three Months Ended March 31, 2015
	West		Texas		East			Consolidation and Elimination			Total
Revenues from external customers	$	515	$	581	$	550		$	—		$	1,646
Intersegment revenues	2		3		2			(7		)	—
Total operating revenues	$	517	$	584	$	552		$	(7	)	$	1,646
Commodity Margin	$	218	$	149	$	168		$	—		$	535
Add: Mark-to-market commodity activity, net and other⁽¹⁾	119		41		(52		)	(7		)	101
Less:
Plant operating expense	106		89		72			(7		)	260
Depreciation and amortization expense	67		49		42			—			158
Sales, general and other administrative expense	10		17		10			—			37
Other operating expenses	10		2		8			—			20
(Income) from unconsolidated investments in power plants	—		—		(5		)	—			(5		)
Income (loss) from operations	144		33		(11		)	—			166
Interest expense, net of interest income											153
Debt extinguishment costs and other (income) expense, net											21
Loss before income taxes											$	(8	)

_________


(1)	Includes $(22) million and $(24) million of lease levelization and $27 million and $4 million of amortization expense for the three months ended March 31, 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 on a per share basis 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 25 million MWh of electricity during the three months ended March 31, 2016.


•	During the first quarter of 2016, our employees achieved a total recordable incident rate of 0.79 recordable injuries per 100 employees 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 97.6% during the three months ended March 31, 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. 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.


•	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.

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.

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

In April 2016, the Maryland legislature passed the Clean Energy Jobs Act, which will expand the current RPS from 20% by 2022, with a 2% solar carve-out, to 25% by 2020, with a 2.5% solar carve-out. The legislation is now awaiting the Governor’s signature.

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 greenhouse gas 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 greenhouse gases. 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 have been 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 are directed to file to modify their market-based rate tariffs to clarify that the affiliate sales restrictions will apply to the PPAs. Neither AEP nor FE have filed at 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, stakeholders in the New England Power Pool approved changes to the operation of the Forward Capacity Market involving the use of revised demand curve parameters. Any such changes remain subject to FERC approval and 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.

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

MATS and CSAPR have been heavily litigated since their promulgation and judicial challenges continue. On March 3, 2016, the U.S. Supreme Court denied a request to stay MATS while the remaining legal challenges proceed; thus, power plants must continue to comply with MATS. MATS and CSAPR primarily impact coal-fired power plants; therefore, judicial decisions related to 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 June 2, 2016 in the U.S. Court of Appeals for the District of Columbia Circuit (“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.

RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 2016 AND 2015

Below are our results of operations for the three months ended March 31, 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	$	1,585		$	1,638		$	(53	)	(3	)
Mark-to-market gain	25			3			22			#
Other revenue	5			5			—			—
Operating revenues	1,615			1,646			(31		)	(2	)
Operating expenses:
Fuel and purchased energy expense:
Commodity expense	1,006			1,077			71			7
Mark-to-market (gain) loss	120			(67		)	(187		)	#
Fuel and purchased energy expense	1,126			1,010			(116		)	(11	)
Plant operating expense	255			260			5			2
Depreciation and amortization expense	180			158			(22		)	(14	)
Sales, general and other administrative expense	38			37			(1		)	(3	)
Other operating expenses	20			20			—			—
Total operating expenses	1,619			1,485			(134		)	(9	)
(Income) from unconsolidated investments in power plants	(7		)	(5		)	2			40
Income from operations	3			166			(163		)	(98	)
Interest expense	157			154			(3		)	(2	)
Interest (income)	(1		)	(1		)	—			—
Debt extinguishment costs	—			19			19			#
Other (income) expense, net	6			2			(4		)	#
Loss before income taxes	(159		)	(8		)	(151		)	#
Income tax expense (benefit)	35			(1		)	(36		)	#
Net loss	(194		)	(7		)	(187		)	#
Net income attributable to the noncontrolling interest	(4		)	(3		)	(1		)	(33	)
Net loss attributable to Calpine	$	(198	)	$	(10	)	$	(188	)	#



	2016		2015		Change		% Change
Operating Performance Metrics:
MWh generated (in thousands)⁽¹⁾⁽²⁾	24,125		25,567		(1,442	)	(6	)
Average availability⁽²⁾	89.9	%	89.4	%	0.5	%	1
Average total MW in operation⁽¹⁾	26,238		25,768		470		2
Average capacity factor, excluding peakers	47.4	%	52.0	%	(4.6	)%	(9	)
Steam Adjusted Heat Rate⁽²⁾	7,264		7,262		(2	)	—

__________


#	Variance of 100% or greater


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


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

We evaluate our Commodity revenue and Commodity expense on a collective basis because the price of power and natural gas tend to move together as the price for power is generally determined by the variable operating cost of the next marginal generator to be dispatched to meet demand. The spread between our Commodity revenue and Commodity expense represents a significant portion of our Commodity Margin. Our financial performance is correlated to how we maximize our Commodity Margin through management of our portfolio of power plants, as well as our hedging and optimization activities. See additional segment discussion in “Commodity Margin and Adjusted EBITDA.”

Commodity revenue, net of Commodity expense, increased $18 million for the three months ended March 31, 2016, compared to the same period in 2015, primarily due to:


+	higher contribution from hedges, including retail,


+	higher regulatory capacity revenue in PJM and ISO-NE, and

the net impact of our portfolio management activities, including approximately two months of operation of our 695 MW Granite Ridge Energy Center, which was acquired on February 5, 2016, a full quarter of operation of our 309 MW Garrison Energy Center, which commenced commercial operations in June 2015, partially offset by the expiration of the operating lease related to the Greenleaf power plants in June 2015,


–	a decrease in generation and lower market Spark Spreads in the West resulting from lower natural gas prices in the first quarter of 2016 and an increase in hydroelectric generation in California and the Pacific Northwest in March 2016, and


–	the expiration of a tolling contract associated with our Pastoria Energy Center in December 2015.

Generation decreased 6% primarily due to an increase in hydroelectric generation in the West and milder weather in Texas and the East. Average total MW in operation increased 470 MW, or 2%, resulting primarily from the aforementioned changes in our power plant portfolio.

Mark-to-market gain/loss from hedging our future generation, retail activities and fuel needs had an unfavorable variance of $165 million primarily driven by the impact of a decrease in forward power and natural gas prices on our forward derivative contracts during the quarter ended March 31, 2016 compared to the same period in 2015.

Our normal, recurring plant operating expense decreased by $7 million for the three months ended March 31, 2016 compared to the same period in 2015 after excluding a $12 million increase attributable to power plant portfolio changes, a $3 million increase in equipment failure costs related to outages and a $14 million decrease in major maintenance expense resulting from our plant outage schedule.

Depreciation and amortization expense increased by $22 million for the three months ended March 31, 2016, compared to the same period in 2015, primarily due to the acquisitions of Champion Energy and Granite Ridge Energy Center, commencement of commercial operations at our Garrison Energy Center in June 2015 and the reassessment of certain assets’ useful lives and carrying values.

Debt extinguishment costs for the three months ended March 31, 2015 consisted of $19 million in connection with the repurchase of approximately $147 million of our 2023 First Lien Notes, which is comprised of $18 million of prepayment penalties and $1 million associated with the write-off of deferred financing costs.

During the three months ended March 31, 2016, we recorded an income tax expense of $35 million compared to an income tax benefit of $1 million for the three months ended March 31, 2015. The unfavorable period-over-period change primarily resulted from estimated state income tax expense in jurisdictions where we do not have NOLs.

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 March 31, 2016 and 2015

The following tables show our Commodity Margin and related operating performance metrics by segment for the three months ended March 31, 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)	$	197		$	218		$	(21	)	(10	)
Commodity Margin per MWh generated	$	30.69		$	30.06		$	0.63		2

MWh generated (in thousands)	6,418			7,253			(835		)	(12	)
Average availability	90.3		%	88.3		%	2.0		%	2
Average total MW in operation	7,425			7,524			(99		)	(1	)
Average capacity factor, excluding peakers	42.9		%	47.7		%	(4.8		)%	(10	)
Steam Adjusted Heat Rate	7,329			7,301			(28		)	—

West — Commodity Margin in our West segment decreased by $21 million, or 10%, for the three months ended March 31, 2016 compared to the three months ended March 31, 2015, primarily due to:


–	a decrease in generation and lower market Spark Spreads resulting from lower natural gas prices in the first quarter of 2016 and an increase in hydroelectric generation in California and the Pacific Northwest in March 2016, and


–	the expiration of a tolling contract associated with 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)	$	153		$	149		$	4		3
Commodity Margin per MWh generated	$	13.60		$	12.91		$	0.69		5

MWh generated (in thousands)	11,249			11,544			(295		)	(3	)
Average availability	86.6		%	88.1		%	(1.5		)%	(2	)
Average total MW in operation	9,191			9,191			—			—
Average capacity factor, excluding peakers	56.0		%	58.2		%	(2.2		)%	(4	)
Steam Adjusted Heat Rate	7,049			7,096			47			1

Texas — Commodity Margin in our Texas segment increased by $4 million, or 3%, for the three months ended March 31, 2016 compared to the three months ended March 31, 2015, primarily due to:


+	higher contribution from hedges, including retail, partially offset by


–	lower market Spark Spreads, primarily resulting from milder weather in the first quarter of 2016.



East:	2016			2015			Change			% Change
Commodity Margin (in millions)	$	230		$	168		$	62		37
Commodity Margin per MWh generated	$	35.61		$	24.82		$	10.79		43

MWh generated (in thousands)	6,458			6,770			(312		)	(5	)
Average availability	92.8		%	91.7		%	1.1		%	1
Average total MW in operation	9,622			9,053			569			6
Average capacity factor, excluding peakers	40.6		%	47.9		%	(7.3		)%	(15	)
Steam Adjusted Heat Rate	7,597			7,516			(81		)	(1	)

East — Commodity Margin in our East segment increased by $62 million, or 37%, for the three months ended March 31, 2016 compared to the three months ended March 31, 2015, primarily due to:


+	higher contribution from hedges, including retail,


+	higher regulatory capacity revenue in PJM and ISO-NE, and


+	approximately two months of operation of our 695 MW Granite Ridge Energy Center, which was acquired on February 5, 2016, and a full quarter of operation of our 309 MW Garrison Energy Center, which commenced commercial operations in June 2015, partially offset by


–	a decrease in generation at our legacy power plants due to 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 extraordinary, 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 loss attributable to Calpine on a consolidated basis for the periods indicated (in millions).



	Three Months Ended March 31, 2016
	West			Texas			East			Consolidation and Elimination		Total
Net loss attributable to Calpine												$	(198	)
Net income attributable to the noncontrolling interest												4
Income tax expense												35
Other (income) expense, net												6
Interest expense, net of interest income												156
Income (loss) from operations	$	65		$	(114	)	$	52		$	—	$	3
Add:
Adjustments to reconcile income (loss) from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs⁽¹⁾	68			53			58			—		179
Major maintenance expense	17			22			25			—		64
Operating lease expense	—			—			6			—		6
Mark-to-market (gain) loss on commodity derivative activity	(23		)	97			21			—		95
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest⁽²⁾	(4		)	—			9			—		5
Stock-based compensation expense	3			4			2			—		9
Loss on dispositions of assets	—			1			1			—		2
Contract amortization	—			21			6			—		27
Other	(13		)	—			(3		)	—		(16		)
Total Adjusted EBITDA	$	113		$	84		$	177		$	—	$	374



	Three Months Ended March 31, 2015
	West			Texas			East			Consolidation and Elimination		Total
Net loss attributable to Calpine												$	(10	)
Net income attributable to the noncontrolling interest												3
Income tax benefit												(1		)
Debt extinguishment costs and other (income) expense, net												21
Interest expense, net of interest income												153
Income (loss) from operations	$	144		$	33		$	(11	)	$	—	$	166
Add:
Adjustments to reconcile income (loss) from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs⁽¹⁾	65			50			42			—		157
Major maintenance expense	25			31			22			—		78
Operating lease expense	3			—			6			—		9
Mark-to-market (gain) loss on commodity derivative activity	(87		)	(33		)	50			—		(70		)
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest⁽²⁾	(3		)	—			8			—		5
Stock-based compensation expense	4			5			2			—		11
Loss on dispositions of assets	—			—			1			—		1
Contract amortization	—			—			4			—		4
Other	(24		)	—			1			—		(23		)
Total Adjusted EBITDA	$	127		$	86		$	125		$	—	$	338

____________


(1)	Depreciation and amortization expense in the income from operations calculation on our Consolidated Condensed Statements of Operations excludes amortization of other assets.


(2)	Adjustments to reflect Adjusted EBITDA from unconsolidated investments include (gain) loss on mark-to-market activity of nil for each of the three months ended March 31, 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 March 31, 2016 and December 31, 2015 (in millions):



	March 31, 2016		December 31, 2015
Cash and cash equivalents, corporate⁽¹⁾	$	183	$	850
Cash and cash equivalents, non-corporate	61		56
Total cash and cash equivalents⁽²⁾	244		906
Restricted cash	184		228
Corporate Revolving Facility availability⁽³⁾	1,364		1,184
CDHI letter of credit facility availability	38		59
Total current liquidity availability⁽⁴⁾	$	1,830	$	2,377

____________


(1)	Includes $22 million and $35 million of margin deposits posted with us by our counterparties at March 31, 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 three months ended March 31, 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, 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 March 31, 2016, an increase of $1/MMBtu in natural gas prices would result in an increase of collateral required by approximately $256 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 March 31, 2016, an increase of 500 Btu/KWh in the Market Heat Rate would result in an increase in collateral required by approximately $52 million. If Market Heat Rates were to fall at a similar rate, we estimate that our collateral required would decrease by approximately $33 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 March 31, 2016 and December 31, 2015 (in millions):



	March 31, 2016		December 31, 2015
Corporate Revolving Facility⁽¹⁾	$	314	$	316
CDHI	262		241
Various project financing facilities	178		198
Total	$	754	$	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

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.

Garrison Energy Center — We are in the early stages of development of a second phase of the Garrison Energy Center that will add approximately 450 MW of dual-fuel, combined-cycle capacity to our existing Garrison Energy Center. PJM has completed the project’s system impact study and the facilities study is underway.

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 2017/2018 and 2018/2019 base residual auctions. The project is now under construction, and we expect COD during the second 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 2018/2019 base residual auction.

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.

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.

PJM and ISO-NE Development Opportunities — We are currently evaluating opportunities to develop additional projects in the PJM and ISO-NE market areas that feature cost advantages such as existing infrastructure and favorable transmission queue positions. These projects are continuing to advance entitlements (such as permits, zoning and transmission) for their potential future development when economical.

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. 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 27-month PPA. 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.

Turbine Modernization — We continue to move forward with our turbine modernization program. Through March 31, 2016, we have completed the upgrade of 13 Siemens and eight GE turbines totaling approximately 210 MW and have committed to upgrade three additional turbines. In addition, we have begun a program to update our dual-fueled turbines at certain of our power plants in our East segment.

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.

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 more than 80% of the normal operating capacity and will be restored to pre-fire levels once repairs are completed, which is expected during the third quarter 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. We do not anticipate the impact of the wildfire or timing of insurance proceeds recovery will 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 three months ended March 31, 2016 and 2015 (in millions):



	2016			2015
Beginning cash and cash equivalents	$	906		$	717
Net cash provided by (used in):
Operating activities	26			(17		)
Investing activities	(611		)	(128		)
Financing activities	(77		)	224
Net increase (decrease) in cash and cash equivalents	(662		)	79
Ending cash and cash equivalents	$	244		$	796

Net Cash Provided By (Used In) Operating Activities

Cash provided by operating activities for the three months ended March 31, 2016, was $26 million compared to cash used in operating activities of $17 million for the three months ended March 31, 2015. The increase was primarily due to:

•

Income from operations — Income from operations, adjusted for non-cash items, increased by $49 million for the three months ended March 31, 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 $53 million increase in Commodity revenue, net of Commodity expense, excluding non-cash amortization of intangible assets. See “Results of Operations for the Three Months Ended March 31, 2016 and 2015” above for further discussion of these changes.

•

Working capital employed — Working capital employed increased by $24 million for the three months ended March 31, 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 an increase in net accounts receivable/accounts payable balances as a result of higher Commodity Margin for the three months ended March 31, 2016, compared to the same period in 2015.


•	Debt extinguishment payments — During the three months ended March 31, 2015, we made cash payments of $18 million related to prepayment penalties in connection with the partial repurchase of our 2023 First Lien Notes. There was no similar activity for the first quarter of 2016.

Net Cash Used In Investing Activities

Cash used in investing activities for the three months ended March 31, 2016, was $611 million compared to $128 million for the three months ended March 31, 2015. The increase was primarily due to:


•	Purchase of Granite Ridge Energy Center — During the three months ended March 31, 2016, we purchased a natural gas-fired, combined-cycle power plant located in Londonderry, New Hampshire for $527 million. There were no acquisitions during the first quarter of 2015.


•	Capital expenditures — Capital expenditures for the three months ended March 31, 2016, were $133 million, a decrease of $29 million, compared to expenditures of $162 million for the three months ended March 31, 2015. The decrease was primarily due to lower expenditures on construction projects and outages during the first quarter of 2016 as compared to the first quarter of 2015.

Net Cash Provided By (Used In) Financing Activities

Cash used in financing activities for the three months ended March 31, 2016, was $77 million compared to cash provided by financing activities of $224 million for the three months ended March 31, 2015. The decrease was primarily due to:

•

First Lien Notes and Senior Unsecured Notes — During the three months ended March 31, 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 our 2023 First Lien Notes and for general corporate purposes. There were no similar activities during the first quarter of 2016.


•	Stock repurchases — During the three months ended March 31, 2016, we repurchased an insignificant amount of common stock as compared to $202 million paid to repurchase our common stock during the three months ended March 31, 2015.

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 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 swaps to adjust the mix between our fixed and variable rate debt. To the extent eligible, our interest rate swaps 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 swaps. Since prices for power and natural gas and interest rates are volatile, there may be material changes in the fair value of our derivatives over time, driven both by price volatility and the changes in volume of open derivative transactions. Our derivative assets have increased to approximately $2.3 billion at March 31, 2016, when compared to approximately $2.0 billion at December 31, 2015, and our derivative liabilities have increased to approximately $2.6 billion at March 31, 2016, when compared to approximately $2.2 billion at December 31, 2015. The fair value of our level 3 derivative assets and liabilities at March 31, 2016 represent a small portion of our total assets and liabilities measured at fair value (approximately 2% and 5%, 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 derivative instruments from January 1, 2016, through March 31, 2016, is summarized in the table below (in millions):



	Commodity Instruments			Interest Rate Swaps			Total
Fair value of contracts outstanding at January 1, 2016	$	(107	)	$	(89	)	$	(196	)
Items recognized or otherwise settled during the period⁽¹⁾⁽²⁾	(42		)	10			(32		)
Fair value attributable to new contracts	(22		)	—			(22		)
Changes in fair value attributable to price movements	(18		)	(18		)	(36		)
Changes in fair value attributable to nonperformance risk	(1		)	—			(1		)
Fair value of contracts outstanding at March 31, 2016⁽³⁾	$	(190	)	$	(97	)	$	(287	)

__________

(1)

Commodity contract settlements consist of the realization of previously recognized gains on contracts not designated as hedging instruments of $52 million (represents a portion of Commodity revenue and Commodity expense as reported on our Consolidated Condensed Statements of Operations) and $10 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 $10 million related to realized losses from settlements of designated cash flow hedges (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 March 31,
	2016			2015
Realized gain (loss)⁽¹⁾⁽²⁾
Commodity derivative instruments	$	118		$	59
Total realized gain (loss)	$	118		$	59

Mark-to-market gain (loss)⁽³⁾
Commodity derivative instruments	$	(95	)	$	70
Interest rate swaps	1			1
Total mark-to-market gain (loss)	$	(94	)	$	71
Total activity, net	$	24		$	130

___________


(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 March 31,
	2016			2015
Realized and mark-to-market gain (loss)
Derivatives contracts included in operating revenues⁽¹⁾	$	204		$	119
Derivatives contracts included in fuel and purchased energy expense⁽¹⁾	(181		)	10
Interest rate swaps included in interest expense	1			1
Total activity, net	$	24		$	130

___________


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

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

The net fair value of outstanding derivative commodity instruments at March 31, 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	$	70		$	22		$	1		$	—	$	93
Prices provided by other external sources	(133		)	(108		)	(23		)	—		(264		)
Prices based on models and other valuation methods	(13		)	(11		)	5			—		(19		)
Total fair value	$	(76	)	$	(97	)	$	(17	)	$	—	$	(190	)

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 market movements in comparison to internally established thresholds. 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 months ended March 31, 2016 and 2015 (in millions):



	2016		2015
Three months ended March 31:
High	$	31	$	38
Low	$	15	$	21
Average	$	22	$	30
As of March 31	$	17	$	21

Due to the inherent limitations of statistical measures such as VAR, the VAR calculation may not capture the full extent of our commodity price exposure. As a result, actual changes in the value of our energy commodity portfolio could be different from the calculated VAR, and could have a material 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 the liquidity of the market and 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 March 31, 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 March 31, 2016)	2016			2017-2018			2019-2020			After 2020		Total
Investment grade	$	(60	)	$	(102	)	$	(21	)	$	—	$	(183	)
Non-investment grade	(5		)	5			3			—		3
No external ratings	(11		)	—			1			—		(10		)
Total fair value	$	(76	)	$	(97	)	$	(17	)	$	—	$	(190	)

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 swaps are validated based upon external quotes. Our interest rate swaps are with counterparties we believe are primarily high quality institutions, and we do not believe that our interest rate swaps 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 swaps hedging our variable rate debt of approximately $(4) million at March 31, 2016.

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 first 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, such as the actions taken in Ohio, could adversely impact our competitive position and business.

Certain states in the PJM market, including Ohio, 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 PJM power market. We are actively participating at PJM and in regulatory and judicial processes challenging these actions at the state and federal levels. If the processes result in these anticompetitive actions being upheld, they could have an adverse impact on capacity and energy prices in the deregulated PJM electricity markets which in turn could have a 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⁾
January	11,348	$	13.39	7,800	$	307
February	408,456	$	12.40	14,727	$	307
March	1,623	$	13.91	—	$	307
Total	421,427	$	12.43	22,527	$	307

___________


(1)	To satisfy tax withholding obligations associated with the vesting of restricted stock awarded to employees during the first quarter of 2016, we withheld a total of 398,900 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

10.1		Form of Performance Share Unit Award Agreement Under the Amended and Restated Calpine Corporation 2008 Equity Incentive Plan between the Company and W. Thaddeus Miller. †

10.2		Form of Performance Share Unit Award Agreement Under the Amended and Restated Calpine Corporation 2008 Equity Incentive Plan between the Company and Certain Designated Senior Employees. †

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

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

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

101.INS		XBRL Instance Document.

101.SCH		XBRL Taxonomy Extension Schema.

101.CAL		XBRL Taxonomy Extension Calculation Linkbase.

101.DEF		XBRL Taxonomy Extension Definition Linkbase.

101.LAB		XBRL Taxonomy Extension Label Linkbase.

101.PRE		XBRL Taxonomy Extension Presentation Linkbase.

_______________


*	Furnished herewith.


†	Management contract or compensatory plan, contract or arrangement.

SIGNATURES

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



CALPINE CORPORATION
(Registrant)

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

Date: April 28, 2016

Three Months Ended March 31,

Share-based awards