CALPINE CORP - FORM 10-Q - October 29, 2015

Attached files

file	filename
EX-31.1 - SECTION 302 CERTIFICATION OF CHIEF EXECUTIVE OFFICER - CALPINE CORP	cpn_exhibit311x09302015.htm
EX-31.2 - SECTION 302 CERTIFICATION OF CHIEF FINANCIAL OFFICER - CALPINE CORP	cpn_exhibit312x09302015.htm
EX-10.1 - EMPLOYMENT SEPARATION AGREEMENT - CALPINE CORP	cpn_exhibit101xemployments.htm
EX-32.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER - CALPINE CORP	cpn_exhibit321x09302015.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 September 30, 2015

		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. (Check one):



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: 356,841,902 shares of common stock, par value $0.001, were outstanding as of October 28, 2015.

CALPINE CORPORATION AND SUBSIDIARIES

REPORT ON FORM 10-Q

For the Quarter Ended September 30, 2015

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 and Nine Months Ended September 30, 2015 and 2014	1
Consolidated Condensed Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2015 and 2014	2
Consolidated Condensed Balance Sheets at September 30, 2015 and December 31, 2014	3
Consolidated Condensed Statements of Cash Flows for the Nine Months Ended September 30, 2015 and 2014	4
Notes to Consolidated Condensed Financial Statements	6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Forward-Looking Information	27
Introduction and Overview	27
Results of Operations	33
Commodity Margin and Adjusted EBITDA	37
Liquidity and Capital Resources	45
Risk Management and Commodity Accounting	52
New Accounting Standards and Disclosure Requirements	56
Item 3. Quantitative and Qualitative Disclosures About Market Risk	56
Item 4. Controls and Procedures	56

PART II – OTHER INFORMATION

Item 1. Legal Proceedings	57
Item 1A. Risk Factors	57
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	58
Item 3. Defaults Upon Senior Securities	58
Item 4. Mine Safety Disclosures	58
Item 5. Other Information	58
Item 6. Exhibits	59
Signatures	60

DEFINITIONS

As used in this report for the quarter ended September 30, 2015 (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
2014 Form 10-K		Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2014, filed with the SEC on February 13, 2015

2018 First Lien Term Loans		Collectively, the $1.3 billion first lien senior secured term loan dated March 9, 2011 and the $360 million first lien senior secured term loan dated June 17, 2011

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 hereto, 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 hereto, 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 hereto, 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

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

AB 32		California Assembly Bill 32

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

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

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

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

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

CFTC		Commodity 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 and New York

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 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

iii



ABBREVIATION		DEFINITION

Corporate Revolving Facility		The $1.5 billion aggregate amount revolving credit facility credit agreement, dated as of December 10, 2010, as amended on June 27, 2013 and July 30, 2014, among Calpine Corporation, Goldman Sachs Bank USA, as administrative agent, Goldman Sachs Credit Partners L.P., as collateral agent, the lenders party thereto and the other parties thereto

CPUC		California Public Utilities Commission

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

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

EPA		U.S. Environmental Protection Agency

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 2018 First Lien Term Loans, the 2019 First Lien Term Loan, the 2020 First Lien Term Loan and the 2022 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

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



ABBREVIATION		DEFINITION
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)

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 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 revenues 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, fuel oil and 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 2014 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 soon after such reports 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 September 30,						Nine Months Ended September 30,
		2015			2014			2015			2014
	(in millions, except share and per share amounts)
Operating revenues:
Commodity revenue		$	1,888		$	2,186		$	4,933		$	6,000
Mark-to-market gain (loss)		55			(2		)	89			81
Other revenue		5			3			14			10
Operating revenues		1,948			2,187			5,036			6,091
Operating expenses:
Fuel and purchased energy expense:
Commodity expense		943			1,281			2,754			3,757
Mark-to-market (gain) loss		130			(13		)	95			2
Fuel and purchased energy expense		1,073			1,268			2,849			3,759
Plant operating expense		200			215			732			754
Depreciation and amortization expense		166			153			484			453
Sales, general and other administrative expense		33			37			100			108
Other operating expenses		16			23			56			66
Total operating expenses		1,488			1,696			4,221			5,140
Impairment losses		—			123			—			123
(Gain) on sale of assets, net		—			(753		)	—			(753		)
(Income) from unconsolidated investments in power plants		(6		)	(5		)	(18		)	(18		)
Income from operations		466			1,126			833			1,599
Interest expense		159			156			471			491
Interest (income)		(1		)	(2		)	(3		)	(5		)
Debt modification and extinguishment costs		—			340			32			341
Other (income) expense, net		1			4			8			20
Income before income taxes		307			628			325			752
Income tax expense		28			9			32			5
Net income		279			619			293			747
Net income attributable to the noncontrolling interest		(6		)	(5		)	(11		)	(11		)
Net income attributable to Calpine		$	273		$	614		$	282		$	736

Basic earnings per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands)		355,443			398,232			365,053			411,534
Net income per common share attributable to Calpine — basic		$	0.77		$	1.54		$	0.77		$	1.79

Diluted earnings per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands)		357,676			402,962			368,219			416,056
Net income per common share attributable to Calpine — diluted		$	0.76		$	1.52		$	0.77		$	1.77

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

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



		Three Months Ended September 30,						Nine Months Ended September 30,
		2015			2014			2015			2014
	(in millions)
Net income		$	279		$	619		$	293		$	747
Cash flow hedging activities:
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income		(16		)	3			(32		)	(32		)
Reclassification adjustment for loss on cash flow hedges realized in net income		12			8			36			34
Foreign currency translation loss		(11		)	(7		)	(19		)	(7		)
Income tax expense		—			—			—			—
Other comprehensive income (loss)		(15		)	4			(15		)	(5		)
Comprehensive income		264			623			278			742
Comprehensive (income) attributable to the noncontrolling interest		(5		)	(5		)	(11		)	(10		)
Comprehensive income attributable to Calpine		$	259		$	618		$	267		$	732

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

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited)



	September 30,			December 31,
	2015			2014
	(in millions, except share and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents ($76 and $229 attributable to VIEs)	$	659		$	717
Accounts receivable, net of allowance of $2 and $4	581			648
Inventories	470			447
Margin deposits and other prepaid expense	204			148
Restricted cash, current ($158 and $106 attributable to VIEs)	246			195
Derivative assets, current	1,429			2,058
Other current assets	9			7
Total current assets	3,598			4,220
Property, plant and equipment, net ($4,090 and $4,342 attributable to VIEs)	12,984			13,190
Restricted cash, net of current portion ($28 and $48 attributable to VIEs)	29			49
Investments in power plants	77			95
Long-term derivative assets	718			439
Long-term assets held for sale	130			—
Other assets ($161 and $164 attributable to VIEs)	362			385
Total assets	$	17,898		$	18,378
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	446		$	580
Accrued interest payable	137			165
Debt, current portion ($149 and $150 attributable to VIEs)	199			199
Derivative liabilities, current	1,334			1,782
Other current liabilities	307			473
Total current liabilities	2,423			3,199
Debt, net of current portion ($3,147 and $3,242 attributable to VIEs)	11,465			11,083
Long-term derivative liabilities	501			444
Other long-term liabilities	298			221
Total liabilities	14,687			14,947

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, 504,629,876 and 502,287,022 shares issued, respectively, and 357,831,952 and 381,921,264 shares outstanding, respectively	1			1
Treasury stock, at cost, 146,797,924 and 120,365,758 shares, respectively	(2,867		)	(2,345		)
Additional paid-in capital	12,470			12,440
Accumulated deficit	(6,258		)	(6,540		)
Accumulated other comprehensive loss	(193		)	(178		)
Total Calpine stockholders’ equity	3,153			3,378
Noncontrolling interest	58			53
Total stockholders’ equity	3,211			3,431
Total liabilities and stockholders’ equity	$	17,898		$	18,378

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

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended September 30,
	2015			2014
	(in millions)
Cash flows from operating activities:
Net income	$	293		$	747
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense⁽¹⁾	519			486
Debt extinguishment costs	—			35
Deferred income taxes	12			(9		)
Impairment losses	—			123
(Gain) on sale of assets, net	—			(753		)
Mark-to-market activity, net	4			(88		)
(Income) from unconsolidated investments in power plants	(18		)	(18		)
Return on unconsolidated investments in power plants	23			13
Stock-based compensation expense	19			30
Change in operating assets and liabilities:
Accounts receivable	42			(120		)
Derivative instruments, net	(44		)	(69		)
Other assets	(199		)	54
Accounts payable and accrued expenses	(211		)	127
Other liabilities	108			(54		)
Net cash provided by operating activities	548			504
Cash flows from investing activities:
Purchases of property, plant and equipment	(411		)	(354		)
Proceeds from sale of power plants, interests and other	—			1,573
Purchase of Guadalupe Energy Center	—			(656		)
Increase in restricted cash	(31		)	(15		)
Other	(8		)	2
Net cash provided by (used in) investing activities	(450		)	550
Cash flows from financing activities:
Borrowings under CCFC Term Loans and First Lien Term Loans	1,592			420
Repayment of CCFC Term Loans and First Lien Term Loans	(1,622		)	(34		)
Borrowings under Senior Unsecured Notes	650			2,800
Repurchase of First Lien Notes	(147		)	(2,800		)
Borrowings from project financing, notes payable and other	—			79
Repayments of project financing, notes payable and other	(102		)	(116		)
Distribution to noncontrolling interest holder	(6		)	(12		)
Financing costs	(17		)	(55		)
Stock repurchases	(510		)	(767		)
Proceeds from exercises of stock options	6			19
Net cash used in financing activities	(156		)	(466		)
Net increase (decrease) in cash and cash equivalents	(58		)	588
Cash and cash equivalents, beginning of period	717			941
Cash and cash equivalents, end of period	$	659		$	1,529

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)



	Nine Months Ended September 30,
	2015			2014
	(in millions)
Cash paid during the period for:
Interest, net of amounts capitalized	$	465		$	534
Income taxes	$	19		$	19

Supplemental disclosure of non-cash investing and financing activities:
Change in capital expenditures included in accounts payable	$	(17	)	$	8
Additions to property, plant and equipment through capital lease	$	9		$	—

____________


(1)	Includes depreciation and amortization included in fuel and purchased energy 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

September 30, 2015

(Unaudited)


1.	Basis of Presentation and Summary of Significant Accounting Policies

We are a wholesale 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 region (included in our East segment) of the U.S. We sell wholesale 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, power marketers and others. 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 and other physical and financial 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, 2014, included in our 2014 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 certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts, which 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. 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, major maintenance and debt repurchases or with applicable regulatory requirements. Funds that are expected to 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 September 30, 2015 and December 31, 2014 (in millions):



	September 30, 2015						December 31, 2014
	Current		Non-Current		Total		Current		Non-Current		Total
Debt service	$	39	$	7	$	46	$	10	$	25	$	35
Rent reserve	—		—		—		4		—		4
Construction/major maintenance	47		15		62		54		17		71
Security/project/insurance	159		5		164		127		5		132
Other	1		2		3		—		2		2
Total	$	246	$	29	$	275	$	195	$	49	$	244

Property, Plant and Equipment, Net — At September 30, 2015 and December 31, 2014, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):



	September 30, 2015		December 31, 2014		Depreciable Lives
Buildings, machinery and equipment	$	16,204	$	16,059	3 – 47 Years
Geothermal properties	1,315		1,294		13 – 58 Years
Other	209		203		3 – 47 Years
	17,728		17,556
Less: Accumulated depreciation	5,245		4,984
	12,483		12,572
Land	120		120
Construction in progress	381		498
Property, plant and equipment, net	$	12,984	$	13,190

Capitalized Interest — The total amount of interest capitalized was $3 million during each of the three months ended September 30, 2015 and 2014, and $12 million and $15 million for the nine months ended September 30, 2015 and 2014, respectively.

Treasury Stock — During the nine months ended September 30, 2015, we repurchased a total of 25.4 million shares of our outstanding common stock for approximately $510 million at an average price of $20.04 per share. Additionally, we withheld shares with a value of $12 million to satisfy tax withholding obligations associated with the vesting of restricted stock awarded to employees and with net share employee stock option exercises under the Equity Plan.

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 was originally to be effective for fiscal periods beginning after December 15, 2016, including interim periods within that reporting period and allowed 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. We are currently assessing the future impact this 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 do not anticipate a material impact on our financial condition, results of operations or cash flows as a result of adopting this standard.

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 do not anticipate a material impact on our financial condition, results of operations or cash flows as a result of adopting these standards.

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 do not anticipate a material impact on our financial condition, results of operations or cash flows as a result of adopting this standard.

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.


2.	Acquisitions and Divestiture

Acquisition of Granite Ridge Energy Center

On October 12, 2015, we, through our indirect, wholly-owned subsidiary Calpine Granite Holdings, LLC, entered into a purchase and sale agreement to acquire Granite Ridge Energy Center, a power plant with a nameplate capacity of 745 MW, from Granite Ridge Holdings, LLC, for approximately $500 million, excluding working capital adjustments. The addition of this modern, efficient, natural gas-fired, combined-cycle power plant will increase 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 expect the transaction to close in the first quarter of 2016, and expect to fund the acquisition with a combination of cash on hand and financing.

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. Champion Energy, a leading retail electric provider, is expected to serve approximately 22 million MWh of commercial, industrial and residential customer load in 2015, concentrated in Texas, PJM and the Northeast U.S. where Calpine has a substantial power generation presence. The addition of this well-established retail sales organization is expected to provide us an important outlet for directly reaching a much greater portion of the load we serve. The purchase price was funded with cash on hand and will be primarily allocated to intangible assets, working capital accounts and derivative assets and liabilities. Any excess of the purchase price over the fair values of Champion Energy’s assets and liabilities will be recorded as goodwill; however, we do not anticipate any significant goodwill will be recognized as a result of this acquisition. We are currently evaluating the fair value of the assets acquired and liabilities assumed and will provide these disclosures in our annual report on Form 10-K for the year ended December 31, 2015. The pro forma incremental impact of Champion Energy on our results of operations for each of the three and nine months ended September 30, 2015 and 2014 is not material.

Acquisition of Fore River Energy Center

On November 7, 2014, we, through our indirect, wholly-owned subsidiary Calpine Fore River Energy Center, LLC, completed the purchase of our 731 MW Fore River Energy Center and related plant inventory from a subsidiary of Exelon Corporation, for approximately $530 million, excluding working capital adjustments. The purchase price allocation was finalized during the third quarter of 2015 which did not result in any material adjustments or the recognition of goodwill.

Sale of Osprey Energy Center

During the fourth quarter of 2014, we executed an asset sale agreement for the sale of our Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million, excluding working capital and other adjustments. In accordance with the asset sale agreement, the sale will be consummated in January 2017 upon the conclusion of PPA with a term of 27 months. In July 2015, the transaction was approved by the FERC and the Florida Public Service Commission. This sale represents a strategic disposition of a power plant in a wholesale power market dominated by regulated utilities. The assets of Osprey Energy Center, which is in our East segment, are reported as long-term assets held for sale on our Consolidated Condensed Balance Sheet at September 30, 2015 and comprise 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 nine months ended September 30, 2015. See Note 5 in our 2014 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 and 10,365 MW at September 30, 2015 and December 31, 2014, respectively. For these VIEs, we may provide other operational and administrative support through various affiliate contractual arrangements among the VIEs, Calpine Corporation and its other wholly-owned subsidiaries whereby we support the VIE through the reimbursement of costs and/or the purchase and sale of energy. Other than amounts contractually required, we provided support to these VIEs in the form of cash and other contributions of $2 million during each of the three and nine months ended September 30, 2015 and $7 million and $47 million during the three and nine months ended September 30, 2014, respectively.

Unconsolidated VIEs and Investments in Power Plants

We have a 50% partnership interest in Greenfield LP and in Whitby. Greenfield LP and Whitby are also 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 September 30, 2015 and December 31, 2014, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):



	Ownership Interest as of September 30, 2015	September 30, 2015		December 31, 2014
Greenfield LP	50%	$	66	$	78
Whitby	50%	11		17
Total investments in power plants		$	77	$	95

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; therefore, the debt of our unconsolidated investments is not reflected on our Consolidated Condensed Balance Sheets. At September 30, 2015 and December 31, 2014, equity method investee debt was approximately $283 million and $342 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 $171 million at September 30, 2015 and December 31, 2014, respectively.

Our equity interest in the net income from Greenfield LP and Whitby for the three and nine months ended September 30, 2015 and 2014, is recorded in (income) from unconsolidated investments in power plants on our Consolidated Condensed Statements of Operations. The following table sets forth details of our (income) from unconsolidated investments in power plants for the periods indicated (in millions):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Greenfield LP	$	(3	)	$	(2	)	$	(9	)	$	(7	)
Whitby	(3		)	(3		)	(9		)	(11		)
Total	$	(6	)	$	(5	)	$	(18	)	$	(18	)

Distributions from Greenfield LP were $10 million during each of the three and nine months ended September 30, 2015, and nil during each of the three and nine months ended September 30, 2014. Distributions from Whitby were nil and $13 million during both the three and nine months ended September 30, 2015 and 2014, respectively.

Inland Empire Energy Center Put and Call Options — We hold a call option to purchase the Inland Empire Energy Center (a 775 MW natural gas-fired power plant located in California) from GE that may be exercised between years 2017 and 2024. GE holds a put option whereby they can require us to purchase the power plant, if certain plant performance criteria are met by 2025. We determined that we are not the primary beneficiary of the Inland Empire power plant, and we do not consolidate it due to the fact that GE directs the most significant activities of the power plant including operations and maintenance.


4.	Debt

Our debt at September 30, 2015 and December 31, 2014, was as follows (in millions):



	September 30, 2015		December 31, 2014
Senior Unsecured Notes	$	3,450	$	2,800
First Lien Term Loans	2,780		2,799
First Lien Notes	1,928		2,075
Project financing, notes payable and other	1,720		1,810
CCFC Term Loans	1,585		1,596
Capital lease obligations	201		202
Subtotal	11,664		11,282
Less: Current maturities	199		199
Total long-term debt	$	11,465	$	11,083

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 5.4% for the nine months ended September 30, 2015, from 6.0% for the same period in 2014. The issuance of our Senior Unsecured Notes in July 2014 and 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):



	September 30, 2015		December 31, 2014
2023 Senior Unsecured Notes	$	1,250	$	1,250
2024 Senior Unsecured Notes	650		—
2025 Senior Unsecured Notes	1,550		1,550
Total Senior Unsecured Notes	$	3,450	$	2,800

In February 2015, we issued $650 million in aggregate principal amount of 5.5% senior unsecured notes due 2024 in a public offering. The 2024 Senior Unsecured Notes bear interest at 5.5% per annum with interest payable semi-annually on February 1 and August 1 of each year, beginning on August 1, 2015. The 2024 Senior Unsecured Notes were issued at par, mature on

February 1, 2024 and contain substantially similar covenants, qualifications, exceptions and limitations as our 2023 Senior Unsecured Notes and 2025 Senior Unsecured Notes. We used the net proceeds received from the issuance of our 2024 Senior Unsecured Notes to replenish cash on hand used for the acquisition of Fore River Energy Center in the fourth quarter of 2014, to repurchase approximately $147 million of our 2023 First Lien Notes and for general corporate purposes. During the first quarter of 2015, we recorded approximately $9 million in deferred financing costs related to the issuance of our 2024 Senior Unsecured Notes and approximately $19 million in debt extinguishment costs related to the partial repurchase of our 2023 First Lien Notes.

First Lien Term Loans

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



	September 30, 2015		December 31, 2014
2018 First Lien Term Loans	$	—	$	1,597
2019 First Lien Term Loan	810		816
2020 First Lien Term Loan	383		386
2022 First Lien Term Loan	1,587		—
Total First Lien Term Loans	$	2,780	$	2,799

On May 28, 2015, we entered into our $1.6 billion 2022 First Lien Term Loan. We used the net proceeds received, together with operating cash on hand, to repay the 2018 First Lien Term Loans. The 2022 First Lien Term Loan matures on May 27, 2022 and bears interest, at our option, at either (i) the base rate, equal to the highest of (a) the Federal Funds effective rate plus 0.50% per annum, (b) the Prime Rate or (c) the Eurodollar rate for a one-month interest period plus 1.0% (in each case, as such terms are defined in the 2022 First Lien Term Loan credit agreement), plus an applicable margin of 1.75%, or (ii) LIBOR plus 2.75% per annum subject to a LIBOR floor of 0.75%. An aggregate amount equal to 0.25% of the aggregate principal amount of the 2022 First Lien Term Loan will be payable at the end of each quarter commencing in September 2015. The 2022 First Lien Term Loan contains substantially similar covenants, qualifications, exceptions and limitations as the First Lien Term Loans and First Lien Notes.

We accounted for this transaction as a debt modification rather than an extinguishment of debt and, accordingly, did not record any debt extinguishment costs associated with the repayment of our 2018 First Lien Term Loans. However, in accordance with the accounting guidance for debt modification and extinguishment, we recorded approximately $13 million in debt modification costs associated with issuance costs and approximately $6 million in deferred financing costs related to the 2022 First Lien Term Loan during the second quarter of 2015.

First Lien Notes

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



	September 30, 2015		December 31, 2014
2022 First Lien Notes	$	745	$	745
2023 First Lien Notes⁽¹⁾	693		840
2024 First Lien Notes	490		490
Total First Lien Notes	$	1,928	$	2,075

____________


(1)	On February 3, 2015, we repurchased approximately $147 million of our 2023 First Lien Notes with the proceeds from our 2024 Senior Unsecured Notes, as described in further detail above.

Corporate Revolving Facility and Other Letters of Credit Facilities

The table below represents amounts issued under our letter of credit facilities at September 30, 2015 and December 31, 2014 (in millions):



	September 30, 2015		December 31, 2014
Corporate Revolving Facility⁽¹⁾	$	170	$	223
CDHI	238		214
Various project financing facilities	239		207
Total	$	647	$	644

____________


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

Fair Value of Debt

We record our debt instruments based on contractual terms, net of any applicable premium or discount. The following table details the fair values and carrying values of our debt instruments at September 30, 2015 and December 31, 2014 (in millions):



	September 30, 2015				December 31, 2014
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Unsecured Notes	$	3,188	$	3,450	$	2,832	$	2,800
First Lien Term Loans	2,755		2,780		2,769		2,799
First Lien Notes	2,023		1,928		2,247		2,075
Project financing, notes payable and other⁽¹⁾	1,643		1,613		1,734		1,688
CCFC Term Loans	1,548		1,585		1,540		1,596
Total	$	11,157	$	11,356	$	11,122	$	10,958

____________


(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 are observable. Generally, we obtain our level 2 pricing inputs from market sources such as the Intercontinental Exchange and Bloomberg. To the extent we obtain prices from brokers in the marketplace, we have procedures in place to ensure that prices represent executable prices for market participants. 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 September 30, 2015 and December 31, 2014, by level within the fair value hierarchy:



	Assets and Liabilities with Recurring Fair Value Measures as of September 30, 2015
	Level 1		Level 2		Level 3		Total
	(in millions)
Assets:
Cash equivalents⁽¹⁾	$	874	$	—	$	—	$	874
Margin deposits	167		—		—		167
Commodity instruments:
Commodity exchange traded futures and swaps contracts	1,584		—		—		1,584
Commodity forward contracts⁽²⁾	—		256		305		561
Interest rate swaps	—		2		—		2
Total assets	$	2,625	$	258	$	305	$	3,188
Liabilities:
Margin deposits posted with us by our counterparties	$	15	$	—	$	—	$	15
Commodity instruments:
Commodity exchange traded futures and swaps contracts	1,477		—		—		1,477
Commodity forward contracts⁽²⁾	—		235		13		248
Interest rate swaps	—		110		—		110
Total liabilities	$	1,492	$	345	$	13	$	1,850



	Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2014
	Level 1		Level 2		Level 3		Total
	(in millions)
Assets:
Cash equivalents⁽¹⁾	$	896	$	—	$	—	$	896
Margin deposits	96		—		—		96
Commodity instruments:
Commodity exchange traded futures and swaps contracts	2,134		—		—		2,134
Commodity forward contracts⁽²⁾	—		195		164		359
Interest rate swaps	—		4		—		4
Total assets	$	3,126	$	199	$	164	$	3,489
Liabilities:
Margin deposits posted with us by our counterparties	$	47	$	—	$	—	$	47
Commodity instruments:
Commodity exchange traded futures and swaps contracts	1,870		—		—		1,870
Commodity forward contracts⁽²⁾	—		163		79		242
Interest rate swaps	—		114		—		114
Total liabilities	$	1,917	$	277	$	79	$	2,273

___________


(1)	As of September 30, 2015 and December 31, 2014, we had cash equivalents of $624 million and $679 million included in cash and cash equivalents and $250 million and $217 million included in restricted cash, respectively.


(2)	Includes OTC swaps and options.

At September 30, 2015 and December 31, 2014, 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 September 30, 2015 and December 31, 2014:



	Quantitative Information about Level 3 Fair Value Measurements
	September 30, 2015
	Fair Value, Net Asset			Significant Unobservable
	(Liability)		Valuation Technique	Input	Range
	(in millions)
Power Contracts	$	285	Discounted cash flow	Market price (per MWh)	$11.86 — $90.80/MWh
Power Congestion Products	$	8	Discounted cash flow	Market price (per MWh)	$(11.47) — $5.95/MWh

	December 31, 2014
	Fair Value, Net Asset			Significant Unobservable
	(Liability)		Valuation Technique	Input	Range
	(in millions)
Power Contracts	$	74	Discounted cash flow	Market price (per MWh)	$14.00 — $122.79/MWh
Natural Gas Contracts	$	5	Discounted cash flow	Market price (per MMBtu)	$1.00 — $10.86/MMBtu
Power Congestion Products	$	9	Discounted cash flow	Market price (per MWh)	$(19.56) — $19.56/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 September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Balance, beginning of period	$	243		$	(9	)	$	85		$	14
Realized and mark-to-market gains (losses):
Included in net income:
Included in operating revenues⁽¹⁾	70			7			236			(1		)
Included in fuel and purchased energy expense⁽²⁾	(2		)	5			(2		)	9
Purchases and settlements:
Purchases	—			—			3			1
Settlements	(8		)	9			(24		)	(7		)
Transfers in and/or out of level 3⁽³⁾:
Transfers into level 3⁽⁴⁾	—			—			—			—
Transfers out of level 3⁽⁵⁾	(11		)	(1		)	(6		)	(5		)
Balance, end of period	$	292		$	11		$	292		$	11
Change in unrealized gains relating to instruments still held at end of period	$	68		$	12		$	234		$	8

___________


(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 and nine months ended September 30, 2015 and 2014.


(4)	There were no transfers out of level 2 into level 3 for each of the three and nine months ended September 30, 2015 and 2014.


(5)	We had $11 million and $1 million in gains transferred out of level 3 into level 2 for the three months ended September 30, 2015 and 2014, respectively, and $6 million and $5 million in gains transferred out of level 3 into level 2 for the nine months ended September 30, 2015 and 2014, 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, 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 and nine months ended September 30, 2015 and 2014.

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 September 30, 2015, 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 September 30, 2015 and December 31, 2014, 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	September 30, 2015			December 31, 2014
Power (MWh)	(111		)	(62		)
Natural gas (MMBtu)	984			291
Environmental credits (Tonnes)	5			—
Interest rate swaps	$	1,405		$	1,431

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 September 30, 2015, was $12 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 $8 million would be required and that no counterparty could request immediate, full settlement.

Accounting for Derivative Instruments

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

hedged) within operating activities or investing 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 and environmental product 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 contracts, environmental product 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 September 30, 2015 and December 31, 2014 (in millions):



	September 30, 2015
	Commodity Instruments		Interest Rate Swaps			Total Derivative Instruments
Balance Sheet Presentation
Current derivative assets	$	1,429	$	—		$	1,429
Long-term derivative assets	716		2			718
Total derivative assets	$	2,145	$	2		$	2,147

Current derivative liabilities	$	1,293	$	41		$	1,334
Long-term derivative liabilities	432		69			501
Total derivative liabilities	$	1,725	$	110		$	1,835
Net derivative assets (liabilities)	$	420	$	(108	)	$	312



	December 31, 2014
	Commodity Instruments		Interest Rate Swaps			Total Derivative Instruments
Balance Sheet Presentation
Current derivative assets	$	2,058	$	—		$	2,058
Long-term derivative assets	435		4			439
Total derivative assets	$	2,493	$	4		$	2,497

Current derivative liabilities	$	1,738	$	44		$	1,782
Long-term derivative liabilities	374		70			444
Total derivative liabilities	$	2,112	$	114		$	2,226
Net derivative assets (liabilities)	$	381	$	(110	)	$	271



	September 30, 2015					December 31, 2014
	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	$	2	$	111		$	4	$	112
Total derivatives designated as cash flow hedging instruments	$	2	$	111		$	4	$	112

Derivatives not designated as hedging instruments:
Commodity instruments	$	2,145	$	1,725		$	2,493	$	2,112
Interest rate swaps	—		(1		)	—		2
Total derivatives not designated as hedging instruments	$	2,145	$	1,724		$	2,493	$	2,114
Total derivatives	$	2,147	$	1,835		$	2,497	$	2,226

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 September 30, 2015 and December 31, 2014 (in millions):



	September 30, 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	$	1,584		$	(1,473	)	$	(111	)	$	—
Commodity forward contracts	561			(231		)	(2		)	328
Interest rate swaps	2			—			—			2
Total derivative assets	$	2,147		$	(1,704	)	$	(113	)	$	330
Derivative (liabilities):
Commodity exchange traded futures and swaps contracts	$	(1,477	)	$	1,473		$	4		$	—
Commodity forward contracts	(248		)	231			9			(8		)
Interest rate swaps	(110		)	—			—			(110		)
Total derivative (liabilities)	$	(1,835	)	$	1,704		$	13		$	(118	)
Net derivative assets (liabilities)	$	312		$	—		$	(100	)	$	212



	December 31, 2014
	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	$	2,134		$	(1,865	)	$	(269	)	$	—
Commodity forward contracts	359			(222		)	—			137
Interest rate swaps	4			—			—			4
Total derivative assets	$	2,497		$	(2,087	)	$	(269	)	$	141
Derivative (liabilities):
Commodity exchange traded futures and swaps contracts	$	(1,870	)	$	1,865		$	5		$	—
Commodity forward contracts	(242		)	222			10			(10		)
Interest rate swaps	(114		)	—			—			(114		)
Total derivative (liabilities)	$	(2,226	)	$	2,087		$	15		$	(124	)
Net derivative assets (liabilities)	$	271		$	—		$	(254	)	$	17

____________

(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 September 30,					Nine Months Ended September 30,
	2015			2014		2015			2014
Realized gain (loss)⁽¹⁾
Commodity derivative instruments	$	160		$	59	$	323		$	38
Total realized gain (loss)	$	160		$	59	$	323		$	38

Mark-to-market gain (loss)⁽²⁾
Commodity derivative instruments	$	(75	)	$	11	$	(6	)	$	79
Interest rate swaps	1			7		2			9
Total mark-to-market gain (loss)	$	(74	)	$	18	$	(4	)	$	88
Total activity, net	$	86		$	77	$	319		$	126

___________


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


(2)	In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.



	Three Months Ended September 30,					Nine Months Ended September 30,
	2015			2014		2015			2014
Realized and mark-to-market gain (loss)
Derivatives contracts included in operating revenues	$	189		$	53	$	423		$	(26	)
Derivatives contracts included in fuel and purchased energy expense	(104		)	17		(106		)	143
Interest rate swaps included in interest expense	1			7		2			9
Total activity, net	$	86		$	77	$	319		$	126

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 September 30,					Three Months Ended September 30,
	Gain (Loss) Recognized in OCI (Effective Portion)					Gain (Loss) Reclassified from AOCI into Income (Effective Portion)⁽³⁾⁽⁴⁾
	2015			2014		2015			2014			Affected Line Item on the Consolidated Condensed Statements of Operations
Interest rate swaps⁽¹⁾⁽²⁾	$	(4	)	$	11	$	(12	)	$	(8	)	Interest expense



	Nine Months Ended September 30,				Nine Months Ended September 30,
	Gain (Loss) Recognized in OCI (Effective Portion)				Gain (Loss) Reclassified from AOCI into Income (Effective Portion)⁽³⁾⁽⁴⁾
	2015		2014		2015			2014			Affected Line Item on the Consolidated Condensed Statements of Operations
Interest rate swaps⁽¹⁾⁽²⁾	$	4	$	2	$	(36	)	$	(34	)	Interest expense

____________


(1)	We did not record any gain (loss) on hedge ineffectiveness related to our interest rate swaps designated as cash flow hedges during the three and nine months ended September 30, 2015 and 2014.


(2)	We recorded an income tax expense of nil for each of the three and nine months ended September 30, 2015 and 2014, 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 $145 million and $149 million at September 30, 2015 and December 31, 2014, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $12 million and $12 million at September 30, 2015 and December 31, 2014, respectively.


(4)	Includes a loss of nil and $10 million for the three and nine months ended September 30, 2014, respectively, that was reclassified from AOCI to interest expense, where the hedged transactions are no longer expected to occur.

We estimate that pre-tax net losses of $45 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 September 30, 2015 and December 31, 2014 (in millions):



	September 30, 2015		December 31, 2014
Margin deposits⁽¹⁾	$	167	$	96
Natural gas and power prepayments	23		22
Total margin deposits and natural gas and power prepayments with our counterparties⁽²⁾	$	190	$	118

Letters of credit issued	$	460	$	450
First priority liens under power and natural gas agreements	28		48
First priority liens under interest rate swap agreements	112		116
Total letters of credit and first priority liens with our counterparties	$	600	$	614

Margin deposits posted with us by our counterparties⁽¹⁾⁽³⁾	$	15	$	47
Letters of credit posted with us by our counterparties	125		61
Total margin deposits and letters of credit posted with us by our counterparties	$	140	$	108

___________

(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 September 30, 2015 and December 31, 2014, $176 million and $109 million, respectively, were included in margin deposits and other prepaid expense and $14 million and $9 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets.


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

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


8.	Income Taxes

Income Tax Expense

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Income tax expense	$	28		$	9		$	32		$	5
Effective tax rate	9		%	1		%	10		%	1		%

Our income tax rates do not bear a customary relationship to statutory income tax rates primarily as a result of the impact of our NOLs, changes in unrecognized tax benefits and valuation allowances. For the three and nine months ended September 30, 2015 and 2014, our income tax expense 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 2014 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 earnings history, we are unable to assume future profits; however, we are able to consider available tax planning strategies.

Unrecognized Tax Benefits — At September 30, 2015, we had unrecognized tax benefits of $53 million. If recognized, $12 million of our unrecognized tax benefits could impact the annual effective tax rate and $41 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 $11 million for income tax matters at September 30, 2015. We recognize interest and penalties related to unrecognized tax benefits in income tax expense on our Consolidated Condensed Statements of Operations.


9.	Earnings 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. Reconciliations of the amounts used in the basic and diluted earnings per common share computations for the three and nine months ended September 30, 2015 and 2014, are as follows (shares in thousands):



	Three Months Ended September 30,		Nine Months Ended September 30,
	2015	2014	2015	2014
Diluted weighted average shares calculation:
Weighted average shares outstanding (basic)	355,443	398,232	365,053	411,534
Share-based awards	2,233	4,730	3,166	4,522
Weighted average shares outstanding (diluted)	357,676	402,962	368,219	416,056

We excluded the following items from diluted earnings per common share for the three and nine months ended September 30, 2015 and 2014, because they were anti-dilutive (shares in thousands):



	Three Months Ended September 30,		Nine Months Ended September 30,
	2015	2014	2015	2014
Share-based awards	4,982	2,854	4,208	2,855


10.	Stock-Based Compensation

Equity Classified Share-Based Awards

Stock-based compensation expense recognized for our equity classified share-based awards was $8 million for each of the three months ended September 30, 2015 and 2014, and $24 million and $25 million for the nine months ended September 30, 2015 and 2014, 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 nine months ended September 30, 2015 and 2014. At September 30, 2015, there was unrecognized compensation cost of $31 million related to restricted stock which is expected to be recognized over a weighted average period of 1.2 years.

A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the nine months ended September 30, 2015, is as follows:



	Number of Restricted Stock Awards	Weighted Average Grant-Date Fair Value
Nonvested — December 31, 2014	4,201,868	$	18.01
Granted	1,577,932	$	21.40
Forfeited	240,259	$	19.64
Vested	1,589,073	$	16.54
Nonvested — September 30, 2015	3,950,468	$	19.85

The total fair value of our restricted stock and restricted stock units that vested during the nine months ended September 30, 2015 and 2014 was approximately $34 million and $31 million, respectively.

Liability Classified Share-Based Awards

Performance share units granted under the Equity Plan are settled in cash with payouts based on the relative performance of Calpine’s TSR over a three-year performance period compared with the TSR performance of the S&P 500 companies over the same period. The performance share units vest on the last day of the performance period and will be settled in cash; thus, these awards are classified as a liability and 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 $(1) million and nil for the three months ended September 30, 2015 and 2014, respectively, and $(5) million and $5 million for the nine months ended September 30, 2015 and 2014, respectively.

A summary of our performance share unit activity for the nine months ended September 30, 2015, is as follows:



	Number of Performance Share Units	Weighted Average Grant-Date Fair Value
Nonvested — December 31, 2014	867,479	$	21.93
Granted	365,667	$	23.91
Forfeited	89,117	$	22.33
Vested⁽¹⁾	8,254	$	22.56
Nonvested — September 30, 2015	1,135,775	$	22.53

___________


(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 2014 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 September 30, 2015, our reportable segments were West (including geothermal), Texas and East (including Canada). We continue to evaluate the manner in which we assess our performance, including our segments, which may result in future 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 September 30, 2015
	West		Texas			East			Consolidation and Elimination			Total
Revenues from external customers	$	736	$	709		$	503		$	—		$	1,948
Intersegment revenues	1		4			3			(8		)	—
Total operating revenues	$	737	$	713		$	506		$	(8	)	$	1,948
Commodity Margin	$	385	$	264		$	325		$	—		$	974
Add: Mark-to-market commodity activity, net and other⁽¹⁾	68		(98		)	(62		)	(7		)	(99		)
Less:
Plant operating expense	87		62			57			(6		)	200
Depreciation and amortization expense	61		58			48			(1		)	166
Sales, general and other administrative expense	7		15			10			1			33
Other operating expenses	8		2			8			(2		)	16
(Income) from unconsolidated investments in power plants	—		—			(6		)	—			(6		)
Income from operations	290		29			146			1			466
Interest expense, net of interest income												158
Other (income) expense, net												1
Income before income taxes												$	307



	Three Months Ended September 30, 2014
	West		Texas			East			Consolidation and Elimination			Total
Revenues from external customers	$	714	$	985		$	488		$	—		$	2,187
Intersegment revenues	1		4			2			(7		)	—
Total operating revenues	$	715	$	989		$	490		$	(7	)	$	2,187
Commodity Margin⁽²⁾	$	361	$	346		$	237		$	—		$	944
Add: Mark-to-market commodity activity, net and other⁽¹⁾	41		(64		)	4			(6		)	(25		)
Less:
Plant operating expense	91		77			55			(8		)	215
Depreciation and amortization expense	65		51			38			(1		)	153
Sales, general and other administrative expense	11		18			8			—			37
Other operating expenses	12		1			6			4			23
Impairment losses	—		—			123			—			123
(Gain) on sale of assets, net	—		—			(753		)	—			(753		)
(Income) from unconsolidated investments in power plants	—		—			(5		)	—			(5		)
Income from operations	223		135			769			(1		)	1,126
Interest expense, net of interest income												154
Debt extinguishment costs and other (income) expense, net												344
Income before income taxes												$	628



	Nine Months Ended September 30, 2015
	West		Texas			East			Consolidation and Elimination			Total
Revenues from external customers	$	1,672	$	1,860		$	1,504		$	—		$	5,036
Intersegment revenues	3		12			7			(22		)	—
Total operating revenues	$	1,675	$	1,872		$	1,511		$	(22	)	$	5,036
Commodity Margin	$	843	$	583		$	740		$	—		$	2,166
Add: Mark-to-market commodity activity, net and other⁽³⁾	173		(47		)	(84		)	(21		)	21
Less:
Plant operating expense	313		233			206			(20		)	732
Depreciation and amortization expense	193		157			135			(1		)	484
Sales, general and other administrative expense	23		47			29			1			100
Other operating expenses	28		6			24			(2		)	56
(Income) from unconsolidated investments in power plants	—		—			(18		)	—			(18		)
Income from operations	459		93			280			1			833
Interest expense, net of interest income												468
Debt modification and extinguishment costs and other (income) expense, net												40
Income before income taxes												$	325



	Nine Months Ended September 30, 2014
	West		Texas		East			Consolidation and Elimination			Total
Revenues from external customers	$	1,692	$	2,592	$	1,807		$	—		$	6,091
Intersegment revenues	4		19		46			(69		)	—
Total operating revenues	$	1,696	$	2,611	$	1,853		$	(69	)	$	6,091
Commodity Margin⁽²⁾	$	791	$	644	$	786		$	—		$	2,221
Add: Mark-to-market commodity activity, net and other⁽³⁾	91		74		(31		)	(23		)	111
Less:
Plant operating expense	291		250		237			(24		)	754
Depreciation and amortization expense	183		141		129			—			453
Sales, general and other administrative expense	28		48		32			—			108
Other operating expenses	39		4		22			1			66
Impairment losses	—		—		123			—			123
(Gain) on sale of assets, net	—		—		(753		)	—			(753		)
(Income) from unconsolidated investments in power plants	—		—		(18		)	—			(18		)
Income from operations	341		275		983			—			1,599
Interest expense, net of interest income											486
Debt extinguishment costs and other (income) expense, net											361
Income before income taxes											$	752

_________


(1)	Includes $41 million and $49 million of lease levelization and $4 million and $4 million of amortization expense for the three months ended September 30, 2015 and 2014, respectively.


(2)	Commodity Margin related to the six power plants sold in our East segment on July 3, 2014, was not significant for the three months ended September 30, 2014. The Commodity Margin related to those power plants was $81 million for the nine months ended September 30, 2014.


(3)	Includes $(1) million and $(7) million of lease levelization and $11 million and $11 million of amortization expense for the nine months ended September 30, 2015 and 2014, 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 wholesale 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 region (included in our East segment) of the U.S. We sell wholesale 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, power marketers and others. As a result of our investment in cleaner power generation, we have become a recognized leader in developing, constructing, owning and operating an environmentally responsible portfolio of flexible and reliable power plants. Effective October 1, 2015, we also sell power to commercial, industrial and residential customers through our retail subsidiary, Champion Energy.

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 and other physical and financial 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. We currently consider the repurchases of our own shares of common stock as an attractive investment opportunity, and we utilize the expected returns from this investment as the benchmark against which we evaluate all other capital allocation decisions. We believe this philosophy closely aligns our objectives with those of our shareholders.

Our goal is to be recognized as the premier 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 2015:


•	We produced approximately 87 million MWh of electricity during the nine months ended September 30, 2015.


•	Our entire fleet achieved a forced outage factor of 1.7% and a starting reliability of 98.2% during the nine months ended September 30, 2015.


•	In 2015, through the filing of this Report, we repurchased a total of 26.6 million shares of our common stock for approximately $529 million at an average price of $19.87 per share.


•	In February 2015, we issued $650 million in aggregate principal amount of 5.5% senior unsecured notes due 2024. We used the net proceeds to replenish cash on hand used for the acquisition of Fore River Energy Center in the fourth quarter of 2014, to repurchase approximately $147 million of our 2023 First Lien Notes and for general corporate purposes.


•	In May 2015, we repaid our 2018 First Lien Term Loans with the proceeds from the 2022 First Lien Term Loan which extended the maturity and reduced the interest rate on approximately $1.6 billion of corporate debt.


•	In June 2015, our Garrison Energy Center commenced commercial operations, bringing online approximately 309 MW of combined-cycle, natural gas-fired capacity.


•	During the second quarter of 2015, we began construction of our 760 MW York 2 Energy Center and expect commercial operations to commence during the second quarter of 2017.


•	On October 1, 2015, we completed the acquisition of Champion Energy for approximately $240 million, excluding working capital adjustments. The addition of this well-established retail sales organization will provide us an important outlet for directly reaching a much greater portion of the load we serve.


•	On October 12, 2015, we entered into an agreement to purchase Granite Ridge Energy Center, a power plant with a nameplate capacity of 745 MW, for approximately $500 million, excluding working capital adjustments. The addition of this modern, efficient, natural gas-fired, combined-cycle power plant will increase capacity in our East segment, specifically the constrained New England market.


•	In October 2015, we issued notice to the holders of our 2023 First Lien Notes of our intent to redeem 10% of the original aggregate principal amount, plus accrued and unpaid interest. We intend to use cash on hand to fund the redemption.

•

We successfully originated several new contracts with customers in our West, Texas and East segments, including those related to our Delta and Pastoria Energy Centers, Geysers Assets, Mankato Power Plant and Texas power plant fleet. The execution of two of these PPAs with customers in Texas and the East will facilitate the construction of a 418 MW natural gas-fired peaking power plant to be co-located with our Guadalupe Energy Center and the 345 MW expansion of our Mankato Power Plant.

Our wholesale power plant portfolio, including partnership interests, consists of 83 power plants, including one under construction, located throughout 18 states in the U.S. and in Canada, with an aggregate current generation capacity of 26,587 MW and 760 MW under construction. Our fleet, including projects under construction, consists of 67 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 9,735 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 2014 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. 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. As follow up to the ORDC, ERCOT has implemented a stakeholder approved reliability deployment adder that reflects the value of ISO out of merit actions and corrects real time price reversals that result from out of merit actions such as shedding certain loads during emergency conditions. The adder became effective prior to the 2015 peak summer season. 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

PJM experienced several unusual cold weather events during January 2014. PJM maintained system reliability, but the system was challenged. In order to address some of these challenges, PJM filed proposed capacity market rule changes in December 2014 which include stronger performance incentives and more significant penalties for failure to perform during peak power system conditions. On June 9, 2015, the FERC approved PJM’s proposed changes with minor alterations, and on July 22, 2015, the FERC granted rehearing of its June 9, 2015 order in order to permit qualifying demand response and energy efficiency resources to participate in the transition auctions. As a result of the FERC’s orders, PJM conducted the 2018/2019 base residual auction in August 2015 and the transition auctions for the 2016/2017 and 2017/2018 delivery periods were conducted shortly thereafter. All of these auctions included the capacity performance measures approved by the FERC. We support PJM’s capacity market rule changes and believe that, overall, they enhance the competitiveness and reliability of the PJM power market.

Beginning several years ago, New Jersey and Maryland each directed their load serving entities (“LSEs”) 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. Each state directed its LSEs to purchase capacity from the winning generators at guaranteed prices for 15 to 20 years. Under the terms of the state-mandated contracts, the winning generators were required to bid their capacity into PJM’s annual capacity auction. Several generators and LSEs challenged the New Jersey and Maryland actions in federal court, arguing that the states’ actions impermissibly interfered with the FERC’s exclusive jurisdiction over wholesale capacity markets. The generators and LSEs 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. 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. Oral argument has not yet been scheduled.

ISO-NE

ISO-NE continues to express concern related to the adequacy of natural gas transmission infrastructure and has received FERC approval to continue its winter reliability program for the next three winter periods. Over the longer term, the FERC has approved significant changes to the operation of the region’s capacity market that became effective with the 2015 Forward Capacity Auction (“FCA”). The ISO’s new “Pay for Performance” capacity market will result in significantly higher penalties for assets that fail to perform during shortage events beginning with the 2018-2019 commitment period. The prospect of these performance requirements, combined with recent capacity retirements in the region, resulted in significantly higher 2015 FCA clearing prices than were seen in recent years. The FERC also approved a two-year extension of the “lock-in” period for new generation, allowing new generating assets that clear the FCA to lock in their cleared price for a total of seven years.

Three New England states, Massachusetts, Connecticut and Rhode Island, have regulations in place or are considering legislation that would allow their investor owned utilities to enter into long-term contracts for up to approximately 2,000 MW of Canadian hydro imports. We cannot predict at this time whether long-term contracts will ultimately be signed or the related transmission facilities will be approved by federal and state regulators. Thus, the impact these efforts may have on our business is currently unknown.

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

After extended litigation over several years, CSAPR became effective on January 1, 2015 as originally proposed, but with delayed compliance timelines. The U.S. Court of Appeals for the District of Columbia Circuit (“D.C. Circuit”) heard oral arguments regarding additional remaining legal issues on February 25, 2015. On July 28, 2015, the D.C. Circuit rejected several of the broader challenges to CSAPR, and also held that some portions of CSAPR were invalid, remanding those portions of the rule to the EPA and leaving the rules in place while the EPA crafts a remedy. The court did not set a timeline for the EPA to address the invalid provisions.

On April 15, 2014, the D.C. Circuit rejected all legal challenges to the EPA’s MATS regulation in White Stallion Energy Center, LLC, et al v. EPA., which included challenges by over 20 states, industry groups and companies. In response to further challenges by the petitioners, the U.S. Supreme Court granted petitions for certiorari in November 2014 and heard oral arguments on March 25, 2015. On June 29, 2015, the U.S. Supreme Court reversed the decision of the D.C. Circuit and remanded the case for further action.

At this time, the ultimate outcome of these two cases on remand cannot be determined. However, CSPAR took effect on January 1, 2015, and MATS took effect on April 15, 2015, and both rules remain in effect until further action by the D.C. Circuit. Many of the announced retirements and emissions control installations undertaken to comply with MATS have already occurred.

CSAPR and MATS primarily impact coal-fired power plants, and therefore judicial decisions related to these rules do not directly affect our business. 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.

GHG Emissions

In January 2014, the EPA proposed New Source Performance Standards (“NSPS”) for GHG emissions from new power plants. In June 2014, the EPA proposed the Clean Power Plan which requires a reduction in GHG emissions from existing power plants of 30% from 2005 levels by 2030. In June 2014, the EPA also proposed GHG NSPS provisions for modified and reconstructed sources.

On August 4, 2015, the EPA finalized the NSPS for GHG emissions from new power plants, as well as from modified and reconstructed sources. At the same time, the EPA finalized the Clean Power Plan, requiring a reduction in GHG emissions from existing power plants of 32% from 2005 levels by 2030. The Clean Power Plan provides states flexibility in meeting the emission reduction requirements including adding renewable generation and increasing dispatch of natural gas-fired generation. The Clean Power Plan will first take effect in 2022 with more modest interim reduction requirements, which will increase to the final requirements by 2030. The Clean Power Plan is structured as a set of requirements for states to implement, with such state rulemakings required in the 2016-2018 time frame. At the same time, the EPA proposed a “Federal Plan,” which is a set of regulations the EPA will impose in the event the states do not act timely. Litigation to invalidate the Clean Power Plan has already been filed by at least 15 states and a number of industry opponents.

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.

Demand Response

The FERC’s Order No. 745 regarding compensation of demand response in the energy market was appealed to the D.C. Circuit. In May 2014, the D.C. Circuit issued an order vacating and remanding Order No. 745 on the basis that the FERC does not have jurisdiction to regulate demand response in the energy market. On January 15, 2015, the FERC and several other entities filed petitions for certiorari with the U.S. Supreme Court, asking for review of the D.C. Circuit’s decision. Also, on October 20, 2014, the D.C. Circuit granted the FERC’s request for a stay of the decision. In May 2015, the U.S. Supreme Court granted the petitions for certiorari. Oral argument was held on October 14, 2015. The stay will remain in place until final disposition by the U.S. Supreme Court.

On January 30, 2013, the EPA finalized amendments to the National Emission Standards for Hazardous Air Pollutants (“NESHAP”) for Reciprocating Internal Combustion Engines (“RICE”). The final rule creates an exemption from otherwise applicable air emission requirements for uncontrolled “emergency” diesel-fired backup generators to operate for up to 100 hours per year for “emergency demand response” (“the 100-Hour Rule”) and up to 50 hours per year in certain non-emergency situations as part of a financial arrangement with another entity.

On May 1, 2015, the D.C. Circuit vacated the RICE NESHAP 100-Hour Rule and further modified its original ruling on July 21, 2015. The EPA sought a stay of the mandate until May 1, 2016, which was granted by the D.C. Circuit on August 18, 2015. On September 23, 2015, at the request of the EPA, the D.C. Circuit remanded the 50-hour rule without vacatur; therefore, the 50-hour rule remains in effect.

National Ambient Air Quality Standards - Ozone

As part of its ongoing Clean Air Act obligation to periodically review National Ambient Air Quality Standards (“NAAQS”) to ensure that air quality is protective of human health and the environment, on October 1, 2015, the EPA set a new standard for ground-level of ozone of 70 parts per billion, down from the standard set in 2008 of 75 parts per billion. This is significant to the power sector because ground-level ozone is a product of complex chemical reactions contributed to by nitrogen oxides, or NOx, which are one of the primary emissions of concern from power plants. A tighter ozone standard may lead to further, more stringent regulation of NOx emissions from mobile sources and a number of industries, particularly the power industry. Rulemaking to support attainment of this newer standard will go through multiple stages, with regulations beginning to take effect in approximately 2020. As with CSAPR and other regulations noted above, we believe that our clean, efficient generating fleet positions us well for the implementation of these regulations.

Clean Water Act - Waters of the United States

On June 29, 2015, the EPA published the “Clean Water Rule: Definition of Waters of the United States Under the Clean Water Act,” which redefined and broadened the scope of Clean Water Act jurisdiction. The rule became effective on August 28, 2015. We do not anticipate a significant impact to our business as a result of the Clean Water Rule.

Clean Water Act - Effluent Limit Guidelines

The EPA is required by the Clean Water Act to issue and periodically update Effluent Limit Guidelines (“ELG”) for different categories of industrial sources, including power plants. The EPA last issued power plant ELGs in the early 1980s. The EPA proposed new ELGs for the power sector in April 2013. The proposed rules would mostly be significant for coal-fired power plants, particularly wastewater from coal combustion residuals and air quality control processes. The EPA finalized the revised ELGs on September 30, 2015. These rules target waste streams from coal-fired power plants (fly ash and bottom ash transport water; wastewater from flue-gas mercury control, flue-gas desulfurization, and coal gasification processes; and leachates from combustion residual landfills and ponds) and are expected to have no direct impact on our fleet of power plants.

California: GHG - Cap-and-Trade Regulation

California’s AB 32 requires the state to reduce statewide GHG emissions to 1990 levels by 2020. To meet this benchmark, the California Air Resources Board (“CARB”) has promulgated a number of regulations, including the Cap-and-Trade Regulation and Mandatory Reporting Rule, which took effect on January 1, 2012. These regulations have since been amended by the CARB several times.

Under the Cap-and-Trade Regulation, the first compliance period for covered entities like Calpine began on January 1, 2013 and ended on December 31, 2014. The second and third compliance periods, wherein the program applies to a broader scope of entities, including transportation fuels and natural gas distribution, run through the end of 2017 and 2020, respectively. Covered entities must surrender compliance instruments, which include both allowances and offset credits, in an amount equivalent to their GHG emissions.

On January 1, 2014, the California Cap-and-Trade market was officially linked to the GHG Cap-and-Trade market in Quebec. The first joint GHG allowance auction occurred on November 25, 2014. Joint auctions of allowances issued by both jurisdictions, which can be used interchangeably, are held quarterly.

On May 22, 2014, the CARB approved its first update to the Climate Change Scoping Plan pursuant to AB 32. The updated scoping plan states that California is on track to meet its 2020 emissions target and makes recommendations for how the state can achieve the goal established by a 2005 executive order of reducing statewide GHG emissions to 80% below 1990 levels by 2050, including recommending the establishment of a mid-term emissions target for 2030. On April 29, 2015, California Governor Jerry Brown issued an executive order that establishes a new interim GHG reduction target of 40% below 1990 levels by 2030 and orders the CARB to update the Climate Change Scoping Plan to express the 2030 target in tons of GHG emissions.

Legislation that would enact both the 2050 and 2030 goals into law, known as Senate Bill (“SB”) 32, failed to pass in the first year of the two-year legislative session, but is expected to be reconsidered by the California Legislature in 2016. Although SB 32 has not yet been enacted into law, another bill, SB 350, which was enacted into law in 2015, requires the CPUC to adopt a process for each load-serving entity to file an integrated resource plan to ensure they meet greenhouse gas emissions reduction targets established by the CARB, in coordination with the CPUC and the California Energy Commission, for the electricity sector and each load-serving entity, which reflect the electricity sector’s percentage in achieving the economy-wide greenhouse gas emissions reductions of 40% from 1990 levels by 2030. At this time, neither the CARB, nor the CPUC, has initiated a public process to implement this requirement or to establish the emission reductions targets for the electricity sector and each load-serving entity described by it.

On April 13, 2015, Ontario’s Premier Kathleen Wynne announced that the Canadian province will be developing a Cap-and-Trade program and intends to join the linked California-Quebec market. Several rulemaking steps would need to occur before an Ontario Cap-and-Trade system could be linked with the California program, including that the California governor would need to make findings regarding the equivalence and enforceability of Ontario’s GHG emission reduction program and the CARB would need to adopt an amendment to the Cap-and-Trade Regulation.

Overall, we support AB 32 and expect the net impact of the Cap-and-Trade Regulation to be beneficial to Calpine. We also believe we are well positioned to comply with the Cap-and-Trade Regulation.

California RPS

As recently expanded by SB 350, California’s RPS requires retail power providers to generate or procure 33% and 50% of the power they sell to retail customers from renewable resources by 2020 and 2030, respectively, with intermediate targets leading up to 2020 and 2030. Behind-the-meter solar generally does not count towards California’s RPS requirements. Under California’s RPS, there are limits on different “buckets” of procurement that can be used to satisfy the RPS. Load-serving entities must satisfy a growing fraction of their compliance obligations with renewable power from resources located in California or delivered into California within the hour, such as our Geysers Assets. While the RPS generally depresses wholesale energy prices,

the intermittency of many renewable resources presents operational flexibility challenges that present opportunities for natural gas-fired generation to provide capacity and ancillary services products.

RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2015 AND 2014

Below are our results of operations for the three months ended September 30, 2015 as compared to the same period in 2014 (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.



	2015			2014			Change			% Change
Operating revenues:
Commodity revenue	$	1,888		$	2,186		$	(298	)	(14	)
Mark-to-market gain (loss)	55			(2		)	57			#
Other revenue	5			3			2			67
Operating revenues	1,948			2,187			(239		)	(11	)
Operating expenses:
Fuel and purchased energy expense:
Commodity expense	943			1,281			338			26
Mark-to-market (gain) loss	130			(13		)	(143		)	#
Fuel and purchased energy expense	1,073			1,268			195			15
Plant operating expense	200			215			15			7
Depreciation and amortization expense	166			153			(13		)	(8	)
Sales, general and other administrative expense	33			37			4			11
Other operating expenses	16			23			7			30
Total operating expenses	1,488			1,696			208			12
Impairment losses	—			123			123			#
(Gain) on sale of assets, net	—			(753		)	(753		)	#
(Income) from unconsolidated investments in power plants	(6		)	(5		)	1			20
Income from operations	466			1,126			(660		)	(59	)
Interest expense	159			156			(3		)	(2	)
Interest (income)	(1		)	(2		)	(1		)	(50	)
Debt extinguishment costs	—			340			340			#
Other (income) expense, net	1			4			3			75
Income before income taxes	307			628			(321		)	(51	)
Income tax expense	28			9			(19		)	#
Net income	279			619			(340		)	(55	)
Net income attributable to the noncontrolling interest	(6		)	(5		)	(1		)	(20	)
Net income attributable to Calpine	$	273		$	614		$	(341	)	(56	)



	2015		2014		Change		% Change
Operating Performance Metrics:
MWh generated (in thousands)⁽¹⁾	32,583		28,449		4,134		15
Average availability	97.0	%	96.6	%	0.4	%	—
Average total MW in operation⁽¹⁾	25,807		25,071		736		3
Average capacity factor, excluding peakers	63.3	%	57.7	%	5.6	%	10
Steam Adjusted Heat Rate	7,336		7,402		66		1

__________


#	Variance of 100% or greater


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

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 of 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 $40 million for the three months ended September 30, 2015, compared to the same period in 2014, primarily due to:


•	the acquisition of our 731 MW Fore River Energy Center in November 2014 and the commencement of commercial operations at our 309 MW Garrison Energy Center in June 2015;


•	higher regulatory capacity revenue; and


•	higher settled Spark Spreads in Texas in July and August 2015 compared to the same months in 2014; partially offset by


•	lower contribution from hedges; and


•	lower Spark Spreads in the West due to lower natural gas prices during the third quarter of 2015 compared to the third quarter of 2014.

Generation increased 15% primarily due to stronger market conditions and lower natural gas prices in Texas, the acquisition of our 731 MW Fore River Energy Center in November 2014 and the commencement of commercial operations at our 309 MW Garrison Energy Center in June 2015. Our average total MW in operation increased by 736 MW, or 3%, primarily due to Fore River and Garrison Energy Centers.

Mark-to-market gain/loss on our derivative hedge position had an unfavorable variance of $86 million primarily driven by settlement of previous mark-to-market gains on 2015 hedges during the third quarter of 2015 as compared to the same period in 2014.

Plant operating expense decreased by $15 million for the three months ended September 30, 2015, compared to the same period in 2014 due to a $12 million decrease in our normal, recurring plant operating expense and a $4 million decrease in major maintenance expense resulting from our plant outage schedule, net of an increase in costs from scrap parts related to outages.

Depreciation and amortization expense increased by $13 million for the three months ended September 30, 2015, compared to the same period in 2014, primarily due to the acquisition of our Fore River Energy Center in November 2014 and commencement of commercial operations at our Garrison Energy Center in June 2015.

In line with our strategy to sell or contract power plants located in wholesale power markets dominated by regulated utilities and focus on competitive wholesale markets, we completed the sale of six of our power plants in our East segment on July 3, 2014, resulting in a gain on sale of assets, net of $753 million, which was recorded during the third quarter of 2014. In addition, we executed a term sheet with a third party related to our Osprey Energy Center in August 2014 for a new PPA with a term of 27 months, after which the third party would purchase our Osprey Energy Center which resulted in an impairment loss of approximately $123 million that was recorded during the third quarter of 2014.

Debt extinguishment costs for the three months ended September 30, 2014, consisted of $340 million in connection with the repayment of our 2019 First Lien Notes, 2020 First Lien Notes and 2021 First Lien Notes, which is comprised of $306 million of prepayment penalties and $34 million associated with the write-off of unamortized debt discount and deferred financing costs.

During the three months ended September 30, 2015, we recorded income tax expense of $28 million compared to $9 million for the same period in 2014. The unfavorable period-over-period change primarily resulted from an increase in various state and foreign jurisdiction income taxes and the application of the intraperiod tax allocation.

RESULTS OF OPERATIONS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2015 AND 2014

Below are our results of operations for the nine months ended September 30, 2015 as compared to the same period in 2014 (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.



	2015			2014			Change			% Change
Operating revenues:
Commodity revenue	$	4,933		$	6,000		$	(1,067	)	(18	)
Mark-to-market gain	89			81			8			10
Other revenue	14			10			4			40
Operating revenues	5,036			6,091			(1,055		)	(17	)
Operating expenses:
Fuel and purchased energy expense:
Commodity expense	2,754			3,757			1,003			27
Mark-to-market loss	95			2			(93		)	#
Fuel and purchased energy expense	2,849			3,759			910			24
Plant operating expense	732			754			22			3
Depreciation and amortization expense	484			453			(31		)	(7	)
Sales, general and other administrative expense	100			108			8			7
Other operating expenses	56			66			10			15
Total operating expenses	4,221			5,140			919			18
Impairment losses	—			123			123			#
(Gain) on sale of assets, net	—			(753		)	(753		)	#
(Income) from unconsolidated investments in power plants	(18		)	(18		)	—			—
Income from operations	833			1,599			(766		)	(48	)
Interest expense	471			491			20			4
Interest (income)	(3		)	(5		)	(2		)	(40	)
Debt modification and extinguishment costs	32			341			309			91
Other (income) expense, net	8			20			12			60
Income before income taxes	325			752			(427		)	(57	)
Income tax expense	32			5			(27		)	#
Net income	293			747			(454		)	(61	)
Net income attributable to the noncontrolling interest	(11		)	(11		)	—			—
Net income attributable to Calpine	$	282		$	736		$	(454	)	(62	)



	2015		2014		Change		% Change
Operating Performance Metrics:
MWh generated (in thousands)⁽¹⁾	85,104		74,511		10,593		14
Average availability	90.8	%	90.9	%	(0.1	)%	—
Average total MW in operation⁽¹⁾	25,777		27,045		(1,268	)	(5	)
Average capacity factor, excluding peakers	56.3	%	47.1	%	9.2	%	20
Steam Adjusted Heat Rate	7,312		7,396		84		1

__________


#	Variance of 100% or greater


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

Commodity revenue, net of Commodity expense, decreased $64 million for the nine months ended September 30, 2015, compared to the same period in 2014, primarily due to:


•	a significant decrease in power and natural gas prices in our East segment in the first quarter of 2015 compared to the prior year period, given the unusually high price levels experienced during the polar vortex events in the first quarter of 2014;

•

the net impact of our portfolio management activities, including the sale of six power plants with a total capacity of 3,498 MW in our East segment in July 2014, the acquisition of our Guadalupe and Fore River Energy Centers in February and November 2014, respectively, the commencement of commercial operations at our Garrison Energy Center in June 2015 and the completion of the expansions of our Deer Park and Channel Energy Centers in June 2014; and


•	lower regulatory capacity revenue in PJM; partially offset by


•	higher contribution from hedges which more than offset lower on-peak Spark Spreads across all of our segments, excluding the impact of the polar vortex events experienced during the first quarter of 2014; and


•	higher generation in Texas resulting from lower natural gas prices, which drove lower system-wide coal-fired generation during the nine months ended September 30, 2015.

Generation increased 14% primarily due to higher generation in Texas due to the factors described above. Our average total MW in operation decreased by 1,268 MW, or 5%, primarily due to the aforementioned changes in our power plant portfolio.

Mark-to-market gain/loss on our derivative hedge position had an unfavorable variance of $85 million primarily driven by settlement of previous mark-to-market gains on 2015 hedges during the nine months ended September 30, 2015 as compared to the same period in 2014.

Plant operating expense decreased by $22 million for the nine months ended September 30, 2015, compared to the same period in 2014. Our normal, recurring plant operating expense, after excluding a decrease of $17 million attributable to power plant portfolio changes, decreased by $12 million during the nine months ended September 30, 2015 compared to the same period in 2014 primarily resulting from a decrease in equipment failure costs related to outages. The overall decrease was partially offset by a net increase of $7 million related to an increase in major maintenance expense resulting from our plant outage schedule and costs from scrap parts related to outages, net of a decrease in stock-based compensation expense and other miscellaneous costs.

Depreciation and amortization expense increased by $31 million for the nine months ended September 30, 2015, compared to the same period in 2014, primarily due to the acquisition of our Guadalupe and Fore River Energy Centers in February and November 2014, respectively, the commencement of commercial operations at our Garrison Energy Center in June 2015 and the completion of the expansions of our Deer Park and Channel Energy Centers in June 2014.

Sales, general and other administrative expenses decreased by $8 million for the nine months ended September 30, 2015, compared to the same period in 2014, primarily due to a decrease in the fair value of stock-based compensation awards.

Other operating expenses decreased by $10 million for the nine months ended September 30, 2015 compared to the same period in 2014 primarily due to a decrease in production royalty expense associated with our Geysers Assets and a decrease in operating lease expense due to the expiration of the operating lease associated with the Greenleaf power plants in June 2015.

Interest expense decreased by $20 million for the nine months ended September 30, 2015, compared to the same period in 2014, primarily due to a decrease in our annual effective interest rate on our consolidated debt, excluding the impacts of capitalized interest and mark-to-market gains (losses) on interest rate swaps, to 5.4% for the nine months ended September 30, 2015, from 6.0% for the nine months ended September 30, 2014. The issuance of our Senior Unsecured Notes in July 2014 and 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.

Debt modification and extinguishment costs for the nine months ended September 30, 2015, consisted of $19 million in debt extinguishment costs 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, and $13 million in debt modification costs related to the issuance of our 2022 First Lien Term Loan in May 2015. Debt extinguishment costs for the nine months ended September 30, 2014, primarily consisted of $340 million in connection with the repayment of our 2019 First Lien Notes, 2020 First Lien Notes and 2021 First Lien Notes, which is comprised of $306 million of prepayment penalties and $34 million associated with the write-off of unamortized debt discount and deferred financing costs.

During the nine months ended September 30, 2015, we recorded income tax expense of $32 million compared to $5 million for the same period in 2014. The unfavorable period-over-period change primarily resulted from a one-time tax benefit recorded during the first quarter of 2014 associated with the reorganization of certain Calpine subsidiaries as well as an increase in various state and foreign jurisdiction income taxes and the application of the intraperiod tax allocation during the nine months ended September 30, 2015 compared to the same period in 2014.

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 from operations by segment.

Commodity Margin by Segment for the Three Months Ended September 30, 2015 and 2014

The following tables show our Commodity Margin and related operating performance metrics by segment for the three months ended September 30, 2015 and 2014 (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.



West:	2015			2014			Change			% Change
Commodity Margin (in millions)	$	385		$	361		$	24		7
Commodity Margin per MWh generated	$	38.05		$	37.47		$	0.58		2

MWh generated (in thousands)	10,117			9,634			483			5
Average availability	97.6		%	98.6		%	(1.0		)%	(1	)
Average total MW in operation	7,425			7,524			(99		)	(1	)
Average capacity factor, excluding peakers	66.0		%	61.9		%	4.1		%	7
Steam Adjusted Heat Rate	7,333			7,325			(8		)	—

West — Commodity Margin in our West segment increased by $24 million, or 7%, for the three months ended September 30, 2015 compared to the three months ended September 30, 2014, primarily due to higher contribution from hedges and a 5% increase in generation resulting from a decrease in hydroelectric generation in the Pacific Northwest. The increase in Commodity Margin was partially offset by lower power prices and Spark Spreads resulting from lower natural gas prices during the three months ended September 30, 2015 compared to the three months ended September 30, 2014, the expiration of the operating lease related to our Greenleaf power plants in June 2015 and a wildfire in northern California in September 2015 which negatively impacted our Geysers Assets.



Texas:	2015			2014			Change			% Change
Commodity Margin (in millions)	$	264		$	346		$	(82	)	(24	)
Commodity Margin per MWh generated	$	19.45		$	29.02		$	(9.57	)	(33	)

MWh generated (in thousands)	13,576			11,924			1,652			14
Average availability	97.2		%	96.3		%	0.9		%	1
Average total MW in operation	9,191			9,191			—			—
Average capacity factor, excluding peakers	66.9		%	58.8		%	8.1		%	14
Steam Adjusted Heat Rate	7,111			7,215			104			1

Texas — Commodity Margin in our Texas segment decreased by $82 million, or 24%, for the three months ended September 30, 2015 compared to the three months ended September 30, 2014, primarily due to lower contribution from hedges. The decrease in Commodity Margin was partially offset by higher settled Spark Spreads in July and August 2015 compared to the same months in 2014 as well as a 14% increase in generation due to stronger market conditions and lower natural gas prices that drove lower systemwide coal-fired generation during the third quarter of 2015 compared to the same period in 2014.



East:	2015			2014			Change			% Change
Commodity Margin (in millions)	$	325		$	237		$	88		37
Commodity Margin per MWh generated	$	36.56		$	34.39		$	2.17		6

MWh generated (in thousands)	8,890			6,891			1,999			29
Average availability	96.2		%	95.1		%	1.1		%	1
Average total MW in operation	9,191			8,356			835			10
Average capacity factor, excluding peakers	55.8		%	50.8		%	5.0		%	10
Steam Adjusted Heat Rate	7,710			7,848			138			2

East — Commodity Margin in our East segment increased by $88 million, or 37%, for the three months ended September 30, 2015 compared to the three months ended September 30, 2014, primarily due to higher contribution from hedges, the acquisition of our 731 MW Fore River Energy Center in November 2014 and the commencement of commercial operations at our 309 MW Garrison Energy Center in June 2015. Also contributing to the increase in Commodity Margin was higher regulatory capacity revenues during the three months ended September 30, 2015 compared to the same period in 2014 and the positive impact of a new contract for our Osprey Energy Center which became effective in the fourth quarter of 2014. Average total MW in operation increased by 835 MW, or 10%, primarily due to Fore River and Garrison Energy Centers which were also the primary drivers of the 29% increase in generation.

Commodity Margin by Segment for the Nine Months Ended September 30, 2015 and 2014

The following tables show our Commodity Margin and related operating performance metrics by segment for the nine months ended September 30, 2015 and 2014 (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.



West:	2015			2014			Change			% Change
Commodity Margin (in millions)	$	843		$	791		$	52		7
Commodity Margin per MWh generated	$	32.67		$	31.35		$	1.32		4

MWh generated (in thousands)	25,800			25,235			565			2
Average availability	89.6		%	93.1		%	(3.5		)%	(4	)
Average total MW in operation	7,491			7,524			(33		)	—
Average capacity factor, excluding peakers	56.1		%	54.7		%	1.4		%	3
Steam Adjusted Heat Rate	7,322			7,310			(12		)	—

West — Commodity Margin in our West segment increased by $52 million, or 7%, for the nine months ended September 30, 2015 compared to the nine months ended September 30, 2014, primarily due to higher contribution from hedges, a 2% increase in generation resulting from a decrease in hydroelectric generation in the Pacific Northwest and higher REC revenues associated with our Geysers Assets resulting from more favorable REC pricing in 2015. The increase in Commodity Margin was partially offset by lower power prices and on-peak Spark Spreads resulting from lower natural gas prices for the nine months ended September 30, 2015 compared to the nine months ended September 30, 2014, the expiration of the operating lease related to our Greenleaf power plants in June 2015 and a wildfire in northern California in September 2015 which negatively impacted our Geysers Assets. Average availability decreased 4% due to an increase in planned outages during the second quarter of 2015 compared to the same period in 2014.



Texas:	2015			2014			Change			% Change
Commodity Margin (in millions)	$	583		$	644		$	(61	)	(9	)
Commodity Margin per MWh generated	$	16.05		$	22.76		$	(6.71	)	(29	)

MWh generated (in thousands)	36,314			28,290			8,024			28
Average availability	90.9		%	90.2		%	0.7		%	1
Average total MW in operation	9,191			8,745			446			5
Average capacity factor, excluding peakers	60.3		%	49.4		%	10.9		%	22
Steam Adjusted Heat Rate	7,096			7,222			126			2

Texas — Commodity Margin in our Texas segment decreased by $61 million, or 9%, for the nine months ended September 30, 2015 compared to the nine months ended September 30, 2014, primarily due to lower contribution from summer hedges and lower on-peak Spark Spreads resulting from lower natural gas prices. The decrease in Commodity Margin was partially offset by the acquisition of our 1,000 MW Guadalupe Energy Center on February 26, 2014, the expansions of our Deer Park and Channel Energy Centers which were completed in June 2014 and a 28% increase in generation due to stronger market conditions in the third quarter of 2015 and lower natural gas prices that drove lower systemwide coal-fired generation during the nine months ended September 30, 2015 compared to the same period in 2014. Our average total MW in operation increased 446 MW, or 5%, primarily resulting from the acquisition of Guadalupe Energy Center and the expansions of our Deer Park and Channel Energy Centers.



East:	2015			2014			Change			% Change
Commodity Margin (in millions)	$	740		$	786		$	(46	)	(6	)
Commodity Margin per MWh generated	$	32.19		$	37.45		$	(5.26	)	(14	)

MWh generated (in thousands)	22,990			20,986			2,004			10
Average availability	91.6		%	89.8		%	1.8		%	2
Average total MW in operation	9,095			10,776			(1,681		)	(16	)
Average capacity factor, excluding peakers	50.9		%	38.0		%	12.9		%	34
Steam Adjusted Heat Rate	7,660			7,733			73			1

East — Commodity Margin in our East segment increased by $35 million for the nine months ended September 30, 2015 compared to the nine months ended September 30, 2014, after excluding a decrease of $81 million resulting from the sale of six power plants with a total capacity of 3,498 MW on July 3, 2014. The increase in Commodity Margin was primarily due to higher contribution from hedges, the acquisition of our 731 MW Fore River Energy Center in November 2014 and the commencement of commercial operations at our 309 MW Garrison Energy Center in June 2015. Also contributing to the increase in Commodity Margin was a 10% increase in generation driven by lower natural gas prices and the positive impact of a new contract for our Osprey Energy Center which became effective in the fourth quarter of 2014. The increase in Commodity Margin was partially offset by a significant decrease in power and natural gas prices in the first quarter of 2015 compared to the prior year period, given the unusually high price levels experienced during the polar vortex events in the first quarter of 2014, as well as lower regulatory capacity revenues in PJM during the nine months ended September 30, 2015 compared to the same period in 2014. Average total MW in operation decreased 1,681 MW, or 16%, primarily due to the aforementioned power plant portfolio changes.

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 from operations on a segment basis and to net income attributable to Calpine on a consolidated basis for the periods indicated (in millions).



	Three Months Ended September 30, 2015
	West			Texas		East			Consolidation and Elimination			Total
Net income attributable to Calpine												$	273
Net income attributable to the noncontrolling interest												6
Income tax expense												28
Other (income) expense, net												1
Interest expense, net of interest income												158
Income from operations	$	290		$	29	$	146		$	1		$	466
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs⁽¹⁾	59			58		47			—			164
Major maintenance expense	8			11		8			—			27
Operating lease expense	—			—		6			—			6
Mark-to-market (gain) loss on commodity derivative activity	(95		)	106		64			—			75
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest⁽²⁾	(12		)	—		9			—			(3		)
Stock-based compensation expense	3			2		2			—			7
Loss on dispositions of assets	4			1		—			—			5
Acquired contract amortization	—			—		4			—			4
Other	44			—		(3		)	(1		)	40
Total Adjusted EBITDA	$	301		$	207	$	283		$	—		$	791



	Three Months Ended September 30, 2014
	West			Texas		East⁽³⁾			Consolidation and Elimination			Total
Net income attributable to Calpine												$	614
Net income attributable to the noncontrolling interest												5
Income tax expense												9
Debt extinguishment costs and other (income) expense, net												344
Interest expense, net of interest income												154
Income from operations	$	223		$	135	$	769		$	(1	)	$	1,126
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs⁽¹⁾	63			51		38			—			152
Major maintenance expense	7			20		9			—			36
Operating lease expense	3			—		6			—			9
Mark-to-market (gain) loss on commodity derivative activity	(68		)	71		(14		)	—			(11		)
Impairment losses	—			—		123			—			123
(Gain) on sale of assets	—			—		(753		)	—			(753		)
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest⁽²⁾	(11		)	—		8			—			(3		)
Stock-based compensation expense	3			3		2			—			8
Acquired contract amortization	—			—		4			—			4
Other	43			2		8			1			54
Total Adjusted EBITDA	$	263		$	282	$	200		$	—		$	745



	Nine Months Ended September 30, 2015
	West			Texas		East		Consolidation and Elimination			Total
Net income attributable to Calpine											$	282
Net income attributable to the noncontrolling interest											11
Income tax expense											32
Debt modification and extinguishment costs and other (income) expense, net											40
Interest expense, net of interest income											468
Income from operations	$	459		$	93	$	280	$	1		$	833
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs⁽¹⁾	189			157		134		—			480
Major maintenance expense	74			66		55		—			195
Operating lease expense	4			—		19		—			23
Mark-to-market (gain) loss on commodity derivative activity	(142		)	70		78		—			6
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest⁽²⁾	(19		)	—		25		—			6
Stock-based compensation expense	8			7		4		—			19
Loss on dispositions of assets	4			3		1		—			8
Acquired contract amortization	—			—		11		—			11
Other	2			1		3		(1		)	5
Total Adjusted EBITDA	$	579		$	397	$	610	$	—		$	1,586



	Nine Months Ended September 30, 2014
	West			Texas			East⁽³⁾			Consolidation and Elimination		Total
Net income attributable to Calpine												$	736
Net income attributable to the noncontrolling interest												11
Income tax expense												5
Debt extinguishment costs and other (income) expense, net												361
Interest expense, net of interest income												486
Income from operations	$	341		$	275		$	983		$	—	$	1,599
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs⁽¹⁾	179			141			129			—		449
Major maintenance expense	53			77			59			—		189
Operating lease expense	7			—			19			—		26
Mark-to-market (gain) loss on commodity derivative activity	(54		)	(53		)	28			—		(79		)
Impairment losses	—			—			123			—		123
(Gain) on sale of assets	—			—			(753		)	—		(753		)
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest⁽²⁾	(17		)	—			23			—		6
Stock-based compensation expense	9			12			9			—		30
Loss on dispositions of assets	1			—			—			—		1
Acquired contract amortization	—			—			11			—		11
Other	(3		)	3			2			—		2
Total Adjusted EBITDA	$	516		$	455		$	633		$	—	$	1,604

____________


(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 the three and nine months ended September 30, 2015 and 2014.


(3)	Adjusted EBITDA related to the six power plants sold in our East segment on July 3, 2014 was not significant for the three months ended September 30, 2014. Adjusted EBITDA related to those power plants was $43 million for the nine months ended September 30, 2014.

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 September 30, 2015 and December 31, 2014 (in millions):



	September 30, 2015		December 31, 2014
Cash and cash equivalents, corporate⁽¹⁾	$	558	$	460
Cash and cash equivalents, non-corporate	101		257
Total cash and cash equivalents	659		717
Restricted cash	275		244
Corporate Revolving Facility availability	1,330		1,277
CDHI letter of credit facility availability	62		86
Total current liquidity availability	$	2,326	$	2,324

____________


(1)	Includes $15 million and $47 million of margin deposits posted with us by our counterparties at September 30, 2015 and December 31, 2014, respectively.

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 September 30, 2015, an increase of $1/MMBtu in natural gas prices would result in an increase of collateral required by approximately $154 million. If natural gas prices decreased by $1/MMBtu, we estimate that our collateral requirements would decrease by approximately $142 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 September 30, 2015, 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 $49 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 September 30, 2015 and December 31, 2014 (in millions):



	September 30, 2015		December 31, 2014
Corporate Revolving Facility⁽¹⁾	$	170	$	223
CDHI	238		214
Various project financing facilities	239		207
Total	$	647	$	644

____________


(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, made progress toward completing or initiated certain key capital management transactions during 2015, as further described below.

Share Repurchase Program

In 2015, through the filing of this Report, we have repurchased a total of 26.6 million shares of our common stock for approximately $529 million at an average price of $19.87 per share.

2024 Senior Unsecured Notes

In February 2015, we issued $650 million in aggregate principal amount of 5.5% senior unsecured notes due 2024 in a public offering and used the net proceeds to replenish cash on hand used for the acquisition of Fore River Energy Center in the fourth quarter of 2014, to repurchase approximately $147 million of our 2023 First Lien Notes and for general corporate purposes. See Note 4 of the Notes to Consolidated Condensed Financial Statements for a further description of our 2024 Senior Unsecured Notes.

2022 First Lien Term Loan

In May 2015, we repaid our 2018 First Lien Term Loans with the proceeds from the 2022 First Lien Term Loan which extended the maturity and reduced the interest rate on approximately $1.6 billion of corporate debt. See Note 4 of the Notes to Consolidated Condensed Financial Statements for a further description of our 2022 First Lien Term Loan.

2023 First Lien Notes

In October 2015, we issued notice to the holders of our 2023 First Lien Notes of our intent to redeem 10% of the original aggregate principal amount, plus accrued and unpaid interest. We intend to use cash on hand to fund the redemption.

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 October 12, 2015, we entered into an agreement to purchase Granite Ridge Energy Center, a power plant with a nameplate capacity of 745 MW, for approximately $500 million, excluding working capital adjustments. The addition of this modern, efficient, natural gas-fired, combined-cycle power plant will increase capacity in our East segment, specifically the constrained New England market. See Note 2 of the Notes to the Consolidated Condensed Financial Statements for a further description of our acquisition of the Granite Ridge Energy Center.

Garrison Energy Center — Our Garrison Energy Center commenced commercial operations in June 2015, bringing online approximately 309 MW of combined-cycle, natural gas-fired capacity. The power plant features one combustion turbine, one heat recovery steam generator and one steam turbine, and is expected to be dual-fuel capable by this winter. We are in the early stages of development of a second phase of the Garrison Energy Center.

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 70 MW of planned capacity at the York 2 Energy Center. This incremental 70 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 between the dates of June 1, 2017, and 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 remains subject to approval by the North Dakota Public Service Commission. Commercial operation of the expanded capacity may commence as early as 2019, subject to requisite regulatory approvals and applicable contract conditions.

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.

Osprey Energy Center — During the fourth quarter of 2014, we executed an asset sale agreement for the sale of our Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million, excluding working capital and other adjustments. In accordance with the asset sale agreement, the sale will be consummated in January 2017 upon the conclusion of a 27-month PPA. In July 2015, the transaction was approved by the FERC and the Florida Public Service Commission. This sale 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 September 30, 2015, we have completed the upgrade of thirteen 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-Oriented Origination Business

We continue to focus on providing products and services that are beneficial to our customers. A summary of certain significant contracts entered into in 2015 is as follows:

Retail Acquisition

•

On October 1, 2015, we completed the acquisition of Champion Energy for approximately $240 million, excluding working capital adjustments. Champion Energy, a leading retail electric provider, is expected to serve approximately 22 million MWh of commercial, industrial and residential customer load in 2015, concentrated in Texas, PJM and the Northeast U.S. where Calpine has a substantial power generation presence. The addition of this well-established retail sales organization is expected to provide us an important outlet for directly reaching a much greater portion of the load we serve.

West


•	We entered into a new three-year PPA with Marin Clean Energy to provide up to 65 MW of power from our Delta Energy Center and other northern California power plants commencing in April 2015 and extending through December 2017.


•	Our ten-year PPA with Southern California Edison for 225 MW of capacity and renewable energy from our Geysers Assets commencing in June 2017 was approved by the CPUC in the first quarter of 2015.


•	We entered into a new ten-year PPA with Southern California Edison for 50 MW of capacity and renewable energy from our Geysers Assets commencing in January 2018. The PPA remains subject to approval by the CPUC.


•	We entered into a new one-year resource adequacy contract with SCE for 238 MW from our Pastoria Energy Center commencing in January 2018.

Texas


•	We entered into a new three-year PPA with Brazos Electric Power Cooperative to provide 300 MW of power from our Texas power plant fleet commencing in January 2016.


•	We entered into a new three-year PPA with Pedernales Electric Cooperative to provide approximately 140 MW of power from our Texas power plant fleet commencing in January 2017.


•	We entered into a new two-year PPA with Guadalupe Valley Electric Cooperative to provide approximately 270 MW of power from our Texas power plant fleet commencing in June 2017. The execution of this PPA will facilitate the construction of a 418 MW natural gas-fired peaking power plant to be co-located with our Guadalupe Energy Center.

East


•	We entered into a new 20-year PPA with Xcel Energy to provide up to 345 MW of capacity and energy from our Mankato Power Plant expansion when commercial operations commence and transmission-related upgrades have been completed.

Wildfire at our Geysers Assets

In September 2015, a wildfire spread to our Geysers Assets in Lake and Sonoma Counties, California, affecting five of our 14 power plants in the region which sustained damage to ancillary structures such as cooling towers and communication/electric deliverability infrastructure. The wildfire has since been contained and our Geysers Assets are generating renewable power for our customers at approximately three-quarters of the normal operating capacity. We expect our insurance program to cover repair and replacement costs as well as our net revenue losses after deductibles are met. As a result, we do not anticipate that the wildfire 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, 2014, our consolidated federal NOLs totaled approximately $6.9 billion.

Cash Flow Activities

The following table summarizes our cash flow activities for the nine months ended September 30, 2015 and 2014 (in millions):



	2015			2014
Beginning cash and cash equivalents	$	717		$	941
Net cash provided by (used in):
Operating activities	548			504
Investing activities	(450		)	550
Financing activities	(156		)	(466		)
Net increase (decrease) in cash and cash equivalents	(58		)	588
Ending cash and cash equivalents	$	659		$	1,529

Net Cash Provided By Operating Activities

Cash provided by operating activities for the nine months ended September 30, 2015, was $548 million compared to cash provided by operating activities of $504 million for the nine months ended September 30, 2014. The increase was primarily due to:

•

Income from operations — Income from operations, adjusted for non-cash items, decreased by $18 million for the nine months ended September 30, 2015, compared to the nine months ended September 30, 2014. Non-cash items consist primarily of depreciation and amortization, income from unconsolidated investments in power plants, impairment losses, gain on sale of assets, net and mark-to-market activity. The decrease in income from operations was primarily driven by a $64 million decrease in Commodity revenue, net of Commodity expense, partially offset by a $22 million decrease in plant operating expense and a $10 million decrease in other operating expenses for the nine months ended September 30, 2015 compared to the nine months ended September 30, 2014. See “Results of Operations for the Nine Months Ended September 30, 2015 and 2014” above for further discussion of these changes.

•

Working capital employed — Working capital employed increased by $289 million for the nine months ended September 30, 2015, compared to the nine months ended September 30, 2014, after adjusting for changes in debt, restricted cash and mark-to-market related balances which did not impact cash provided by operating activities. The increase was primarily due to the change in net margin requirements and an increase in the purchase of environmental allowances for the nine months ended September 30, 2015, compared to the nine months ended September 30, 2014.


•	Interest paid — Cash paid for interest decreased by $69 million to $465 million for the nine months ended September 30, 2015, from $534 million for the nine months ended September 30, 2014. The decrease was primarily due to our refinancing activity and the timing of interest payments.

•

Debt modification and extinguishment payments — Cash paid for debt modification and extinguishment decreased $275 million to $31 million during the nine months ended September 30, 2015, from $306 million for the nine months ended September 30, 2014. During the nine months ended September 30, 2015, we made cash payments of $13 million related to the issuance cost associated with our 2022 First Lien Term Loan and cash payments of $18 million related to the repayment penalties of a portion of our 2023 First Lien Notes, as compared to $306 million during the nine months ended September 30, 2014, which were associated with the repayment of our 2019 First Lien Notes, 2020 First Lien Notes and 2021 First Lien Notes.

Net Cash Provided By (Used In) Investing Activities

Cash used in investing activities for the nine months ended September 30, 2015, was $450 million compared to cash provided by investing activities of $550 million for the nine months ended September 30, 2014. The decrease was primarily due to:


•	Proceeds from the sale of power plants, interests and other — During the nine months ended September 30, 2014, we received proceeds of approximately $1.57 billion related to the completion of the sale of six power plants in our East segment. There was no similar activity during the nine months ended September 30, 2015.


•	Purchase of Guadalupe Energy Center — During the nine months ended September 30, 2014, we purchased a natural gas-fired, combined-cycle power plant located in Guadalupe County, Texas for $656 million. There were no acquisitions during the nine months ended September 30, 2015.

•

Capital expenditures — Capital expenditures for the nine months ended September 30, 2015, were $411 million, an increase of $57 million, compared to expenditures of $354 million for the nine months ended September 30, 2014. The increase was primarily due to higher expenditures on construction projects and outages during the nine months ended September 30, 2015, as compared to the nine months ended September 30, 2014.


•	Restricted cash — Restricted cash increased $31 million for the nine months ended September 30, 2015, compared to an increase of $15 million for the nine months ended September 30, 2014. The increase was due to normal operating activity.

Net Cash Used In Financing Activities

Cash used in financing activities for the nine months ended September 30, 2015 was $156 million, compared to cash used in financing activities of $466 million for the nine months ended September 30, 2014. The decrease was primarily due to:


•	CCFC refinancing — During the nine months ended September 30, 2014, we received proceeds of $420 million under the CCFC Term Loans, which were used to fund a portion of the purchase price paid in connection with the acquisition of the Guadalupe Energy Center. There was no similar activity during the nine months ended September 30, 2015.


•	Issuance of First Lien Term Loans — During the nine months ended September 30, 2015, we received proceeds of approximately $1.6 billion from the issuance of the 2022 First Lien Term Loan which was used together with operating cash on hand to repay the 2018 First Lien Term Loan of $1.6 billion. There was no similar activity during the nine months ended September 30, 2014.

•

First Lien Notes and Senior Unsecured Notes — During the nine months ended September 30, 2015, we received proceeds of $650 million from the issuance of the 2024 Senior Unsecured Notes which were used to replenish cash on hand used for the acquisition of Fore River Energy Center in the fourth quarter of 2014, repay $147 million of our 2023 First Lien Notes and other general corporate purposes. During the nine months ended September 30, 2014, we received proceeds of $2.8 billion from the issuance of our 2023 Senior Unsecured Notes and 2025 Senior Unsecured Notes, which were used to repay our 2019 First Lien Notes, 2020 First Lien Notes and 2021 First Lien Notes of $2.8 billion.


•	Proceeds from project debt — During the nine months ended September 30, 2014, we received proceeds of approximately $79 million on project debt for RCEC. There was no similar activity during the nine months ended September 30, 2015.

•

Repayments of project debt, notes payable and other — During the nine months ended September 30, 2015, we made repayments of $102 million compared to $116 million for the nine months ended September 30, 2014. The decrease is related to the repayments on project debt for RCEC and Los Esteros Critical Energy Facility, LLC (“LECEF”), partially offset by an increase in repayment on project debt for Calpine Steamboat Holdings, LLC.


•	Distribution to noncontrolling interest holder — During the nine months ended September 30, 2015, we made a distribution to the noncontrolling interest holder in Russell City Energy Company, LLC of approximately $6 million as compared to $12 million during the nine months ended September 30, 2014.

•

Financing costs — During the nine months ended September 30, 2015, we incurred finance costs of $17 million compared to $55 million for the nine months ended September 30, 2014. The decrease was primarily due to higher financing costs associated with the issuance of our 2023 Senior Unsecured Notes and 2025 Senior Unsecured Notes during the nine months ended September 30, 2014 as compared to the issuances of our 2024 Senior Unsecured Notes, 2022 First Lien Term Loan and the re-pricing of the project debt for LECEF during the nine months ended September 30, 2015.


•	Stock repurchases — During the nine months ended September 30, 2015, we made payments of $510 million to repurchase our common stock compared to $767 million during the nine months ended September 30, 2014.


•	Stock options proceeds — During the nine months ended September 30, 2015, we received proceeds from the exercise of stock options of $6 million compared to $19 million during the nine months ended September 30, 2014.

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 2014 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, gas transportation and storage arrangements, electric transmission service and other contracts for the sale and purchase of power products.

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 contracts, environmental product 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. On October 1, 2015, we completed the acquisition of Champion Energy, a leading retail electric provider, which will provide us with an additional outlet to transact hedging activities related to our wholesale power plant portfolio.

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 decreased to approximately $2.1 billion at September 30, 2015, when compared to approximately $2.5 billion at December 31, 2014, and our derivative liabilities have decreased to approximately $1.8 billion at September 30, 2015, when compared to approximately $2.2 billion at December 31, 2014. The fair value of our level 3 derivative assets and liabilities at September 30, 2015 represent a small portion of our total assets and liabilities measured at fair value (approximately 10% and 1%, respectively). During the nine months ended September 30, 2015, the fair value of our level 3 assets and liabilities increased primarily due to declines in forward power prices and the related impact on longer-dated power sales contracts. 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, 2015, through September 30, 2015, is summarized in the table below (in millions):



	Commodity Instruments			Interest Rate Swaps			Total
Fair value of contracts outstanding at January 1, 2015	$	381		$	(110	)	$	271
Items recognized or otherwise settled during the period⁽¹⁾⁽²⁾	(265		)	33			(232		)
Fair value attributable to new contracts	76			—			76
Changes in fair value attributable to price movements	239			(31		)	208
Changes in fair value attributable to nonperformance risk	(11		)	—			(11		)
Fair value of contracts outstanding at September 30, 2015⁽³⁾	$	420		$	(108	)	$	312

__________

(1)

Commodity contract settlements consist of the realization of previously recognized gains on contracts not designated as hedging instruments of $299 million (represents a portion of Commodity revenue and Commodity expense as reported on our Consolidated Condensed Statements of Operations) and $34 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 $30 million related to realized losses from settlements of designated cash flow hedges and $3 million related to realized losses from settlements of undesignated interest rate swaps (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 September 30,					Nine Months Ended September 30,
	2015			2014		2015			2014
Realized gain (loss)⁽¹⁾
Commodity derivative instruments	$	160		$	59	$	323		$	38
Total realized gain (loss)	$	160		$	59	$	323		$	38

Mark-to-market gain (loss)⁽²⁾
Commodity derivative instruments	$	(75	)	$	11	$	(6	)	$	79
Interest rate swaps	1			7		2			9
Total mark-to-market gain (loss)	$	(74	)	$	18	$	(4	)	$	88
Total activity, net	$	86		$	77	$	319		$	126

____________


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


(2)	In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.



	Three Months Ended September 30,					Nine Months Ended September 30,
	2015			2014		2015			2014
Realized and mark-to-market gain (loss)
Derivatives contracts included in operating revenues	$	189		$	53	$	423		$	(26	)
Derivatives contracts included in fuel and purchased energy expense	(104		)	17		(106		)	143
Interest rate swaps included in interest expense	1			7		2			9
Total activity, net	$	86		$	77	$	319		$	126

Commodity Price Risk — Commodity price risk results 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 September 30, 2015, based on price source and the period during which the instruments will mature, are summarized in the table below (in millions):



Fair Value Source	2015		2016-2017		2018-2019			After 2019		Total
Prices actively quoted	$	52	$	57	$	(2	)	$	—	$	107
Prices provided by other external sources	24		3		1			—		28
Prices based on models and other valuation methods	8		57		65			155		285
Total fair value	$	84	$	117	$	64		$	155	$	420

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 and nine months ended September 30, 2015 and 2014 (in millions):



	2015		2014
Three months ended September 30:
High	$	42	$	44
Low	$	19	$	28
Average	$	30	$	38
Nine months ended September 30:
High	$	42	$	52
Low	$	17	$	28
Average	$	26	$	40
As of September 30	$	32	$	28

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.

Since the fourth quarter of 2012, we have experienced diminished liquidity in the forward commodity markets resulting from a decrease in participation of counterparties in the marketplace with which to transact our hedging activities. Although this occurrence of diminished liquidity has not had a material adverse impact on our results of operations or financial condition, should these conditions persist, it could decrease our ability to hedge our forward commodity price risk and create incremental volatility in our earnings.

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 customers relating to our sales of power and steam and our hedging and optimization activities. We believe that our credit policies and practices adequately monitor our credit risk, and currently our counterparties are performing according to their respective agreements. We monitor and manage our total comprehensive credit risk associated with all of our contracts and PPAs 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 September 30, 2015, 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 September 30, 2015)	2015		2016-2017			2018-2019		After 2019		Total
Investment grade	$	80	$	108		$	52	$	135	$	375
Non-investment grade	1		(2		)	—		—		(1		)
No external ratings	3		11			12		20		46
Total fair value	$	84	$	117		$	64	$	155	$	420

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 $(5) million at September 30, 2015.

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 2014 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 third quarter of 2015, 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 factors, in addition to the risk factors previously disclosed in Part I, Item 1A “Risk Factors” of our 2014 Form 10-K:

Our ability to enter into hedging agreements and manage our counterparty credit risk could adversely affect us.

Our wholesale and retail customer and supplier counterparties may experience deteriorating credit. These conditions could cause counterparties in the natural gas and power markets, particularly in the energy commodity derivative markets that we rely on for our hedging activities, to withdraw from participation in those markets. If multiple parties withdraw from those markets, market liquidity may be threatened, which in turn could adversely impact our business and create more volatility in our earnings. Additionally, these conditions may cause our counterparties to seek bankruptcy protection under Chapter 11 or liquidation under Chapter 7 of the U.S. Bankruptcy Code. Our credit risk may be exacerbated to the extent collateral held by us cannot be realized or is liquidated at prices not sufficient to recover the full amount of the exposure due to us. There can be no assurance that any such losses or impairments to the carrying value of our financial assets would not materially and adversely affect our financial condition, results of operations and cash flows.

Significant events beyond our control, such as natural disasters, including weather-related events, or acts of terrorism, could damage our power plants or our corporate offices or cause a loss of system load and may impact us in unpredictable ways.

Certain of our geothermal and natural gas-fired power plants, particularly in the West, are subject to frequent low-level seismic disturbances and a persistent risk of wildfires. More significant seismic disturbances are possible. In addition, other areas in which we operate, particularly in Texas and the Southeast, experience tornados and hurricanes. Operations at our corporate offices in Houston, Texas could be substantially affected by a hurricane. Any significant loss of system load resulting from a weather-related event could negatively impact our wholesale and retail operations. Such events could damage or shut down our power plants, power transmission or the fuel supply facilities upon which our wholesale and retail business is dependent. Our existing power plants are built to withstand relatively significant levels of seismic and other disturbances, and we believe we maintain adequate insurance protection. However, earthquake, property damage or business interruption insurance may be inadequate to cover all potential losses sustained in the event of serious damages to our power plants or disruptions to our wholesale and retail operations due to natural disasters.

In addition to physical damage to our power plants, the risk of future terrorist activity could result in adverse changes in the insurance markets and disruptions in the power and fuel markets. These events could also adversely affect the U.S. economy, create instability in the financial markets and, as a result, have an adverse effect on our ability to access capital on terms and conditions acceptable to us.

We depend on computer and telecommunications systems we do not own or control and failures in our systems or cyber security attacks could significantly disrupt our business operations or result in sensitive customer information being compromised which would negatively materially impact our reputation and/or results of operations.

We have entered into agreements with third parties for hardware, software, telecommunications and other information technology services in connection with the operation of our power plants. In addition, we have developed proprietary software systems, management techniques and other information technologies incorporating software licensed from third parties. We also rely on software systems owned and operated by third parties, such as ISOs and RTOs, to be functioning in order to be able to transmit the electricity produced by our power plants to our customers. It is possible we or a third party that we rely on could incur interruptions from a loss of communications, hardware or software failures, cyber security attacks, computer viruses or malware. We believe that we have positive relations with our vendors and maintain adequate anti-virus and malware software and controls; however, any interruptions to our arrangements with third parties, to our computing and communications infrastructure, or to our information systems or any of those operated by a third party that we rely on could significantly disrupt our business operations.

Additionally, our retail business requires access to sensitive customer information in the ordinary course of business. If a significant data breach occurred, the reputation of our retail business may be adversely affected, customer confidence may be

diminished, or our retail business may be subject to legal claims, any of which may contribute to the loss of customers and have a material adverse impact on our retail business and our results of operations.


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⁾
July	1,455,344	$	18.33	1,119,070	$	361
August	965,037	$	16.66	911,065	$	346
September	1,275,668	$	15.55	1,275,046	$	326
Total	3,696,049	$	16.94	3,305,181	$	326

___________


(1)	To satisfy tax withholding obligations associated with the vesting of restricted stock awarded to employees and with net share employee stock option exercises under the Equity Plan, during the third quarter of 2015, we withheld a total of 3,443 shares and 387,425 shares, respectively, 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		Separation Agreement between Calpine Corporation and John Adams, dated August 4, 2015.

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

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

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

101.INS		XBRL Instance Document.

101.SCH		XBRL Taxonomy Extension Schema.

101.CAL		XBRL Taxonomy Extension Calculation Linkbase.

101.DEF		XBRL Taxonomy Extension Definition Linkbase.

101.LAB		XBRL Taxonomy Extension Label Linkbase.

101.PRE		XBRL Taxonomy Extension Presentation Linkbase.

_______________


*	Furnished herewith.

SIGNATURES

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



CALPINE CORPORATION
(Registrant)

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

Date: October 29, 2015

EXHIBIT INDEX



Exhibit Number		Description

10.1		Separation Agreement between Calpine Corporation and John Adams, dated August 4, 2015.

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.

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