CALPINE CORP - FORM 10-Q

Attached files

file	filename
EX-32.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER - CALPINE CORP	cpn_exhibit321x06302014.htm
EX-31.2 - SECTION 302 CERTIFICATION OF CHIEF FINANCIAL OFFICER - CALPINE CORP	cpn_exhibit312x06302014.htm
EX-31.1 - SECTION 302 CERTIFICATION OF CHIEF EXECUTIVE OFFICER - CALPINE CORP	cpn_exhibit311x06302014.htm
EXCEL - IDEA: XBRL DOCUMENT - CALPINE CORP	Financial_Report.xls

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

____________________

Form 10-Q

(Mark One)



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

For the quarterly period ended June 30, 2014

		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: 402,545,769 shares of common stock, par value $0.001, were outstanding as of July 30, 2014.

CALPINE CORPORATION AND SUBSIDIARIES

REPORT ON FORM 10-Q

For the Quarter Ended June 30, 2014

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 Six Months Ended June 30, 2014 and 2013	1
Consolidated Condensed Statements of Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2014 and 2013	2
Consolidated Condensed Balance Sheets at June 30, 2014 and December 31, 2013	3
Consolidated Condensed Statements of Cash Flows for the Six Months Ended June 30, 2014 and 2013	4
Notes to Consolidated Condensed Financial Statements	6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Forward-Looking Information	30
Introduction and Overview	30
Results of Operations	34
Commodity Margin and Adjusted EBITDA	38
Liquidity and Capital Resources	46
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	57
Item 3. Defaults Upon Senior Securities	57
Item 4. Mine Safety Disclosures	57
Item 5. Other Information	57
Item 6. Exhibits	58
Signatures	59

DEFINITIONS

As used in this report for the quarter ended June 30, 2014 (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
2013 Form 10-K		Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2013, filed with the SEC on February 13, 2014

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 Notes		The $400 million aggregate principal amount of 8.0% senior secured notes due 2019, issued May 25, 2010

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

2020 First Lien Notes		The $1.1 billion aggregate principal amount of 7.875% senior secured notes due 2020, issued July 23, 2010

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

2021 First Lien Notes		The $2.0 billion aggregate principal amount of 7.50% senior secured notes due 2021, issued October 22, 2010

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

2023 First Lien Notes		The $1.2 billion aggregate principal amount of 7.875% senior secured notes due 2023, issued January 14, 2011

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

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 or extinguishment of debt, (k) non-cash GAAP-related adjustments to levelize revenues from tolling contracts 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

CAA		Federal Clean Air Act, U.S. Code Title 42, Chapter 85

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

CARB		California Air Resources Board

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

CCFC Notes		The $1.0 billion aggregate principal amount of 8.0% senior secured notes due 2016, issued May 19, 2009

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

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 including natural gas transactions hedging future power sales, but excludes our mark-to-market activity and other revenues

iii



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

Company		Calpine Corporation, a Delaware corporation, and its subsidiaries

Corporate Revolving Facility		The $1.5 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

Dodd-Frank Act		The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010

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 2019 First Lien Notes, the 2020 First Lien Notes, the 2021 First Lien Notes, 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 and the 2020 First Lien Term Loan

GE		General Electric International, Inc.

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)

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



ABBREVIATION		DEFINITION
MMBtu		Million Btu

MW		Megawatt(s), a measure of plant capacity

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

NOL(s)		Net operating loss(es)

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 that defines the risk management framework and corporate governance structure for commodity risk, interest rate risk, currency risk and other risks

RTO(s)		Regional Transmission Organization(s)

SEC		U.S. Securities and Exchange Commission

Securities Act		U.S. Securities Act of 1933, as amended

Senior Unsecured Notes		Collectively, the 2023 Senior Unsecured Notes and the 2025 Senior Unsecured Notes

Spark Spread(s)		The difference between the sales price of power per MWh and the cost of fuel 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 that operates Whitby, a 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada

Forward-Looking Statements

In addition to historical information, 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 to hedge risks;


•	Laws, regulation 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 and to comply with covenants under our First Lien Notes, Senior Unsecured Notes, Corporate Revolving Facility, First Lien Term Loans, 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;


•	The unknown future impact on our business from the Dodd-Frank Act and the rules to be promulgated thereunder;


•	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;


•	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 and floods, acts of terrorism or cyber attacks that may impact our power plants or the markets our power plants 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; and


•	Other risks identified in this Report and in our 2013 Form 10-K.

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 at 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 June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(in millions, except share and per share amounts)
Operating revenues:
Commodity revenue	$	1,766		$	1,539		$	3,814		$	2,847
Mark-to-market gain (loss)	169			31			83			(40		)
Other revenue	4			2			7			6
Operating revenues	1,939			1,572			3,904			2,813
Operating expenses:
Fuel and purchased energy expense:
Commodity expense	1,106			998			2,476			1,833
Mark-to-market (gain) loss	28			2			15			(12		)
Fuel and purchased energy expense	1,134			1,000			2,491			1,821
Plant operating expense	274			257			539			484
Depreciation and amortization expense	147			145			300			291
Sales, general and other administrative expense	38			36			71			69
Other operating expenses	21			20			43			38
Total operating expenses	1,614			1,458			3,444			2,703
(Income) from unconsolidated investments in power plants	(4		)	(8		)	(13		)	(16		)
Income from operations	329			122			473			126
Interest expense	169			170			335			346
Interest (income)	(2		)	(1		)	(3		)	(3		)
Debt extinguishment costs	—			68			1			68
Other (income) expense, net	6			3			16			8
Income (loss) before income taxes	156			(118		)	124			(293		)
Income tax expense (benefit)	15			(48		)	(4		)	(98		)
Net income (loss)	141			(70		)	128			(195		)
Net income attributable to the noncontrolling interest	(2		)	—			(6		)	—
Net income (loss) attributable to Calpine	$	139		$	(70	)	$	122		$	(195	)

Basic earnings (loss) per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands)	416,507			447,558			418,296			449,620
Net income (loss) per common share attributable to Calpine — basic	$	0.33		$	(0.16	)	$	0.29		$	(0.43	)

Diluted earnings (loss) per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands)	421,348			447,558			422,697			449,620
Net income (loss) per common share attributable to Calpine — diluted	$	0.33		$	(0.16	)	$	0.29		$	(0.43	)

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

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(in millions)
Net income (loss)	$	141		$	(70	)	$	128		$	(195	)
Cash flow hedging activities:
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income (loss)	(22		)	38			(35		)	42
Reclassification adjustment for loss on cash flow hedges realized in net income (loss)	13			10			26			19
Foreign currency translation gain (loss)	6			(5		)	—			(7		)
Income tax benefit	—			2			—			3
Other comprehensive income (loss)	(3		)	45			(9		)	57
Comprehensive income (loss)	138			(25		)	119			(138		)
Comprehensive (income) attributable to the noncontrolling interest	(1		)	(4		)	(5		)	(5		)
Comprehensive income (loss) attributable to Calpine	$	137		$	(29	)	$	114		$	(143	)

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

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited)



	June 30,			December 31,
	2014			2013
	(in millions, except share and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents ($136 and $242 attributable to VIEs)	$	442		$	941
Accounts receivable, net of allowance of $7 and $5	762			552
Inventories	374			364
Margin deposits and other prepaid expense	303			309
Restricted cash, current ($122 and $100 attributable to VIEs)	191			203
Derivative assets, current	746			445
Current assets held for sale	808			—
Other current assets	76			42
Total current assets	3,702			2,856
Property, plant and equipment, net ($4,542 and $4,191 attributable to VIEs)	12,844			12,995
Restricted cash, net of current portion ($66 and $68 attributable to VIEs)	66			69
Investments in power plants	92			93
Long-term derivative assets	236			105
Other assets ($196 and $195 attributable to VIEs)	430			441
Total assets	$	17,370		$	16,559
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	614		$	462
Accrued interest payable	189			162
Debt, current portion ($134 and $140 attributable to VIEs)	189			204
Derivative liabilities, current	706			451
Current liabilities held for sale	9			—
Other current liabilities	439			252
Total current liabilities	2,146			1,531
Debt, net of current portion ($3,303 and $2,923 attributable to VIEs)	11,260			10,908
Long-term derivative liabilities	248			243
Other long-term liabilities	302			309
Total liabilities	13,956			12,991

Commitments and contingencies (see Note 12)
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, 500,563,630 and 497,841,056 shares issued, respectively, and 417,133,226 and 429,038,988 shares outstanding, respectively	1			1
Treasury stock, at cost, 83,430,404 and 68,802,068 shares, respectively	(1,535		)	(1,230		)
Additional paid-in capital	12,421			12,389
Accumulated deficit	(7,364		)	(7,486		)
Accumulated other comprehensive loss	(168		)	(160		)
Total Calpine stockholders’ equity	3,355			3,514
Noncontrolling interest	59			54
Total stockholders’ equity	3,414			3,568
Total liabilities and stockholders’ equity	$	17,370		$	16,559

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

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended June 30,
	2014			2013
	(in millions)
Cash flows from operating activities:
Net income (loss)	$	128		$	(195	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization expense⁽¹⁾	322			315
Debt extinguishment costs	1			28
Deferred income taxes	(12		)	(15		)
Mark-to-market activity, net	(70		)	24
(Income) from unconsolidated investments in power plants	(13		)	(16		)
Return on unconsolidated investments in power plants	13			16
Stock-based compensation expense	22			20
Other	1			—
Change in operating assets and liabilities:
Accounts receivable	(212		)	(285		)
Derivative instruments, net	(109		)	1
Other assets	(40		)	(182		)
Accounts payable and accrued expenses	378			67
Other liabilities	(60		)	47
Net cash provided by (used in) operating activities	349			(175		)
Cash flows from investing activities:
Purchases of property, plant and equipment	(258		)	(335		)
Purchase of Guadalupe Energy Center, net of cash	(656		)	—
Decrease in restricted cash	14			55
Other	—			(1		)
Net cash used in investing activities	(900		)	(281		)
Cash flows from financing activities:
Borrowings under CCFC Term Loans	420			1,197
Repayment of CCFC Term Loans, CCFC Notes and First Lien Term Loans	(23		)	(1,012		)
Borrowings from project financing, notes payable and other	2			116
Repayments of project financing, notes payable and other	(55		)	(43		)
Financing costs	(10		)	(27		)
Stock repurchases	(297		)	(362		)
Proceeds from exercises of stock options	15			17
Other	—			1
Net cash provided by (used in) financing activities	52			(113		)
Net decrease in cash and cash equivalents	(499		)	(569		)
Cash and cash equivalents, beginning of period	941			1,284
Cash and cash equivalents, end of period	$	442		$	715

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

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS — (CONTINUED)

(Unaudited)



	Six Months Ended June 30,
	2014		2013
	(in millions)
Cash paid during the period for:
Interest, net of amounts capitalized	$	288	$	334
Income taxes	$	16	$	21

Supplemental disclosure of non-cash investing activities:
Change in capital expenditures included in accounts payable	$	13	$	17

____________


(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

June 30, 2014

(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, Texas and the Mid-Atlantic region 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 and power 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, 2013, included in our 2013 Form 10-K. The results for interim periods are not necessarily 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.

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

Cash and Cash Equivalents — We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have 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. At June 30, 2014 and December 31, 2013, we had cash and cash equivalents of $156 million and $292 million, respectively, that were subject to such project finance facilities and lease agreements.

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 can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Condensed Balance Sheets and Statements of Cash Flows.

The table below represents the components of our restricted cash as of June 30, 2014 and December 31, 2013 (in millions):



	June 30, 2014						December 31, 2013
	Current		Non-Current		Total		Current		Non-Current		Total
Debt service	$	13	$	41	$	54	$	11	$	41	$	52
Rent reserve	4		—		4		3		—		3
Construction/major maintenance	35		20		55		35		20		55
Security/project/insurance	139		3		142		151		6		157
Other	—		2		2		3		2		5
Total	$	191	$	66	$	257	$	203	$	69	$	272

Property, Plant and Equipment, Net — See Note 2 for a discussion of the sale of six power plants in our Southeast segment and the amount of property, plant and equipment, net that was reclassified to current assets held for sale on our Consolidated Condensed Balance Sheet at June 30, 2014. At June 30, 2014 and December 31, 2013, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):



	June 30, 2014		December 31, 2013		Depreciable Lives
Buildings, machinery and equipment	$	15,613	$	15,838	3 – 47 Years
Geothermal properties	1,271		1,265		13 – 59 Years
Other	172		164		3 – 47 Years
	17,056		17,267
Less: Accumulated depreciation	4,704		4,897
	12,352		12,370
Land	109		103
Construction in progress	383		522
Property, plant and equipment, net	$	12,844	$	12,995

Capitalized Interest — The total amount of interest capitalized was $6 million and $12 million for the three months ended June 30, 2014 and 2013, respectively, and $12 million and $24 million for the six months ended June 30, 2014 and 2013, respectively.

Treasury Stock — During the six months ended June 30, 2014, we repurchased common stock with a value of $297 million and withheld shares with a value of $8 million to satisfy tax withholding obligations associated with the vesting of restricted stock awarded to employees and net share employee stock option exercises under the Equity Plan.

New Accounting Standards and Disclosure Requirements

Income Taxes — In July 2013, the FASB issued Accounting Standards Update 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists”. The provisions of the standard require an unrecognized tax benefit to be presented as a reduction to a deferred tax asset in the financial statements for an NOL carryforward, a similar tax loss, or a tax credit carryforward except in circumstances when the carryforward or tax loss is not available at the reporting date under the tax laws of the applicable jurisdiction to settle any additional income taxes or the tax law does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purposes. When those circumstances exist, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. The new financial statement presentation provisions relating to this standard are prospective and effective for interim and annual periods beginning after December 15, 2013, with early adoption permitted. We adopted Accounting Standards Update 2013-11 in the first quarter of 2014 which did not have a material impact on our financial condition, results of operations or cash flows.

Financial Reporting of Discontinued Operations — In April 2014, the FASB issued Accounting Standards Update 2014-08, “Presentation of Financial Statements and Property, Plant, and Equipment”. The update limits discontinued operations reporting to disposals that represent a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. The standard also requires new disclosures related to components reported as discontinued operations, as well as components of an entity that were sold and do not meet the criteria for discontinued operations reporting. The new financial statement presentation provisions relating to this standard are prospective and effective for interim and annual periods beginning after December 15, 2014,

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.

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 creates a five-step model for revenue recognition that requires companies to exercise judgment when considering contract terms and relevant facts and circumstances. The five-step model includes (1) identifying the contract, (2) identifying the separate performance obligations in the contract, (3) determining the transaction price, (4) allocating the transaction price to the separate performance obligations and (5) recognizing revenue when each performance obligation has been satisfied. The standard also requires expanded disclosures surrounding revenue recognition. The standard is effective for fiscal periods beginning after December 15, 2016, including interim periods within that reporting period and allows for either full retrospective or modified retrospective adoption with early adoption being prohibited. We are currently assessing the future impact this standard may have on our financial condition, results of operations or cash flows.


2.	Acquisition and Divestitures

Acquisition of Guadalupe Energy Center

On February 26, 2014, we, through our indirect, wholly-owned subsidiary Calpine Guadalupe GP, LLC, completed the purchase of a power plant owned by MinnTex Power Holdings, LLC with a capacity of 1,000 MW, for approximately $625 million, excluding working capital adjustments. The addition of this modern, natural gas-fired, combined-cycle power plant increased capacity in our Texas segment which is one of our core markets. The 110-acre site, located in Guadalupe County, Texas, which is northeast of San Antonio, Texas, includes two 525 MW generation blocks, each consisting of two GE 7FA combustion turbines, two heat recovery steam generators and one GE steam turbine. We also paid $15 million to acquire rights to an advanced development opportunity for an approximately 400 MW quick-start, natural gas-fired peaker. We funded the acquisition with $425 million in incremental CCFC Term Loans and cash on hand. See Note 4 for a further description of the incremental CCFC Term Loans. The purchase price was primarily allocated to property, plant and equipment. Although the purchase price allocation has not been finalized, we do not expect to record any material adjustments to the preliminary purchase price allocation nor do we expect to recognize any goodwill as a result of this acquisition. The pro forma incremental impact of Guadalupe Energy Center on our results of operations for each of the three months and six months ended June 30, 2014 and 2013 is not material.

Sale of Six Southeast Power Plants

On July 3, 2014, we completed the sale of six of our power plants in the Southeast segment to NatGen Southeast Power LLC, a wholly-owned subsidiary of LS Power Equity Partners III. The purchase and sale agreement, dated April 17, 2014, stipulates the sale of 100% of the limited liability company interests in (i) Mobile Energy LLC, (ii) Santa Rosa Energy Center, LLC, (iii) Carville Energy, LLC, (iv) Decatur Energy Center, LLC, (v) Columbia Energy LLC and (vi) Calpine Oneta Power, LLC and thereby sell assets comprising 3,498 MW of combined-cycle generation capacity in Oklahoma, Louisiana, Alabama, Florida and South Carolina for a sale price of approximately $1.57 billion in cash, plus an additional approximately $4 million for working capital and other adjustments at closing. In accordance with the purchase and sale agreement, we may also be required to make up to $16 million in future cash payments for certain planned maintenance events. The divestiture of these power plants has better aligned our asset base with our strategic focus on competitive wholesale markets.

We expect to record a gain on sale of assets, net of approximately $750 million during the third quarter of 2014 and intend to use existing federal and state NOLs to almost entirely offset the projected taxable gains from the sale. The sale of the six power plants did not meet the criteria for treatment as discontinued operations.

The six power plants included in the transaction are as follows:



Plant Name	Plant Capacity		Location
Oneta Energy Center	1,134	MW	Coweta, OK
Carville Energy Center⁽¹⁾	501	MW	St. Gabriel, LA
Decatur Energy Center	795	MW	Decatur, AL
Hog Bayou Energy Center	237	MW	Mobile, AL
Santa Rosa Energy Center	225	MW	Pace, FL
Columbia Energy Center⁽¹⁾	606	MW	Calhoun County, SC
Total	3,498	MW

___________


(1)	Indicates combined-cycle cogeneration power plant.

The assets and liabilities of the six power plants are reported as assets and liabilities held for sale on our Consolidated Condensed Balance Sheet at June 30, 2014. The table below presents the components of assets and liabilities held for sale at June 30, 2014 (in millions):



	June 30, 2014
Assets:
Current assets	$	26
Property, plant and equipment, net	769
Other long-term assets	13
Total current assets held for sale	$	808
Liabilities:
Total current liabilities held for sale	$	9


3.	Variable Interest Entities and Unconsolidated Investments in Power Plants

We consolidate all of our VIEs where we have determined that we are the primary beneficiary. There were no changes to our determination of whether we are the primary beneficiary of our VIEs for the six months ended June 30, 2014. See Note 5 in our 2013 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 10,365 MW and 9,427 MW at June 30, 2014 and December 31, 2013, respectively. For these VIEs, we may provide other operational and administrative support through various affiliate contractual arrangements among the VIEs, Calpine Corporation and its other wholly-owned subsidiaries whereby we support the VIE through the reimbursement of costs and/or the purchase and sale of energy. Other than amounts contractually required, we provided support to these VIEs in the form of cash and other contributions of nil and $40 million during the three and six months ended June 30, 2014 and nil during each of the three and six months ended June 30, 2013.

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 June 30, 2014 and December 31, 2013, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):



	Ownership Interest as of June 30, 2014	June 30, 2014		December 31, 2013
Greenfield LP	50%	$	80	$	76
Whitby	50%	12		17
Total investments in power plants		$	92	$	93

Our risk of loss related to our unconsolidated VIEs is limited to our investment balance. Holders of the debt of our unconsolidated investments do not have recourse to Calpine Corporation and its other subsidiaries; therefore, the debt of our unconsolidated investments is not reflected on our Consolidated Condensed Balance Sheets. At June 30, 2014 and December 31, 2013, equity method investee debt was approximately $385 million and $395 million, respectively, and based on our pro rata share of each of the investments, our share of such debt would be approximately $193 million and $198 million at June 30, 2014 and December 31, 2013, respectively.

Our equity interest in the net income from Greenfield LP and Whitby for the three and six months ended June 30, 2014 and 2013, 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 June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Greenfield LP	$	—		$	(5	)	$	(5	)	$	(9	)
Whitby	(4		)	(3		)	(8		)	(7		)
Total	$	(4	)	$	(8	)	$	(13	)	$	(16	)

Distributions from Greenfield LP were nil during each of the three and six months ended June 30, 2014 and $7 million during each of the three and six months ended June 30, 2013. Distributions from Whitby were nil and $13 million during the three and six months ended June 30, 2014 and $9 million during each of the three and six months ended June 30, 2013.

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

At June 30, 2014 and December 31, 2013, our debt was as follows (in millions):



	June 30, 2014		December 31, 2013
First Lien Notes	$	4,990	$	4,989
First Lien Term Loans	2,814		2,828
Project financing, notes payable and other	1,849		1,901
CCFC Term Loans	1,603		1,191
Capital lease obligations	193		203
Subtotal	11,449		11,112
Less: Current maturities	189		204
Total long-term debt	$	11,260	$	10,908

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 6.1% for the six months ended June 30, 2014, from 6.9% for the six months ended June 30, 2013. The issuance of our CCFC Term Loans, 2022 First Lien Notes, 2024 First Lien Notes and 2020 First Lien Term Loan in 2013 allowed us to reduce our overall cost of debt by replacing our CCFC Notes and a portion of our First Lien Notes with debt carrying lower interest rates.

First Lien Notes

Our First Lien Notes are summarized in the table below (in millions):



	June 30, 2014		December 31, 2013
2019 First Lien Notes⁽¹⁾	$	320	$	320
2020 First Lien Notes⁽²⁾	875		875
2021 First Lien Notes⁽²⁾	1,600		1,600
2022 First Lien Notes	745		744
2023 First Lien Notes	960		960
2024 First Lien Notes	490		490
Total First Lien Notes	$	4,990	$	4,989

____________


(1)	The 2019 First Lien Notes were repaid on July 22, 2014 with a portion of the proceeds from the issuance of our Senior Unsecured Notes which are described in further detail below.

(2)

On July 8, 2014, we launched tender offers and consent solicitations to repurchase our 2020 First Lien Notes and 2021 First Lien Notes with the proceeds from our Senior Unsecured Notes which are described in further detail below. On July 22, 2014, we repurchased approximately $861 million in aggregate principal amount of our 2020 First Lien Notes and approximately $1,582 million in aggregate principal amount of our 2021 First Lien Notes. We used the remaining net proceeds, together with cash on hand, to satisfy and discharge the remaining 2020 First Lien Notes and 2021 First Lien Notes.

Senior Unsecured Notes

On July 22, 2014, we issued $1.25 billion in aggregate principal amount of 5.375% senior unsecured notes due 2023 and $1.55 billion in aggregate principal amount of 5.75% senior unsecured notes due 2025 in a public offering. The 2023 Senior Unsecured Notes bear interest at 5.375% per annum and the 2025 Senior Unsecured Notes bear interest at 5.75% per annum, in each case payable semi-annually on April 15 and October 15 of each year, beginning on April 15, 2015. The 2023 Senior Unsecured Notes mature on January 15, 2023 and the 2025 Senior Unsecured Notes mature on January 15, 2025. Our Senior Unsecured Notes were issued at par.

Our Senior Unsecured Notes are:


•	general unsecured obligations of Calpine;


•	rank equally in right of payment with all of Calpine’s existing and future senior indebtedness;


•	effectively subordinated to Calpine’s secured indebtedness to the extent of the value of the collateral securing such indebtedness;


•	structurally subordinated to any existing and future indebtedness and other liabilities of Calpine’s subsidiaries; and


•	senior in right of payment to any of Calpine’s subordinated indebtedness.

We used the net proceeds received from the issuance of our 2023 Senior Unsecured Notes and 2025 Senior Unsecured Notes, together with cash on hand, to repurchase our outstanding 2019 First Lien Notes and to repurchase approximately $861 million in aggregate principal amount of our 2020 First Lien Notes and approximately $1,582 million in aggregate principal amount of our 2021 First Lien Notes on July 22, 2014. We used the remaining net proceeds, together with cash on hand, to satisfy and discharge the remaining 2020 First Lien Notes and 2021 First Lien Notes. We expect to record approximately $40 million in deferred financing costs and approximately $340 million in debt extinguishment costs during the third quarter of 2014 related to the repayment of our 2019 First Lien Notes, 2020 First Lien Notes and 2021 First Lien Notes.

First Lien Term Loans

Our First Lien Term Loans are summarized in the table below (in millions):



	June 30, 2014		December 31, 2013
2018 First Lien Term Loans	$	1,606	$	1,614
2019 First Lien Term Loan	820		824
2020 First Lien Term Loan	388		390
Total First Lien Term Loans	$	2,814	$	2,828

CCFC Term Loans

In February 2014, we executed an amendment to the credit agreement associated with the CCFC Term Loans, which allowed us to issue $425 million in incremental CCFC Term Loans to fund a portion of the purchase price paid in connection with the closing of our acquisition of Guadalupe Energy Center on February 26, 2014. Guadalupe Energy Center was purchased by Calpine Guadalupe GP, LLC, a wholly-owned subsidiary of CCFC. The incremental term loans carry substantially the same terms and conditions as the $300 million in aggregate principal amount of CCFC Term Loans issued in June 2013. The incremental term loans were offered to investors at an issue price equal to 98.75% of face value.

Corporate Revolving Facility and Other Letters of Credit Facilities

The table below represents amounts issued under our letter of credit facilities at June 30, 2014 and December 31, 2013 (in millions):



	June 30, 2014		December 31, 2013
Corporate Revolving Facility⁽¹⁾	$	235	$	242
CDHI⁽²⁾	269		218
Various project financing facilities	171		170
Total	$	675	$	630

____________


(1)	The Corporate Revolving Facility represents our primary revolving facility. On July 30, 2014, we amended our Corporate Revolving Facility to increase the capacity by an additional $500 million to $1.5 billion.


(2)	During the first quarter of 2014, we amended our CDHI letter of credit facility to lower our fees and extend the maturity to January 2, 2018.

Fair Value of Debt

We record our debt instruments based on contractual terms, net of any applicable premium or discount. We did not elect to apply the alternative U.S. GAAP provisions of the fair value option for recording financial assets and financial liabilities. The following table details the fair values and carrying values of our debt instruments at June 30, 2014 and December 31, 2013 (in millions):



	June 30, 2014				December 31, 2013
	Fair Value		Carrying Value		Fair Value		Carrying Value
First Lien Notes	$	5,441	$	4,990	$	5,317	$	4,989
First Lien Term Loans	2,822		2,814		2,845		2,828
Project financing, notes payable and other⁽¹⁾	1,736		1,728		1,772		1,766
CCFC Term Loans	1,586		1,603		1,179		1,191
Total	$	11,585	$	11,135	$	11,113	$	10,774

____________


(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 First Lien Notes, First Lien Term Loans 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 or 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 June 30, 2014 and December 31, 2013, by level within the fair value hierarchy:



	Assets and Liabilities with Recurring Fair Value Measures as of June 30, 2014
	Level 1		Level 2		Level 3		Total
	(in millions)
Assets:
Cash equivalents⁽¹⁾	$	636	$	—	$	—	$	636
Margin deposits	239		—		—		239
Commodity instruments:
Commodity exchange traded futures and swaps contracts	681		—		—		681
Commodity forward contracts⁽²⁾	—		256		40		296
Interest rate swaps	—		5		—		5
Total assets	$	1,556	$	261	$	40	$	1,857
Liabilities:
Margin deposits posted with us by our counterparties	$	184	$	—	$	—	$	184
Commodity instruments:
Commodity exchange traded futures and swaps contracts	640		—		—		640
Commodity forward contracts⁽²⁾	—		135		49		184
Interest rate swaps	—		130		—		130
Total liabilities	$	824	$	265	$	49	$	1,138



	Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2013
	Level 1		Level 2		Level 3		Total
	(in millions)
Assets:
Cash equivalents⁽¹⁾	$	1,134	$	—	$	—	$	1,134
Margin deposits	261		—		—		261
Commodity instruments:
Commodity exchange traded futures and swaps contracts	434		—		—		434
Commodity forward contracts⁽²⁾	—		75		32		107
Interest rate swaps	—		9		—		9
Total assets	$	1,829	$	84	$	32	$	1,945
Liabilities:
Margin deposits posted with us by our counterparties	$	5	$	—	$	—	$	5
Commodity instruments:
Commodity exchange traded futures and swaps contracts	495		—		—		495
Commodity forward contracts⁽²⁾	—		52		18		70
Interest rate swaps	—		129		—		129
Total liabilities	$	500	$	181	$	18	$	699

___________


(1)	As of June 30, 2014 and December 31, 2013, we had cash equivalents of $406 million and $889 million included in cash and cash equivalents and $230 million and $245 million included in restricted cash, respectively.


(2)	Includes OTC swaps and options.

At June 30, 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; however, given the nature of our net derivative position, we do not believe that a significant change in market commodity prices would have a material impact on our level 3 net fair value. The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at June 30, 2014 and December 31, 2013:



	Quantitative Information about Level 3 Fair Value Measurements
	June 30, 2014
	Fair Value, Net Asset				Significant Unobservable
	(Liability)			Valuation Technique	Input	Range
	(in millions)
Power Contracts	$	(22	)	Discounted cash flow	Market price (per MWh)	$21.41 — $169.45/MWh
Power Congestion Products	$	7		Discounted cash flow	Market price (per MWh)	$(24.07) — $77.80/MWh

	December 31, 2013
	Fair Value, Net Asset				Significant Unobservable
	(Liability)			Valuation Technique	Input	Range
	(in millions)
Power Contracts	$	7		Discounted cash flow	Market price (per MWh)	$28.92 — $53.15/MWh
Power Congestion Products	$	7		Discounted cash flow	Market price (per MWh)	$(8.79) — $11.53/MWh

The following table sets forth a reconciliation of changes in the fair value of our net derivative assets (liabilities) classified as level 3 in the fair value hierarchy for the periods indicated (in millions):



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Balance, beginning of period	$	8		$	13		$	14		$	16
Realized and mark-to-market gains (losses):
Included in net income (loss):
Included in operating revenues⁽¹⁾	(7		)	3			(15		)	4
Included in fuel and purchased energy expense⁽²⁾	—			—			6			—
Purchases, issuances and settlements:
Purchases	—			1			—			1
Issuances	—			—			—			(1		)
Settlements	(3		)	(3		)	(6		)	(5		)
Transfers in and/or out of level 3⁽³⁾:
Transfers into level 3⁽⁴⁾	2			—			—			—
Transfers out of level 3⁽⁵⁾	(9		)	(1		)	(8		)	(2		)
Balance, end of period	$	(9	)	$	13		$	(9	)	$	13
Change in unrealized gains (losses) relating to instruments still held at end of period	$	(7	)	$	3		$	(9	)	$	4

___________


(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 six months ended June 30, 2014 and 2013.


(4)	We had $2 million in gains transferred out of level 2 into level 3 for the three months ended June 30, 2014 due to changes in market liquidity in various power markets. There were no transfers out of level 2 into level 3 for the three months ended June 30, 2013 and for each of the six months ended June 30, 2014 and 2013.


(5)	We had $9 million and $1 million in gains transferred out of level 3 into level 2 for the three months ended June 30, 2014 and 2013, respectively, and $8 million and $2 million in gains transferred out of level 3 into level 2 for the six months ended June 30, 2014 and 2013, 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, as authorized by our Board of Directors and monitored by our Chief Risk Officer and Risk Management Committee of senior management, related to our commodity derivative portfolio which exposes us to certain market risks that are segregated from the market risks of our underlying asset portfolio. 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 six months ended June 30, 2014 and 2013.

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 June 30, 2014, the maximum length of time over which we were hedging using interest rate derivative instruments designated as cash flow hedges was 9 years.

As of June 30, 2014 and December 31, 2013, 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	June 30, 2014			December 31, 2013
Power (MWh)	(49		)	(29		)
Natural gas (MMBtu)	316			448
Environmental credits (Tonnes)	2			—
Interest rate swaps	$	1,510		$	1,527

Certain of our derivative instruments contain credit risk-related contingent provisions that require us to maintain collateral balances consistent with our credit ratings. If our credit rating were to be downgraded, it could require us to post additional collateral or could potentially allow our counterparty to request immediate, full settlement on certain derivative instruments in liability positions. Currently, we do not believe that it is probable that any additional collateral posted as a result of a one credit notch downgrade from its current level would be material. The aggregate fair value of our derivative liabilities with credit risk-related contingent provisions as of June 30, 2014, was $14 million for which we have posted collateral of $13 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 no additional collateral 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 fuel costs 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 report the effective portion of the mark-to-market gain or loss on a derivative instrument 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. During the three and six months ended June 30, 2014 and 2013, we did not have any commodity derivative instruments designated as cash flow hedges. 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 environmental product contracts and Heat Rate swaps and options) and fuel and purchased energy expense (for natural gas contracts, swaps and options). Changes in fair value of interest rate derivatives not designated as hedging instruments are recognized currently in earnings as interest expense.

Derivatives Included on Our Consolidated Condensed Balance Sheets

The following tables present the fair values of our derivative instruments recorded on our Consolidated Condensed Balance Sheets by location and hedge type at June 30, 2014 and December 31, 2013 (in millions):



	June 30, 2014
	Commodity Instruments		Interest Rate Swaps			Total Derivative Instruments
Balance Sheet Presentation
Current derivative assets	$	746	$	—		$	746
Long-term derivative assets	231		5			236
Total derivative assets	$	977	$	5		$	982

Current derivative liabilities	$	659	$	47		$	706
Long-term derivative liabilities	165		83			248
Total derivative liabilities	$	824	$	130		$	954
Net derivative asset (liabilities)	$	153	$	(125	)	$	28



	December 31, 2013
	Commodity Instruments			Interest Rate Swaps			Total Derivative Instruments
Balance Sheet Presentation
Current derivative assets	$	445		$	—		$	445
Long-term derivative assets	96			9			105
Total derivative assets	$	541		$	9		$	550

Current derivative liabilities	$	404		$	47		$	451
Long-term derivative liabilities	161			82			243
Total derivative liabilities	$	565		$	129		$	694
Net derivative asset (liabilities)	$	(24	)	$	(120	)	$	(144	)



	June 30, 2014				December 31, 2013
	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	$	5	$	119	$	9	$	115
Total derivatives designated as cash flow hedging instruments	$	5	$	119	$	9	$	115

Derivatives not designated as hedging instruments:
Commodity instruments	$	977	$	824	$	541	$	565
Interest rate swaps	—		11		—		14
Total derivatives not designated as hedging instruments	$	977	$	835	$	541	$	579
Total derivatives	$	982	$	954	$	550	$	694

We elected not to offset fair value amounts recognized as derivative instruments on our Consolidated Condensed Balance Sheets that are executed with the same counterparty under master netting arrangements or other contractual netting provisions negotiated with the counterparty. Our netting arrangements include a right to set off or net together purchases and sales of similar products in the margining or settlement process. In some instances, we have also negotiated cross commodity netting rights which allow for the net presentation of activity with a given counterparty regardless of product purchased or sold. We also post cash collateral in support of our derivative instruments which may also be subject to a master netting arrangement with the same counterparty. The tables below set forth our net exposure to derivative instruments after offsetting amounts subject to a master netting arrangement with the same counterparty at June 30, 2014 and December 31, 2013 (in millions):



	June 30, 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	$	681		$	(590	)	$	(91	)	$	—
Commodity forward contracts	296			(159		)	(42		)	95
Interest rate swaps	5			—			—			5
Total derivative assets	$	982		$	(749	)	$	(133	)	$	100
Derivative (liabilities):
Commodity exchange traded futures and swaps contracts	$	(640	)	$	590		$	50		$	—
Commodity forward contracts	(184		)	159			11			(14		)
Interest rate swaps	(130		)	—			—			(130		)
Total derivative (liabilities)	$	(954	)	$	749		$	61		$	(144	)
Net derivative assets (liabilities)	$	28		$	—		$	(72	)	$	(44	)



	December 31, 2013
	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	$	434		$	(420	)	$	(14	)	$	—
Commodity forward contracts	107			(60		)	—			47
Interest rate swaps	9			—			—			9
Total derivative assets	$	550		$	(480	)	$	(14	)	$	56
Derivative (liabilities):
Commodity exchange traded futures and swaps contracts	$	(495	)	$	420		$	75		$	—
Commodity forward contracts	(70		)	60			1			(9		)
Interest rate swaps	(129		)	—			—			(129		)
Total derivative (liabilities)	$	(694	)	$	480		$	76		$	(138	)
Net derivative assets (liabilities)	$	(144	)	$	—		$	62		$	(82	)

____________

(1)

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

Derivatives Included on Our Consolidated Condensed Statements of Operations

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

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014			2013
Realized gain (loss)⁽¹⁾
Commodity derivative instruments	$	18	$	5	$	(21	)	$	33
Total realized gain (loss)	$	18	$	5	$	(21	)	$	33

Mark-to-market gain (loss)⁽²⁾
Commodity derivative instruments	$	141	$	29	$	68		$	(28	)
Interest rate swaps	1		2		2			4
Total mark-to-market gain (loss)	$	142	$	31	$	70		$	(24	)
Total activity, net	$	160	$	36	$	49		$	9

___________


(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 June 30,				Six Months Ended June 30,
	2014		2013		2014			2013
Realized and mark-to-market gain (loss)
Derivatives contracts included in operating revenues	$	158	$	15	$	(79	)	$	(59	)
Derivatives contracts included in fuel and purchased energy expense	1		19		126			64
Interest rate swaps included in interest expense	1		2		2			4
Total activity, net	$	160	$	36	$	49		$	9

Derivatives Included in OCI and AOCI

We do not have any commodity derivative instruments that were designated as cash flow hedges during the three and six months ended June 30, 2014 and 2013. The following table details the effect of our net derivative instruments that qualified for hedge accounting treatment and are included in OCI and AOCI for the periods indicated (in millions):



	Three Months Ended June 30,					Three Months Ended June 30,
	Gain (Loss) Recognized in OCI (Effective Portion)					Gain (Loss) Reclassified from AOCI into Income (Effective Portion)⁽³⁾
	2014			2013		2014				2013			Affected Line Item on the Consolidated Condensed Statements of Operations
Interest rate swaps⁽¹⁾	$	(9	)	$	48	$	(13	)	⁽⁴⁾	$	(10	)	Interest expense
Total⁽²⁾	$	(9	)	$	48	$	(13	)		$	(10	)



	Six Months Ended June 30,					Six Months Ended June 30,
	Gain (Loss) Recognized in OCI (Effective Portion)					Gain (Loss) Reclassified from AOCI into Income (Effective Portion)⁽³⁾
	2014			2013		2014				2013			Affected Line Item on the Consolidated Condensed Statements of Operations
Interest rate swaps⁽¹⁾	$	(9	)	$	61	$	(26	)	⁽⁴⁾	$	(19	)	Interest expense
Total⁽²⁾	$	(9	)	$	61	$	(26	)		$	(19	)

____________


(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 six months ended June 30, 2014 and 2013.


(2)	We recorded an income tax benefit of nil for each of the three and six months ended June 30, 2014, and income tax benefit of $2 million and $3 million for the three and six months ended June 30, 2013, respectively, in AOCI related to our cash flow hedging activities.


(3)	Cumulative cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $156 million and $148 million at June 30, 2014 and December 31, 2013, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $12 million and $11 million at June 30, 2014 and December 31, 2013, respectively.


(4)	Includes a loss of $5 million and $10 million that was reclassified from AOCI to interest expense for the three and six months ended June 30, 2014, respectively, where the hedged transactions are no longer expected to occur.

We estimate that pre-tax net losses of $43 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 June 30, 2014 and December 31, 2013 (in millions):



	June 30, 2014		December 31, 2013
Margin deposits⁽¹⁾	$	239	$	261
Natural gas and power prepayments	31		28
Total margin deposits and natural gas and power prepayments with our counterparties⁽²⁾	$	270	$	289

Letters of credit issued	$	561	$	488
First priority liens under power and natural gas agreements	20		31
First priority liens under interest rate swap agreements	133		132
Total letters of credit and first priority liens with our counterparties	$	714	$	651

Margin deposits posted with us by our counterparties⁽¹⁾⁽³⁾	$	184	$	5
Letters of credit posted with us by our counterparties	140		2
Total margin deposits and letters of credit posted with us by our counterparties	$	324	$	7

___________

(1)

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


(2)	At June 30, 2014 and December 31, 2013, $256 million and $272 million, respectively, were included in margin deposits and other prepaid expense and $14 million and $17 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets.


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

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


8.	Income Taxes

Income Tax Expense (Benefit)

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Income tax expense (benefit)	$	15		$	(48	)	$	(4	)	$	(98	)
Effective tax rate	10		%	41		%	(3		)%	33		%

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. As a result, we generally do not record a provision for federal and state income taxes. For the three and six months ended June 30, 2014 and 2013, our income tax expense (benefit) is largely comprised of discrete tax items and estimated state and foreign income taxes in jurisdictions where we do not have NOLs. See Note 10 in our 2013 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. Due to significant NOLs, any adjustment of state returns or federal returns would likely result in a reduction of deferred tax assets rather than a cash payment of income taxes.

Canadian Tax Audits — In January 2013, we received an adjusted reassessment on one of two transfer pricing issues that we were disputing with the Canadian Revenue Authority (“CRA”). We proposed a settlement of the adjusted reassessment with the CRA and it has accepted our proposal. The adjustment to our transfer pricing increased taxable income and was offset by existing NOLs to which a valuation allowance had been applied and did not have a material impact on our Consolidated Condensed Financial Statements.

On January 28, 2014, we received a letter from the CRA which informed us that they did not agree with our transfer price on the second issue and proposed an increase to taxable income for tax years 2006 and 2007. On June 6, 2014, we proposed a settlement, and on June 14, 2014, the CRA accepted our proposal. The adjustment to our transfer price increased taxable income for one of our Canadian affiliates and was offset by existing NOLs to which a valuation allowance had been applied. As part of the settlement, we agreed to pay some interest and withholding taxes which did not have a material impact on our Consolidated Condensed Financial Statements.

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

Unrecognized Tax Benefits — At June 30, 2014, we had unrecognized tax benefits of $67 million. If recognized, $16 million of our unrecognized tax benefits could impact the annual effective tax rate and $51 million, related to deferred tax assets, could be offset against the recorded valuation allowance resulting in no impact on our effective tax rate. We also had accrued interest and penalties of $13 million for income tax matters at June 30, 2014. We recognize interest and penalties related to unrecognized tax benefits in income tax expense (benefit) on our Consolidated Condensed Statements of Operations. We believe it is reasonably possible that a decrease within the range of nil and $9 million in unrecognized tax benefits could occur within the next 12 months primarily related to foreign tax issues.


9.	Earnings (Loss) per Share

We include restricted stock units for which no future service is required as a condition to the delivery of the underlying common stock in our calculation of weighted average shares outstanding. As we incurred a net loss for each of the three and six months ended June 30, 2013, diluted loss per share for both periods are computed on the same basis as basic loss per share, as the inclusion of any other potential shares outstanding would be anti-dilutive. Reconciliations of the amounts used in the basic and diluted earnings (loss) per common share computations for the three and six months ended June 30, 2014 and 2013, are as follows (shares in thousands):



	Three Months Ended June 30,		Six Months Ended June 30,
	2014	2013	2014	2013
Diluted weighted average shares calculation:
Weighted average shares outstanding (basic)	416,507	447,558	418,296	449,620
Share-based awards	4,841	—	4,401	—
Weighted average shares outstanding (diluted)	421,348	447,558	422,697	449,620

We excluded the following items from diluted earnings (loss) per common share for the three and six months ended June 30, 2014 and 2013, because they were anti-dilutive (shares in thousands):



	Three Months Ended June 30,		Six Months Ended June 30,
	2014	2013	2014	2013
Share-based awards	2,854	10,002	5,066	9,741


10.	Stock-Based Compensation

Calpine Equity Incentive Plans

The Calpine Equity Incentive Plans provide for the issuance of equity awards to all non-union employees as well as the non-employee members of our Board of Directors. The equity awards may include incentive or non-qualified stock options, restricted stock, restricted stock units, stock appreciation rights, performance compensation awards and other share-based awards. The equity awards granted under the Calpine Equity Incentive Plans include both graded and cliff vesting awards which vest over periods between one and five years, contain contractual terms between approximately five and ten years and are subject to forfeiture provisions under certain circumstances, including termination of employment prior to vesting. At June 30, 2014, there were 567,000 and 40,533,000 shares of our common stock authorized for issuance to participants under the Director Plan and the Equity Plan, respectively. At June 30, 2014, 186,816 shares and 12,501,451 shares remain available for future issuance under the Director Plan and the Equity Plan, respectively.

Equity Classified Share-Based Awards

We use the Black-Scholes option-pricing model or the Monte Carlo simulation model, as appropriate, to estimate the fair value of our employee stock options on the grant date, which takes into account the exercise price and expected term of the stock option, the current price of the underlying stock and its expected volatility, expected dividends on the stock and the risk-free interest rate for the expected term of the stock option as of the grant date. For our restricted stock and restricted stock units, we use our closing stock price on the date of grant, or the last trading day preceding the grant date for restricted stock granted on non-trading days, as the fair value for measuring compensation expense. Stock-based compensation expense is recognized over the period in which the related employee services are rendered. The service period is generally presumed to begin on the grant date and end when the equity award is fully vested. We use the graded vesting attribution method to recognize fair value of the equity award over the service period. For example, the graded vesting attribution method views one three-year restricted stock grant with annual graded vesting as three separate sub-grants, each representing 33 1/3% of the total number of shares of restricted stock granted. The first sub-grant vests over one year, the second sub-grant vests over two years and the third sub-grant vests over three years. A three-year restricted stock grant with cliff vesting is viewed as one grant vesting over three years.

Stock-based compensation expense recognized for our equity classified share-based awards was $8 million and $11 million for the three months ended June 30, 2014 and 2013, and $17 million and $19 million for the six months ended June 30, 2014 and 2013, respectively. We did not record any significant tax benefits related to stock-based compensation expense in any period as we are not benefiting from a significant portion of our deferred tax assets, including deductions related to stock-based compensation expense. In addition, we did not capitalize any stock-based compensation expense as part of the cost of an asset for the six months ended June 30, 2014 and 2013. At June 30, 2014, there was unrecognized compensation cost of $1 million related to options, $41 million related to restricted stock and $1 million related to restricted stock units, which is expected to be recognized over a weighted average period of 0.7 years for options, 1.5 years for restricted stock and 0.9 years for restricted stock units. We issue new shares from our share reserves set aside for the Calpine Equity Incentive Plans and employment inducement options when stock options are exercised and for other share-based awards.

A summary of all of our non-qualified stock option activity for the six months ended June 30, 2014, is as follows:



	Number of Shares	Weighted Average Exercise Price		Weighted Average Remaining Term (in years)	Aggregate Intrinsic Value (in millions)
Outstanding — December 31, 2013	14,114,289	$	18.25	3.1	$	36
Granted	—	$	—
Exercised	935,269	$	16.04
Forfeited	—	$	—
Expired	2,500	$	17.79
Outstanding — June 30, 2014	13,176,520	$	18.41	2.4	$	73
Exercisable — June 30, 2014	12,313,723	$	18.63	2.1	$	66
Vested and expected to vest – June 30, 2014	13,140,231	$	18.42	2.4	$	73

The total intrinsic value of our employee stock options exercised was $6 million and $4 million for the six months ended June 30, 2014 and 2013, respectively. The total cash proceeds received from our employee stock options exercised was $15 million and $17 million for the six months ended June 30, 2014 and 2013, respectively.

There were no stock options granted during the six months ended June 30, 2014. The fair value of options granted during the six months ended June 30, 2013 was determined on the grant date using the Black-Scholes option-pricing model. Certain assumptions were used in order to estimate fair value for options as noted in the following table:



	2013
Expected term (in years)⁽¹⁾	6.5
Risk-free interest rate⁽²⁾	1.4		%
Expected volatility⁽³⁾	25.6		%
Dividend yield⁽⁴⁾	—
Weighted average grant-date fair value (per option)	$	5.31

___________


(1)	Expected term calculated using the simplified method prescribed by the SEC due to the lack of sufficient historical exercise data on the grant date to provide a reasonable basis to estimate the expected term.


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


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


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

A summary of our restricted stock and restricted stock unit activity for the six months ended June 30, 2014, is as follows:



	Number of Restricted Stock Awards	Weighted Average Grant-Date Fair Value
Nonvested — December 31, 2013	4,431,841	$	16.45
Granted	1,842,822	$	19.26
Forfeited	79,990	$	17.54
Vested	1,501,982	$	15.23
Nonvested — June 30, 2014	4,692,691	$	17.92

The total fair value of our restricted stock and restricted stock units that vested during the six months ended June 30, 2014 and 2013, was approximately $30 million and $21 million, respectively.

Liability Classified Share-Based Awards

During the first quarter of 2014, our Board of Directors approved the award of performance share units to certain senior management employees. These performance share units will be settled in cash with payouts based on the relative performance of Calpine’s TSR over the three-year performance period of January 1, 2014 through December 31, 2016 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 liability classified and are measured at fair value using a Monte Carlo simulation model at each reporting date until settlement. Stock-based compensation expense recognized related to our liability classified share-based awards was $4 million and $1 million for the three months ended June 30, 2014 and 2013, respectively, and $5 million and $1 million for the six months ended June 30, 2014 and 2013, respectively.

A summary of our performance share unit activity for the six months ended June 30, 2014, is as follows:



	Number of Performance Share Units		Weighted Average Grant-Date Fair Value
Nonvested — December 31, 2013	449,798		$	21.25
Granted	461,393		$	22.56
Forfeited	—		$	—
Vested	15,312	⁽¹⁾	$	21.25
Nonvested — June 30, 2014	895,879		$	21.92

___________


(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.


11.	Shareholder Transaction

On July 8, 2014, we entered into a share repurchase agreement, at the prevailing market price, with a shareholder that beneficially held slightly less than 10% of our outstanding common stock to purchase 13,213,372 shares of our common stock for the aggregate purchase price of $311,464,283 in a private transaction. We used cash on hand to fund the transaction which settled on July 10, 2014, and the repurchased shares have been returned to treasury stock.


12.	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 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 reserved its rights to assert any penalty claims associated with this violation and RCEC reserved its rights to assert any defenses to such claims in future proceedings.


13.	Segment Information

We assess our business on a regional basis due to the impact on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors impacting supply and demand. At June 30, 2014, our reportable segments were West (including geothermal), Texas, North (including Canada) and Southeast.

On July 3, 2014, we announced the closing of the sale of six power plants in our Southeast segment. Accordingly, during the third quarter of 2014, we plan to reflect the results of operations of the remaining four power plants in our Southeast segment, along with the historical results of the six power plants that were sold, in our North segment and change the name of this geographic segment to “East”. Thus, beginning in the third quarter of 2014, our reportable segments will be West (including geothermal), Texas and East (including North, Southeast and Canada). These changes will be made in conjunction with the manner in which our geographic information will be presented internally to our chief operating decision maker.

Commodity Margin is a key operational measure reviewed by our chief operating decision maker to assess the performance of our segments. During the fourth quarter of 2013, we changed the methodology previously used during 2013 for allocating corporate expenses to our segments. This change had no impact on our Consolidated Condensed Statements of Operations for the three and six months ended June 30, 2014; however, segment amounts previously reported for the three and six months ended June 30, 2013 were adjusted by immaterial amounts. Our segment data for the three and six months ended June 30, 2013 have been recast to reflect these changes. The tables below show our financial data for our segments for the periods indicated (in millions).



	Three Months Ended June 30, 2014
	West		Texas		North			Southeast			Consolidation and Elimination			Total
Revenues from external customers	$	487	$	960	$	332		$	160		$	—		$	1,939
Intersegment revenues	1		3		12			57			(73		)	—
Total operating revenues	$	488	$	963	$	344		$	217		$	(73	)	$	1,939
Commodity Margin⁽¹⁾	$	228	$	177	$	175		$	52		$	—		$	632
Add: Mark-to-market commodity activity, net and other⁽²⁾	21		184		(23		)	(1		)	(8		)	173
Less:
Plant operating expense	95		83		65			38			(7		)	274
Depreciation and amortization expense	58		48		32			8			1			147
Sales, general and other administrative expense	7		18		6			6			1			38
Other operating expenses	15		1		8			1			(4		)	21
(Income) from unconsolidated investments in power plants	—		—		(4		)	—			—			(4		)
Income (loss) from operations	74		211		45			(2		)	1			329
Interest expense, net of interest income														167
Other (income) expense, net														6
Income before income taxes														$	156



	Three Months Ended June 30, 2013
	West		Texas			North			Southeast			Consolidation and Elimination			Total
Revenues from external customers	$	479	$	571		$	348		$	174		$	—		$	1,572
Intersegment revenues	—		(25		)	8			71			(54		)	—
Total operating revenues	$	479	$	546		$	356		$	245		$	(54	)	$	1,572
Commodity Margin⁽¹⁾	$	198	$	133		$	159		$	43		$	—		$	533
Add: Mark-to-market commodity activity, net and other⁽²⁾	19		34			(12		)	7			(9		)	39
Less:
Plant operating expense	92		93			46			34			(8		)	257
Depreciation and amortization expense	53		42			32			18			—			145
Sales, general and other administrative expense	8		16			6			6			—			36
Other operating expenses	12		1			7			1			(1		)	20
(Income) from unconsolidated investments in power plants	—		—			(8		)	—			—			(8		)
Income (loss) from operations	52		15			64			(9		)	—			122
Interest expense, net of interest income															169
Debt extinguishment costs and other (income) expense, net															71
Loss before income taxes															$	(118	)



	Six Months Ended June 30, 2014
	West		Texas		North			Southeast		Consolidation and Elimination			Total
Revenues from external customers	$	978	$	1,607	$	971		$	348	$	—		$	3,904
Intersegment revenues	3		15		27			138		(183		)	—
Total operating revenues	$	981	$	1,622	$	998		$	486	$	(183	)	$	3,904
Commodity Margin⁽³⁾	$	430	$	298	$	442		$	107	$	—		$	1,277
Add: Mark-to-market commodity activity, net and other⁽⁴⁾	50		138		(40		)	5		(17		)	136
Less:
Plant operating expense	200		173		117			65		(16		)	539
Depreciation and amortization expense	118		90		65			26		1			300
Sales, general and other administrative expense	17		30		12			12		—			71
Other operating expenses	27		3		14			2		(3		)	43
(Income) from unconsolidated investments in power plants	—		—		(13		)	—		—			(13		)
Income from operations	118		140		207			7		1			473
Interest expense, net of interest income													332
Debt extinguishment costs and other (income) expense, net													17
Income before income taxes													$	124



	Six Months Ended June 30, 2013
	West			Texas			North			Southeast			Consolidation and Elimination			Total
Revenues from external customers	$	862		$	978		$	654		$	319		$	—		$	2,813
Intersegment revenues	1			(18		)	15			104			(102		)	—
Total operating revenues	$	863		$	960		$	669		$	423		$	(102	)	$	2,813
Commodity Margin⁽³⁾	$	400		$	209		$	301		$	84		$	—		$	994
Add: Mark-to-market commodity activity, net and other⁽⁴⁾	(18		)	23			(5		)	14			(16		)	(2		)
Less:
Plant operating expense	187			158			89			65			(15		)	484
Depreciation and amortization expense	106			84			65			37			(1		)	291
Sales, general and other administrative expense	15			30			12			12			—			69
Other operating expenses	21			2			14			2			(1		)	38
(Income) from unconsolidated investments in power plants	—			—			(16		)	—			—			(16		)
Income (loss) from operations	53			(42		)	132			(18		)	1			126
Interest expense, net of interest income																343
Debt extinguishment costs and other (income) expense, net																76
Loss before income taxes																$	(293	)

_________


(1)	Our Southeast segment includes Commodity Margin of $42 million and $32 million for the three months ended June 30, 2014 and 2013, respectively, related to the six power plants in our Southeast segment that were sold in July 2014.


(2)	Includes $(27) million and $(11) million of lease levelization and $3 million and $3 million of amortization expense for the three months ended June 30, 2014 and 2013, respectively.


(3)	Our Southeast segment includes Commodity Margin of $81 million and $57 million for the six months ended June 30, 2014 and 2013, respectively, related to the six power plants in our Southeast segment that were sold in July 2014.


(4)	Includes $(56) million and $(27) million of lease levelization and $7 million and $7 million of amortization expense for the six months ended June 30, 2014 and 2013, 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, Texas and the Mid-Atlantic region 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.

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 and power 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 goal is to be recognized as the premier power generation company in the U.S. as viewed by our employees, customers, regulators, shareholders and 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, and to set the foundation for future growth and success with the following achievements during 2014:


•	Our entire fleet achieved a low forced outage factor of 2% and an impressive starting reliability of 98.3% during the six months ended June 30, 2014 despite extreme weather conditions experienced in some of our markets during the first quarter of 2014.

•

In November 2013, our Board of Directors authorized a new $1.0 billion multi-year share repurchase program, under which we have repurchased a total of 21,063,743 shares of our common stock for approximately $434 million at an average price of $20.60 per share, leaving $566 million of remaining authorization. In addition, our Board of Directors authorized the repurchase of 13,213,372 shares of our common stock from a shareholder for approximately $311 million in a private transaction that was completed in July 2014.

•

On February 26, 2014, we completed the purchase of a modern, natural gas-fired, combined-cycle power plant with a capacity of 1,000 MW located in Guadalupe County, Texas for approximately $625 million, excluding working capital adjustments, which increased capacity in our Texas segment. We also paid $15 million to acquire rights to an advanced development opportunity for an approximately 400 MW quick-start, natural gas-fired peaker.


•	During the first quarter of 2014, we amended our CDHI letter of credit facility to lower our fees and extend the maturity to January 2, 2018.


•	In the second quarter of 2014, we completed the construction to expand the baseload capacity of our Deer Park and Channel Energy Centers by approximately 260 MW each.


•	On July 3, 2014, we completed the sale of six of our power plants in the Southeast segment for a purchase price of approximately $1.57 billion in cash, subject to working capital and other adjustments. The divestiture of these power plants has better aligned our asset base with our strategic focus on competitive wholesale markets.


•	On July 22, 2014, we issued $1.25 billion in aggregate principal amount of 5.375% senior unsecured notes due 2023 and $1.55 billion in aggregate principal amount of 5.75% senior unsecured notes due 2025 in a public offering. We used the proceeds to repurchase secured debt with a higher fixed interest rate.


•	On July 30, 2014, we amended our Corporate Revolving Facility to increase the capacity by an additional $500 million to $1.5 billion.


•	We successfully originated several new contracts with customers in our West, North and Texas segments, including those related to our Geysers Assets, RockGen Energy Center and Texas power plant fleet.

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. Our reportable segments are West (including geothermal), Texas, North (including Canada) and Southeast.

Following the sale of six of our Southeast power plants, our portfolio, including partnership interests, consists of 87 power plants, including 1 under construction, located throughout 17 states in the U.S. and in Canada, with an aggregate current generation capacity of 25,851 MW and 309 MW under construction. Our fleet, including projects under construction, consists of 70 combustion turbine-based plants, one fossil steam-based plant, 15 geothermal turbine-based plants and one photovoltaic solar plant. As of the filing of this Report, our segments have an aggregate generation capacity of 7,524 MW in the West, 9,427 MW in Texas and 8,900 MW with an additional 390 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 2013 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, though 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. At the direction of the PUCT, ERCOT stakeholders have introduced changes to avoid potential price suppression associated with the ORDC and the real time energy clearing prices. The PUCT has scheduled two workshops 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 continues to make refinements to the Reliability Pricing Model to increase its effectiveness. We generally support PJM’s proposed changes and believe that, overall, they enhance the competitiveness of the PJM power market; however, we cannot predict whether the FERC will approve all of PJM’s changes, what their ultimate impact may be, nor the impact on our financial condition, results of operations or cash flows.

PJM experienced several unusual cold weather events during the month of January 2014. PJM maintained system reliability, but significant natural gas and electricity price volatility during this time has led some federal and state legislators and

regulators to open inquiries into the events. PJM is responding to these inquiries and has stated that it intends to propose market rule changes, if warranted, to address any possible market rule deficiencies.

Certain states in the PJM market region, particularly New Jersey and Maryland, have taken anticompetitive actions that could have an adverse impact on the deregulated PJM power market by discouraging the construction of new generation. We are actively participating in the judicial process challenging these actions at the state and federal level. We believe the current competitive construct of the PJM power market, whereby new construction of power generation facilities is determined by forward price signals and not ratepayer guaranteed rate recovery, is the most efficient mechanism for incentivizing the construction of new power plants. As these judicial proceeding are ongoing, we cannot predict the ultimate impact on our financial condition, results of operations or cash flows.

Demand Response Resources

FERC’s Order No. 745 regarding compensation of demand response in the energy market was appealed to the U.S. Court of Appeals for the D.C. Circuit (“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. The FERC and several other parties have sought rehearing en banc of the D.C. Circuit’s decision. The D.C. Circuit has not ruled on these rehearing requests. If the D.C. Circuit’s decision is upheld, it could impact how demand response participates in electricity markets in the future.

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

On April 29, 2014, the U.S. Supreme Court in EME Homer City Generation v. EPA ruled in favor of the EPA by reversing and remanding the decision of the D.C. Circuit invalidating CSAPR. The U.S. Department of Justice on behalf of the EPA, has filed with the D.C. Circuit to lift the stay of CSAPR by 2015. The primary focus of the motion to lift the stay and responses is the CSAPR implementation deadlines. Subsequent filings have been made in response. The D.C. Circuit has not yet ruled on these filings.

On April 15, 2014, the D.C. Circuit rejected all legal challenges to the EPA's MATS regulation in the case White Stallion Energy Center, LLC, et al v. EPA., which included challenges by over 20 states, industry groups and companies.

MATS and CSAPR 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.

EPA GHG Regulations

In response to the 2007 decision of the U.S. Supreme Court in Massachusetts v. EPA and the Tailpipe Rule, which set GHG emission standards for cars and light trucks, the EPA issued two rules phasing in GHG regulation of stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V programs of the CAA. First, pursuant to the Timing Rule, the EPA delayed when major stationary sources of GHGs would otherwise be subject to PSD and Title V, limiting their application to the effective date of the Tailpipe Rule. Second, pursuant to the Tailoring Rule, the EPA limited the initial applicability of the GHG regulations to sources exceeding a specified carbon threshold.

These rules were the subject of more than sixty petitions for review by industry and the states, and after consolidation at the D.C. Circuit, were upheld. The U.S. Supreme Court heard the case on appeal, and on June 23, 2014, rejected the Tailoring Rule, but upheld the EPA’s authority to impose GHG limits on large new or modified sources if such sources were required to obtain permits for other pollutants. We are still assessing the overall impact of this ruling, but we do not expect a significant negative impact on our business as a result of this narrowing of the EPA’s authority.

In January 2014, the EPA proposed New Source Performance Standards (“NSPS”) for GHG emissions from new power plants, which are to be finalized within a reasonable period (likely within a year). 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. According to the EPA, the Clean Power Plan is to be finalized by June 2015 with state plans to implement these guidelines to be finalized by June 2016 with a possible extension to 2017. The Clean Power Plan provides states flexibility in meeting the requirements including increasing energy efficiency measures, adding renewable generation and increasing dispatch of natural gas-fired generation. We support the reasonable development and implementation of these rules by the EPA and believe that our competitive position is enhanced by regulations that ensure all power plants take the necessary steps to reduce their pollutant emissions.

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 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 been amended by the CARB several times since then, with the most recent amendments becoming effective July 1, 2014.

Under the Cap-and-Trade Regulation, the first compliance period for covered entities like Calpine began on January 1, 2013 and runs through the end of 2014. The second and third compliance periods, wherein the program will apply to a broader scope of entities, including transportation fuels and natural gas distribution, run through the end of 2017 and 2020, respectively. Proposed legislation has been introduced to delay applicability of the program to transportation fuels until the third compliance period.

On January 1, 2014, the California Cap-and-trade market was officially linked to the GHG Cap-and-trade market in Quebec. A practice auction will be held jointly by California and Quebec on August 9, 2014, with the first actual joint GHG allowance auction scheduled for November 2014.

On May 22, 2014, the CARB approved its “First Update to the Climate Change Scoping Plan: Building on the Framework” 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 to achieve the goal of reducing statewide GHG emissions to 80% below 1990 levels by 2050, including recommending the establishment of a mid-term emissions target for 2030.

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.

Cooling Water Intake Structures

On May 19, 2014, the EPA made public the final Cooling Water Intake Structure Rule, which regulates the design and operation of such structures at power plants and other sources in order to minimize adverse environmental impacts. This rule will become effective after its publication in the Federal Register. We are only subject to the provisions of this rule at one of our power plants, and we do not expect the rule to have a material direct impact on our operations.

RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED JUNE 30, 2014 AND 2013

Set forth below are our results of operations for the three months ended June 30, 2014 as compared to the same period in 2013 (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.



	2014			2013			Change			% Change
Operating revenues:
Commodity revenue	$	1,766		$	1,539		$	227		15
Mark-to-market gain	169			31			138			#
Other revenue	4			2			2			#
Operating revenues	1,939			1,572			367			23
Operating expenses:
Fuel and purchased energy expense:
Commodity expense	1,106			998			(108		)	(11	)
Mark-to-market loss	28			2			(26		)	#
Fuel and purchased energy expense	1,134			1,000			(134		)	(13	)
Plant operating expense	274			257			(17		)	(7	)
Depreciation and amortization expense	147			145			(2		)	(1	)
Sales, general and other administrative expense	38			36			(2		)	(6	)
Other operating expenses	21			20			(1		)	(5	)
Total operating expenses	1,614			1,458			(156		)	(11	)
(Income) from unconsolidated investments in power plants	(4		)	(8		)	(4		)	(50	)
Income from operations	329			122			207			#
Interest expense	169			170			1			1
Interest (income)	(2		)	(1		)	1			#
Debt extinguishment costs	—			68			68			#
Other (income) expense, net	6			3			(3		)	#
Income (loss) before income taxes	156			(118		)	274			#
Income tax expense (benefit)	15			(48		)	(63		)	#
Net income (loss)	141			(70		)	211			#
Net income attributable to the noncontrolling interest	(2		)	—			(2		)	—
Net income (loss) attributable to Calpine	$	139		$	(70	)	$	209		#



	2014		2013		Change		% Change
Operating Performance Metrics:
MWh generated (in thousands)⁽¹⁾	23,085		22,339		746		3
Average availability	88.1	%	88.2	%	(0.1	)%	—
Average total MW in operation⁽¹⁾	28,368		26,544		1,824		7
Average capacity factor, excluding peakers	41.7	%	43.4	%	(1.7	)%	(4	)
Steam Adjusted Heat Rate	7,433		7,447		14		—

__________


#	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 $119 million for the three months ended June 30, 2014, compared to the three months ended June 30, 2013, primarily due to:


•	our Russell City and Los Esteros power plants commencing commercial operations during the third quarter of 2013, the acquisition of Guadalupe Energy Center in February 2014 and the completion of the expansions of our Deer Park and Channel Energy Centers in June 2014;


•	stronger market conditions resulting in higher market Spark Spreads in the West and Texas during the second quarter of 2014 compared to the second quarter of 2013;


•	higher contribution from hedges; and


•	higher regulatory capacity revenue in the North; partially offset by


•	the expiration of a tolling contract associated with our Delta Energy Center in December 2013.

Generation increased 3% primarily due to our Russell City and Los Esteros power plants commencing commercial operations during the third quarter of 2013, the acquisition of Guadalupe Energy Center in February 2014 and the completion of the expansions of our Deer Park and Channel Energy Centers in June 2014, partially offset by outages at several of our power plants during the three months ended June 30, 2014 compared to the same period in 2013. Our average total MW in operation increased by 1,824 MW, or 7%, primarily due to the aforementioned changes in our power plant portfolio.

Mark-to-market gain/loss from hedging our future generation and fuel needs had a favorable variance of $112 million driven primarily by the impact on our commodity hedge positions of a near term decrease in forward power prices during the three months ended June 30, 2014 as compared to the same period in 2013 primarily in ERCOT due to mild summer weather.

Our plant operating expense increased by $17 million during the three months ended June 30, 2014, compared to the three months ended June 30, 2013. Of this amount, $11 million was attributable to power plant portfolio changes. Our normal, recurring plant operating expense increased $15 million during the three months ended June 30, 2014 compared to the same period in 2013, primarily resulting from an $8 million increase in equipment failure costs related to outages and a $7 million increase in other miscellaneous expenses. Meanwhile, we experienced an offsetting $10 million decrease in major maintenance expense resulting from our plant outage schedule during the three months ended June 30, 2014 compared to the same period in 2013.

Income from unconsolidated investments in power plants decreased $4 million primarily resulting from higher natural gas prices and a decrease in the Canadian-U.S. dollar exchange rate during the three months ended June 30, 2014 compared to the same period in 2013.

Interest expense decreased by $1 million for the three months ended June 30, 2014, compared to the same period in 2013, 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 6.1% for the three months ended June 30, 2014, from 6.8% for the three months ended June 30, 2013. The issuance of our CCFC Term Loans, 2022 First Lien Notes, 2024 First Lien Notes and 2020 First Lien Term Loan in 2013 allowed us to reduce our overall cost of debt by replacing our CCFC Notes and a portion of our First Lien Notes with debt carrying lower interest rates. The decrease in interest expense was partially offset by a decrease in capitalized interest of $6 million during the three months ended June 30, 2014 compared to the same period in 2013.

Debt extinguishment costs for the three months ended June 30, 2013, consisted of $68 million in connection with the redemption of the CCFC Notes, which is comprised of $40 million of prepayment penalties and $28 million associated with the write-off of unamortized debt discount and deferred financing costs. There were no debt extinguishment costs recorded during the three months ended June 30, 2014.

During the three months ended June 30, 2014, we recorded an income tax expense of $15 million compared to an income tax benefit of $48 million for the three months ended June 30, 2013. The unfavorable period-over-period change resulted from a decrease in income tax benefit of $63 million associated with various state and foreign jurisdiction income taxes, which primarily consisted of a period-over-period decrease related to an increase in our pre-tax income during the three months ended June 30, 2014 compared to the same period in 2013.

RESULTS OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2014 AND 2013

Set forth below are our results of operations for the six months ended June 30, 2014 as compared to the same period in 2013 (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.



	2014			2013			Change			% Change
Operating revenues:
Commodity revenue	$	3,814		$	2,847		$	967		34
Mark-to-market gain (loss)	83			(40		)	123			#
Other revenue	7			6			1			17
Operating revenues	3,904			2,813			1,091			39
Operating expenses:
Fuel and purchased energy expense:
Commodity expense	2,476			1,833			(643		)	(35	)
Mark-to-market (gain) loss	15			(12		)	(27		)	#
Fuel and purchased energy expense	2,491			1,821			(670		)	(37	)
Plant operating expense	539			484			(55		)	(11	)
Depreciation and amortization expense	300			291			(9		)	(3	)
Sales, general and other administrative expense	71			69			(2		)	(3	)
Other operating expenses	43			38			(5		)	(13	)
Total operating expenses	3,444			2,703			(741		)	(27	)
(Income) from unconsolidated investments in power plants	(13		)	(16		)	(3		)	(19	)
Income from operations	473			126			347			#
Interest expense	335			346			11			3
Interest (income)	(3		)	(3		)	—			—
Debt extinguishment costs	1			68			67			99
Other (income) expense, net	16			8			(8		)	#
Income (loss) before income taxes	124			(293		)	417			#
Income tax benefit	(4		)	(98		)	(94		)	(96	)
Net income (loss)	128			(195		)	323			#
Net income attributable to the noncontrolling interest	(6		)	—			(6		)	—
Net income (loss) attributable to Calpine	$	122		$	(195	)	$	317		#



	2014		2013		Change		% Change
Operating Performance Metrics:
MWh generated (in thousands)⁽¹⁾	46,062		46,337		(275	)	(1	)
Average availability	88.3	%	89.2	%	(0.9	)%	(1	)
Average total MW in operation⁽¹⁾	28,031		26,543		1,488		6
Average capacity factor, excluding peakers	42.4	%	45.5	%	(3.1	)%	(7	)
Steam Adjusted Heat Rate	7,393		7,394		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, increased $324 million for the six months ended June 30, 2014, compared to the six months ended June 30, 2013, primarily due to:


•	stronger market conditions resulting in higher realized Spark Spreads for the six months ended June 30, 2014 compared to the same period in 2013;


•	running some of our dual-fueled power plants in the North on fuel oil during the first quarter of 2014 rather than natural gas when fuel oil prices were lower than natural gas prices;


•	our Russell City and Los Esteros power plants commencing commercial operations during the third quarter of 2013, the acquisition of Guadalupe Energy Center in February 2014 and the completion of the expansions of our Deer Park and Channel Energy Centers in June 2014; and


•	higher regulatory capacity revenue in the North; partially offset by


•	lower contribution from hedges; and


•	the expiration of a tolling contract associated with our Delta Energy Center in December 2013.

Generation decreased 1% primarily due to outages at several of our power plants during the six months ended June 30, 2014 compared to the same period in 2013 partially offset by our Russell City and Los Esteros power plants commencing commercial operations during the third quarter of 2013, the acquisition of Guadalupe Energy Center in February 2014 and the completion of the expansions of our Deer Park and Channel Energy Centers in June 2014. Our average total MW in operation increased by 1,488 MW, or 6%, primarily due to the aforementioned changes in our power plant portfolio.

Mark-to-market gain/loss from hedging our future generation and fuel needs had a favorable variance of $96 million driven primarily by the impact on our commodity hedge positions of a near term decrease in forward power prices during the six months ended June 30, 2014 as compared to the same period in 2013 primarily in ERCOT due to mild summer weather.

Our plant operating expense increased by $55 million during the six months ended June 30, 2014, compared to the six months ended June 30, 2013. Of this amount, $20 million was attributable to power plant portfolio changes. Our normal, recurring plant operating expense increased $31 million during the six months ended June 30, 2014 compared to the same period in 2013, primarily resulting from a $13 million increase in equipment failure costs related to outages, an $11 million reversal of Section 185 fees for which we determined we have no current or retroactive fee obligations during 2013 and a $7 million increase in other miscellaneous expenses. We also experienced a $5 million increase in major maintenance expense resulting from our plant outage schedule during the six months ended June 30, 2014 compared to the same period in 2013.

Depreciation and amortization expense increased by $9 million during the six months ended June 30, 2014, compared to the same period in 2013, primarily resulting from a $14 million increase related to our Russell City and Los Esteros power plants commencing commercial operations in the third quarter of 2013 and a $10 million increase due to our acquisition of the Guadalupe Energy Center in February 2014. The increase was partially offset by a $10 million decrease related to the sale of our six power plants in the Southeast segment which we ceased depreciating in April 2014 and a $6 million decrease due to the timing of assets placed into service net of assets fully depreciated during 2013 and in the first half of 2014.

Other operating expenses increased by $5 million during the six months ended June 30, 2014, compared to the same period in 2013, primarily due to a reversal during the first quarter of 2013 of a tax reserve resulting from the expiration of applicable statutes of limitations, and an increase in legal expenses for the six months ended June 30, 2014.

Interest expense decreased by $11 million for the six months ended June 30, 2014, compared to the same period in 2013, 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 6.1% for the six months ended June 30, 2014, from 6.9% for the six months ended June 30, 2013. The issuance of our CCFC Term Loans, 2022 First Lien Notes, 2024 First Lien Notes and 2020 First Lien Term Loan in 2013 allowed us to reduce our overall cost of debt by replacing our CCFC Notes and a portion of our First Lien Notes with debt carrying lower interest rates. The decrease in interest expense was partially offset by a decrease in capitalized interest of $12 million during the six months ended June 30, 2014 compared to the same period in 2013.

Debt extinguishment costs for the six months ended June 30, 2013, consisted of $68 million in connection with the redemption of the CCFC Notes, which is comprised of $40 million of prepayment penalties and $28 million associated with the write-off of unamortized debt discount and deferred financing costs.

Other (income) expense, net increased by $8 million for the six months ended June 30, 2014, compared to the same period in 2013, primarily due to a $7 million increase related to a change in estimate for a legal reserve.

During the six months ended June 30, 2014, we recorded an income tax benefit of $4 million compared to an income tax benefit of $98 million for the six months ended June 30, 2013. The unfavorable period-over-period change resulted from a decrease in income tax benefit associated with an increase in our pre-tax income during the first half of 2014 compared to the same period in 2013.

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 including natural gas transactions hedging future power sales, 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 13 of the Notes to Consolidated Condensed Financial Statements for a reconciliation of Commodity Margin to income (loss) from operations by segment.

Commodity Margin by Segment for the Three Months Ended June 30, 2014 and 2013

The following tables show our Commodity Margin and related operating performance metrics by segment for the three months ended June 30, 2014 and 2013 (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:	2014			2013			Change			% Change
Commodity Margin (in millions)	$	228		$	198		$	30		15
Commodity Margin per MWh generated	$	33.68		$	27.39		$	6.29		23

MWh generated (in thousands)	6,770			7,229			(459		)	(6	)
Average availability	91.6		%	88.8		%	2.8		%	3
Average total MW in operation	7,524			6,751			773			11
Average capacity factor, excluding peakers	44.0		%	52.5		%	(8.5		)%	(16	)
Steam Adjusted Heat Rate	7,377			7,414			37			—

West — Commodity Margin in our West segment increased by $30 million, or 15%, for the three months ended June 30, 2014 compared to the three months ended June 30, 2013, primarily due to our contracted 464 MW Russell City and 309 MW Los Esteros power plants, which commenced commercial operations during the third quarter of 2013 and were also the drivers of a 773 MW, or 11%, increase in our average total MW in operation. The positive impact of 773 MW in additional contracted capacity was partially offset by the expiration of a tolling contract associated with our Delta Energy Center in December 2013. Commodity Margin was also positively impacted by higher market Spark Spreads resulting from stronger market conditions due to lower hydroelectric generation during the second quarter of 2014 compared to the second quarter of 2013. The impact of these positive

factors was partially offset by lower contribution from hedges during the three months ended June 30, 2014 compared to the same period in 2013.



Texas:	2014			2013			Change			% Change
Commodity Margin (in millions)	$	177		$	133		$	44		33
Commodity Margin per MWh generated	$	18.65		$	18.29		$	0.36		2

MWh generated (in thousands)	9,489			7,270			2,219			31
Average availability	90.8		%	83.5		%	7.3		%	9
Average total MW in operation	8,885			7,781			1,104			14
Average capacity factor, excluding peakers	48.9		%	42.8		%	6.1		%	14
Steam Adjusted Heat Rate	7,282			7,184			(98		)	(1	)

Texas — Commodity Margin in our Texas segment increased by $44 million, or 33%, for the three months ended June 30, 2014 compared to the three months ended June 30, 2013, primarily due to stronger market conditions in April and May 2014 compared to the same months in 2013. In addition, weaker market conditions experienced in June 2014 were more than offset from the positive impact of higher contribution from hedges in the same period. Commodity Margin also increased due to the acquisition of our 1,000 MW Guadalupe Energy Center on February 26, 2014 and the expansions of our Deer Park and Channel Energy Centers which were completed in June 2014, all of which were also the primary drivers of the 1,104 MW, or 14%, increase in our average total MW in operation and 31% increase in generation.



North:	2014			2013			Change			% Change
Commodity Margin (in millions)	$	175		$	159		$	16		10
Commodity Margin per MWh generated	$	52.52		$	39.10		$	13.42		34

MWh generated (in thousands)	3,332			4,067			(735		)	(18	)
Average availability	79.0		%	88.2		%	(9.2		)%	(10	)
Average total MW in operation	6,723			6,776			(53		)	(1	)
Average capacity factor, excluding peakers	35.1		%	42.9		%	(7.8		)%	(18	)
Steam Adjusted Heat Rate	8,061			8,015			(46		)	(1	)

North — Commodity Margin in our North segment increased by $16 million, or 10%, for the three months ended June 30, 2014 compared to the three months ended June 30, 2013, primarily due to higher regulatory capacity revenue. Generation decreased 18% due primarily to outages at several of our power plants during the second quarter of 2014. Average total MW in operation decreased 1% due to the retirement of our Deepwater Energy Center during the second quarter of 2014.



Southeast:	2014			2013			Change			% Change
Commodity Margin (in millions)	$	52		$	43		$	9		21
Commodity Margin per MWh generated	$	14.88		$	11.40		$	3.48		31

MWh generated (in thousands)	3,494			3,773			(279		)	(7	)
Average availability	89.9		%	95.2		%	(5.3		)%	(6	)
Average total MW in operation	5,236			5,236			—			—
Average capacity factor, excluding peakers	31.2		%	33.7		%	(2.5		)%	(7	)
Steam Adjusted Heat Rate	7,368			7,429			61			1

Southeast — Commodity Margin in our Southeast segment increased by $9 million, or 21%, for the three months ended June 30, 2014 compared to the three months ended June 30, 2013, primarily due to stronger market conditions and the positive impact of new contracts which became effective in 2014.

Commodity Margin by Segment for the Six Months Ended June 30, 2014 and 2013

The following tables show our Commodity Margin and related operating performance metrics by segment for the six months ended June 30, 2014 and 2013 (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:	2014			2013			Change			% Change
Commodity Margin (in millions)	$	430		$	400		$	30		8
Commodity Margin per MWh generated	$	27.56		$	25.70		$	1.86		7

MWh generated (in thousands)	15,601			15,566			35			—
Average availability	90.3		%	88.7		%	1.6		%	2
Average total MW in operation	7,524			6,751			773			11
Average capacity factor, excluding peakers	51.1		%	57.0		%	(5.9		)%	(10	)
Steam Adjusted Heat Rate	7,301			7,345			44			1

West — Commodity Margin in our West segment increased by $30 million, or 8%, for the six months ended June 30, 2014 compared to the six months ended June 30, 2013, primarily due to our contracted 464 MW Russell City and 309 MW Los Esteros power plants, which commenced commercial operations during the third quarter of 2013 and were also the drivers of a 773 MW, or 11%, increase in our average total MW in operation. The positive impact of 773 MW in additional contracted capacity was partially offset by the expiration of a tolling contract associated with our Delta Energy Center in December 2013. Commodity Margin was also positively impacted by higher market Spark Spreads resulting from stronger market conditions due to lower hydroelectric generation during the first half of 2014 compared to the same period in 2013. The impact of these positive factors was partially offset by lower contribution from hedges during the six months ended June 30, 2014 compared to the same period in 2013.



Texas:	2014			2013			Change			% Change
Commodity Margin (in millions)	$	298		$	209		$	89		43
Commodity Margin per MWh generated	$	18.21		$	13.66		$	4.55		33

MWh generated (in thousands)	16,366			15,300			1,066			7
Average availability	86.9		%	85.4		%	1.5		%	2
Average total MW in operation	8,521			7,780			741			10
Average capacity factor, excluding peakers	44.2		%	45.3		%	(1.1		)%	(2	)
Steam Adjusted Heat Rate	7,227			7,173			(54		)	(1	)

Texas — Commodity Margin in our Texas segment increased by $89 million, or 43%, for the six months ended June 30, 2014 compared to the six months ended June 30, 2013, due primarily to stronger market conditions during the first five months of 2014 compared to the same period in 2013 resulting in higher realized market Spark Spreads. In addition, Commodity Margin increased due to the acquisition of our 1,000 MW Guadalupe Energy Center on February 26, 2014 and the expansions of our Deer Park and Channel Energy Centers which were completed in June 2014, all of which were also the primary drivers of the 741 MW, or 10%, increase in our average total MW in operation and 7% increase in generation.



North:	2014			2013			Change			% Change
Commodity Margin (in millions)	$	442		$	301		$	141		47
Commodity Margin per MWh generated	$	63.35		$	37.74		$	25.61		68

MWh generated (in thousands)	6,977			7,976			(999		)	(13	)
Average availability	83.6		%	90.2		%	(6.6		)%	(7	)
Average total MW in operation	6,750			6,776			(26		)	—
Average capacity factor, excluding peakers	36.8		%	43.1		%	(6.3		)%	(15	)
Steam Adjusted Heat Rate	8,014			7,963			(51		)	(1	)

North — Commodity Margin in our North segment increased by $141 million, or 47%, for the six months ended June 30, 2014 compared to the six months ended June 30, 2013, primarily due to stronger market conditions driven by colder than normal weather during the first quarter of 2014 resulting in higher realized market Spark Spreads. Given the flexible, dual-fuel capability of some of our power plants in the North, we were able to realize higher Commodity Margin by running some of our power plants on fuel oil during the first quarter of 2014 rather than natural gas when fuel oil prices were lower than natural gas prices. Also contributing to the period-over-period increase was higher regulatory capacity revenues during the six months ended June 30, 2014 compared to the same period in 2013. The increase in Commodity Margin was partially offset by lower contribution from hedges in the six months ended June 30, 2014 compared to the same period in 2013. Generation decreased 13% due primarily to outages at several of our power plants during the six months ended June 30, 2014 compared to the same period in 2013.



Southeast:	2014			2013			Change			% Change
Commodity Margin (in millions)	$	107		$	84		$	23		27
Commodity Margin per MWh generated	$	15.03		$	11.21		$	3.82		34

MWh generated (in thousands)	7,118			7,495			(377		)	(5	)
Average availability	93.8		%	94.7		%	(0.9		)%	(1	)
Average total MW in operation	5,236			5,236			—			—
Average capacity factor, excluding peakers	32.0		%	33.7		%	(1.7		)%	(5	)
Steam Adjusted Heat Rate	7,373			7,349			(24		)	—

Southeast — Commodity Margin in our Southeast segment increased by $23 million, or 27%, for the six months ended June 30, 2014 compared to the six months ended June 30, 2013, primarily due to stronger market conditions driven by colder than normal weather during the first quarter of 2014 resulting in higher realized market Spark Spreads as well as the positive impact of new contracts which became effective in 2014. The increase in Commodity Margin was partially offset by lower contribution from hedges during the first half of 2014 compared to the first half of 2013.

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 or extinguishment of debt, non-cash GAAP-related adjustments to levelize revenues from tolling contracts 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.

During the fourth quarter of 2013, we changed the methodology previously used during 2013 for allocating corporate expenses to our segments. This change had no impact on our Consolidated Condensed Statements of Operations for the three and six months ended June 30, 2013; however, segment amounts previously reported for the three and six months ended June 30, 2013 were adjusted by immaterial amounts. Our segment data for the three and six months ended June 30, 2013 has been recast to reflect this change. The tables below provide a reconciliation of Adjusted EBITDA to our income (loss) from operations on a segment basis and to net income (loss) attributable to Calpine on a consolidated basis for the periods indicated (in millions).



	Three Months Ended June 30, 2014
	West			Texas			North		Southeast⁽¹⁾			Consolidation and Elimination			Total
Net income attributable to Calpine															$	139
Net income attributable to the noncontrolling interest															2
Income tax expense															15
Other (income) expense, net															6
Interest expense, net of interest income															167
Income (loss) from operations	$	74		$	211		$	45	$	(2	)	$	1		$	329
Add:
Adjustments to reconcile income (loss) from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs⁽²⁾	58			48			32		8			—			146
Major maintenance expense	18			20			23		11			—			72
Operating lease expense	2			—			6		—			—			8
Mark-to-market (gain) loss on commodity derivative activity	10			(177		)	20		6			—			(141		)
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest⁽³⁾	(2		)	—			8		—			—			6
Stock-based compensation expense	2			6			2		2			—			12
Loss on dispositions of assets	1			—			—		—			—			1
Acquired contract amortization	—			—			3		—			—			3
Other	(23		)	1			2		(2		)	(1		)	(23		)
Total Adjusted EBITDA	$	140		$	109		$	141	$	23		$	—		$	413



	Three Months Ended June 30, 2013
	West			Texas			North		Southeast⁽¹⁾			Consolidation and Elimination		Total
Net loss attributable to Calpine														$	(70	)
Income tax benefit														(48		)
Debt extinguishment costs and other (income) expense, net														71
Interest expense, net of interest income														169
Income (loss) from operations	$	52		$	15		$	64	$	(9	)	$	—	$	122
Add:
Adjustments to reconcile income (loss) from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs⁽²⁾	53			42			32		19			—		146
Major maintenance expense	21			44			8		10			—		83
Operating lease expense	2			—			6		—			—		8
Mark-to-market (gain) loss on commodity derivative activity	(10		)	(28		)	9		—			—		(29		)
Adjustments to reflect Adjusted EBITDA from unconsolidated investments⁽³⁾	—			—			7		—			—		7
Stock-based compensation expense	3			5			2		2			—		12
Loss on dispositions of assets	—			2			—		—			—		2
Acquired contract amortization	—			—			3		—			—		3
Other	(8		)	—			1		(4		)	—		(11		)
Total Adjusted EBITDA	$	113		$	80		$	132	$	18		$	—	$	343



	Six Months Ended June 30, 2014
	West			Texas			North			Southeast⁽⁴⁾			Consolidation and Elimination			Total
Net income attributable to Calpine																$	122
Net income attributable to the noncontrolling interest																6
Income tax benefit																(4		)
Debt extinguishment costs and other (income) expense, net																17
Interest expense, net of interest income																332
Income from operations	$	118		$	140		$	207		$	7		$	1		$	473
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs⁽²⁾	116			90			65			26			—			297
Major maintenance expense	46			57			36			14			—			153
Operating lease expense	4			—			13			—			—			17
Mark-to-market (gain) loss on commodity derivative activity	14			(124		)	39			3			—			(68		)
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest⁽³⁾	(6		)	—			15			—			—			9
Stock-based compensation expense	6			9			3			4			—			22
Loss on dispositions of assets	1			—			—			—			—			1
Acquired contract amortization	—			—			7			—			—			7
Other	(46		)	1			(2		)	(4		)	(1		)	(52		)
Total Adjusted EBITDA	$	253		$	173		$	383		$	50		$	—		$	859



	Six Months Ended June 30, 2013
	West			Texas			North			Southeast⁽⁴⁾			Consolidation and Elimination			Total
Net loss attributable to Calpine																$	(195	)
Income tax benefit																(98		)
Debt extinguishment costs and other (income) expense, net																76
Interest expense, net of interest income																343
Income (loss) from operations	$	53		$	(42	)	$	132		$	(18	)	$	1		$	126
Add:
Adjustments to reconcile income (loss) from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs⁽²⁾	106			84			65			38			(1		)	292
Major maintenance expense	45			70			16			18			—			149
Operating lease expense	4			—			13			—			—			17
Mark-to-market (gain) loss on commodity derivative activity	38			(10		)	4			(4		)	—			28
Adjustments to reflect Adjusted EBITDA from unconsolidated investments⁽³⁾	—			—			13			—			—			13
Stock-based compensation expense	6			8			3			3			—			20
Loss on dispositions of assets	1			3			—			—			—			4
Acquired contract amortization	—			—			7			—			—			7
Other	(18		)	—			(3		)	(6		)	—			(27		)
Total Adjusted EBITDA	$	235		$	113		$	250		$	31		$	—		$	629

____________


(1)	Our Southeast segment includes Adjusted EBITDA of $23 million and $15 million for the three months ended June 30, 2014 and 2013, respectively, related to the six power plants in our Southeast segment that were sold in July 2014.


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


(3)	Adjustments to reflect Adjusted EBITDA from unconsolidated investments include (gain) loss on mark-to-market activity of nil for each of the three and six months ended June 30, 2014 and 2013.


(4)	Our Southeast segment includes Adjusted EBITDA of $43 million and $21 million for the six months ended June 30, 2014 and 2013, respectively, related to the six power plants in our Southeast segment that were sold in July 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 June 30, 2014 and December 31, 2013 (in millions):



	June 30, 2014		December 31, 2013
Cash and cash equivalents, corporate⁽¹⁾	$	286	$	649
Cash and cash equivalents, non-corporate	156		292
Total cash and cash equivalents⁽²⁾	442		941
Restricted cash	257		272
Corporate Revolving Facility availability⁽³⁾	765		758
CDHI letter of credit facility availability	6		7
Total current liquidity availability	$	1,470	$	1,978

____________


(1)	Includes $184 million and $5 million of margin deposits posted with us by our counterparties at June 30, 2014 and December 31, 2013, respectively.

(2)

Cash and cash equivalents decreased during the six months ended June 30, 2014 primarily resulting from $244 million in cash on hand used to fund the purchase of Guadalupe Energy Center, $297 million in share repurchases, $95 million in payments to fund the construction of Garrison Energy Center and the expansions of our Channel and Deer Park Energy Centers as well as other seasonal variations in working capital, which cause fluctuations in our cash and cash equivalents.


(3)	On July 30, 2014, we amended our Corporate Revolving Facility to increase the capacity by an additional $500 million to $1.5 billion. The amount included in the table above does not reflect the amendment.

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, will be 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 July 16, 2014, an increase of $1/MMBtu in natural gas prices would result in an increase of collateral required by

approximately $134 million. If natural gas prices decreased by $1/MMBtu, we estimate that our collateral requirements would decrease by approximately $125 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 July 16, 2014, an increase of 500 Btu/KWh in the Market Heat Rate would result in an increase in collateral required by approximately $27 million. If Market Heat Rates were to fall at a similar rate, we estimate that our collateral required would decrease by $23 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 for 2014; however, we currently remain susceptible to significant price movements for 2015 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.

Our letters of credit, capital management, significant transactions, construction, modernizations, growth initiatives and asset sales are further discussed below.

Letter of Credit Facilities

The Corporate Revolving Facility represents our primary revolving facility. The table below represents amounts issued under our letter of credit facilities at June 30, 2014 and December 31, 2013 (in millions):



	June 30, 2014		December 31, 2013
Corporate Revolving Facility	$	235	$	242
CDHI	269		218
Various project financing facilities	171		170
Total	$	675	$	630

Capital Management and Significant Transactions

In connection with our goals of enhancing long-term shareholder value and leveraging our three scale regions, we have completed, made progress toward completing or initiated certain key capital management and significant transactions during 2014, as further described below.

Share Repurchase Program

of 13,213,372 shares of our common stock from a shareholder for approximately $311 million in a private transaction that was completed in July 2014. See Note 11 of the Notes to Consolidated Condensed Financial Statements for a further description of the shareholder transaction.

CCFC Term Loans

CDHI

During the first quarter of 2014, we amended our CDHI letter of credit facility to lower our fees and extend the maturity to January 2, 2018.

Refinancing of First Lien Notes with Senior Unsecured Notes

On July 22, 2014, we refinanced $2.8 billion of senior secured notes with an equivalent amount of senior unsecured notes. We issued $1.25 billion in aggregate principal amount of 5.375% senior unsecured notes due 2023 and $1.55 billion in aggregate principal amount of 5.75% senior unsecured notes due 2025 in a public offering, representing the inaugural issuance of unsecured debt within our capital structure. We used the net proceeds, together with cash on hand, to repurchase our 2019 First Lien Notes, 2020 First Lien Notes and 2021 First Lien Notes, which carried interest rates of 7.50% - 8.00%.

Corporate Revolving Facility

On July 30, 2014, we amended our Corporate Revolving Facility to increase the capacity by an additional $500 million to $1.5 billion.

Construction, Modernizations, Growth Initiatives and Asset Sales

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 divestiture opportunities on our non-core assets if those opportunities meet our financial expectations. 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 and modernizations are discussed below.

Texas:

Channel and Deer Park Expansions — In the second quarter of 2014, we completed the construction to expand the baseload capacity of our Deer Park and Channel Energy Centers by approximately 260 MW each. Each power plant featured an oversized steam turbine that, along with existing plant infrastructure, allowed us to add capacity and improve the power plant’s overall efficiency at a meaningful discount to the market cost of building new capacity.

Guadalupe Energy Center — On February 26, 2014, we, through our indirect, wholly-owned subsidiary Calpine Guadalupe GP, LLC, completed the purchase of a power plant owned by MinnTex Power Holdings, LLC with a capacity of 1,000 MW, for approximately $625 million, excluding working capital adjustments. The addition of this modern, natural gas-fired, combined-cycle power plant increased capacity in our Texas segment which is one of our core markets. We also paid $15 million to acquire the rights to an advanced development opportunity for an approximately 400 MW quick-start, natural gas-fired peaker. Development efforts are ongoing and we are continuing to advance entitlements (such as permits, zoning and transmission). See Note 2 of the Notes to the Consolidated Condensed Financial Statements for a further description of our acquisition of the Guadalupe Energy Center.

North:

Garrison Energy Center — Garrison Energy Center is a 309 MW combined-cycle project located in Delaware on a site secured by a long-term lease with the City of Dover. Construction commenced in April 2013, and we expect COD during the second quarter of 2015. The project’s capacity has cleared each of PJM’s three most recent base residual auctions. We are in the

early stages of development of a second phase (309 MW) of this project. PJM has completed the feasibility and system impact studies for this phase and the facilities study is currently underway.

Mankato Power Plant Expansion — We are proposing a 345 MW expansion of the Mankato Power Plant in response to a competitive resource acquisition process established by the Minnesota Public Utilities Commission (“MPUC”) to acquire up to approximately 500 MW of new capacity. The initial stage of the proceeding was managed via a contested case hearing. On March 27, 2014, the MPUC agreed in part and disagreed in part with the recommendation of the Administrative Law Judge and directed Xcel Energy (Northern States Power) to negotiate in parallel PPAs with Calpine and certain other entities, subject to final review and approval by the MPUC. A decision is expected in late 2014 or early 2015.

York 2 Energy Center — York 2 Energy Center is a nominal 760 MW dual fuel combined-cycle power plant that will be co-located with our York Energy Center in Peach Bottom Township, Pennsylvania. PJM has completed the project’s feasibility and system impact studies and the facilities study is underway. The project’s capacity cleared PJM’s 2017/2018 base residual auction and we expect COD during the second quarter of 2017. The project’s key permits and approvals are being actively pursued and the air permit has been filed with the Pennsylvania Department of Environmental Protection.

PJM Development Opportunities — We are currently evaluating opportunities to develop additional projects in the PJM market area 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.

Southeast:

Sale of Six Southeast Power Plants — On July 3, 2014, we completed the sale of six of our power plants in the Southeast segment for a purchase price of approximately $1.57 billion in cash, subject to working capital and other adjustments. The divestiture of these power plants has better aligned our asset base with our strategic focus on competitive wholesale markets. See Note 2 of the Notes to Consolidated Condensed Financial Statements for further description of the sale of these assets.

All Segments:

Turbine Modernization — We continue to move forward with our turbine modernization program. Through June 30, 2014, we have completed the upgrade of thirteen Siemens and eight GE turbines totaling approximately 210 MW and have committed to upgrade approximately three additional turbines. Similarly, we have the opportunity at several of our power plants in Texas to implement further turbine modernizations to add as much as 500 MW of incremental capacity across the region at attractive prices. In addition, we have begun a program to update our dual-fueled turbines at certain of our power plants in our North segment. Our decision to invest in these turbine modernizations depends upon, among other things, further clarity on market design reforms currently being considered.

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 2014 is as follows:


•	We entered into a new ten-year PPA, subject to approval by the CPUC, with Southern California Edison to provide 225 MW of capacity and renewable energy from our Geysers Assets commencing in June 2017.


•	We entered into a new five-year PPA with Dairyland Power Cooperative to provide capacity and energy from our RockGen Energy Center commencing in June 2018. The capacity under contract will initially be 135 MW, then will increase to 235 MW for the final four years of the contract.


•	We entered into a new six-year PPA with the City of San Marcos to provide power from our Texas power plant fleet commencing in July 2015.


•	We entered into a new two-year PPA with Pedernales Electric Cooperative to provide approximately 70 MW of power from our Texas power plant fleet commencing in August 2016.

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, 2013, our consolidated federal NOLs totaled approximately $7.5 billion.

Cash Flow Activities

The following table summarizes our cash flow activities for the six months ended June 30, 2014 and 2013 (in millions):



	2014			2013
Beginning cash and cash equivalents	$	941		$	1,284
Net cash provided by (used in):
Operating activities	349			(175		)
Investing activities	(900		)	(281		)
Financing activities	52			(113		)
Net decrease in cash and cash equivalents	(499		)	(569		)
Ending cash and cash equivalents	$	442		$	715

Net Cash Provided By (Used In) Operating Activities

Cash provided by operating activities for the six months ended June 30, 2014, was $349 million compared to cash used in operating activities of $175 million for the six months ended June 30, 2013. The increase was primarily due to:

•

Income from operations — Income from operations, adjusted for non-cash items, increased by $264 million for the six months ended June 30, 2014, compared to the six months ended June 30, 2013. Non-cash items consist primarily of depreciation and amortization, income from unconsolidated investments in power plants and mark-to-market activity. The increase in income from operations was primarily driven by a $324 million increase in Commodity revenue, net of Commodity expense partially offset by a $55 million increase in plant operating expense for the six months ended June 30, 2014, compared to the six months ended June 30, 2013. See “Results of Operations for the Six Months Ended June 30, 2014 and 2013” above for further discussion of these changes.

•

Working capital employed — Working capital employed decreased by approximately $211 million for the six months ended June 30, 2014, compared to the six months ended June 30, 2013, after adjusting for debt related balances which did not impact cash provided by operating activities. The decrease was primarily due to a decrease in net margin requirements partially offset by an increase in net accounts receivable/accounts payable balances as a result of higher Commodity Margin when compared to the same period in 2013.


•	Interest paid — Cash paid for interest decreased by $46 million to $288 million for the six months ended June 30, 2014, compared to $334 million for the six months ended June 30, 2013. The decrease was primarily due to the timing of interest payments.


•	Debt extinguishment payments — During the six months ended June 30, 2013, we made cash payments of $40 million associated with the redemption of the CCFC Notes. No similar payments were made during the six months ended June 30, 2014.

Net Cash Used In Investing Activities

Cash used in investing activities for the six months ended June 30, 2014 was $900 million compared to $281 million for the six months ended June 30, 2013. The increase was primarily due to:


•	Purchase of Guadalupe Energy Center — In 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 six months ended June 30, 2013.


•	Capital expenditures — Capital expenditures for the six months ended June 30, 2014 were $258 million, a decrease of $77 million, compared to expenditures of $335 million for the six months ended June 30, 2013. The decrease was primarily due our Russell City and Los Esteros power plants commencing commercial operations during the third quarter of 2013.


•	Restricted cash — The decrease in restricted cash was $14 million for the six months ended June 30, 2014, compared to a decrease of $55 million for the six months ended June 30, 2013. The smaller decrease in restricted cash in 2014 as compared to 2013 was primarily due to the release of cash collateral related to our CDHI letter of credit facility

and reduced project debt service requirements, partially offset by an increase related to revenue requirements for our Russell City power plant.

Net Cash Provided By (Used In) Financing Activities

Cash flows provided by financing activities were $52 million for the six months ended June 30, 2014, compared to cash flows used in financing activities of $113 million for the six months ended June 30, 2013. The increase was primarily due to:

•

CCFC refinancing — During the six months ended June 30, 2013, we received proceeds of approximately $1.2 billion under the CCFC Term Loans and made payments of $1.0 billion to repay the CCFC Notes, for net proceeds of $197 million. During the six months ended June 30, 2014, we received proceeds of approximately $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.


•	Stock repurchases — During the six months ended June 30, 2014, we made payments of approximately $297 million to repurchase our common stock as compared to $362 million during the six months ended June 30, 2013.

•

Decreased financing costs — During the six months ended June 30, 2014, we incurred finance costs of approximately $10 million as compared to $27 million for the six months ended June 30, 2013. The decrease was primarily due to the issuance of the CCFC Term Loans and the re-pricing of the First Lien Term Loans, which occurred during the six months ended June 30, 2013, with no similar activity during the six months ended June 30, 2014.


•	Lower proceeds from project debt — During the six months ended June 30, 2014, we received proceeds of approximately $2 million from project debt, compared to $116 million during the six months ended June 30, 2013. The decrease was related to lower draws on our Russell City and Los Esteros project debt as the power plants commenced commercial operations during the third quarter of 2013.

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 2013 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, 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 environmental product contracts and Heat Rate swaps and options) and fuel and purchased energy expense (for natural gas contracts, swaps and options). Our future hedged status and marketing and optimization activities are subject to change as determined by our commercial operations group, Chief Risk Officer, senior management and Board of Directors.

At any point in time, the relative quantity of our products hedged or sold under longer-term contracts is determined by the availability of forward product sales opportunities and our view of the attractiveness of the pricing available for forward sales. We have economically hedged a portion of our expected generation and natural gas portfolio mostly through power and natural gas forward physical and financial transactions for 2014; however, we currently remain susceptible to significant price movements for 2015 and beyond. When we elect to enter into these transactions, we are able to economically hedge a portion of our Spark Spread at pre-determined generation and price levels.

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

The primary factors affecting our market risk and the fair value of our derivatives at any point in time are the volume of open derivative positions (MMBtu, MWh and $ notional amounts); changing commodity market prices, primarily for power and natural gas; our credit standing and that of our counterparties for energy commodity derivatives; and prevailing interest rates for our interest rate swaps. Since prices for power and natural gas and interest rates are volatile, there may be material changes in the fair value of our derivatives over time, driven both by price volatility and the changes in volume of open derivative transactions. Our derivative assets have increased to approximately $1.0 billion at June 30, 2014, when compared to approximately $0.6 billion at December 31, 2013, and our derivative liabilities have increased to approximately $1.0 billion at June 30, 2014, compared to approximately $0.7 billion at December 31, 2013. At June 30, 2014, the fair value of our level 3 derivative assets and liabilities represent only a small portion of our total assets and liabilities measured at fair value (approximately 2% and 4%, respectively). See Note 5 of the Notes to Consolidated Condensed Financial Statements for further information related to our level 3 derivative assets and liabilities.

The change in fair value of our outstanding commodity and interest rate derivative instruments from January 1, 2014, through June 30, 2014, is summarized in the table below (in millions):



	Commodity Instruments			Interest Rate Swaps			Total
Fair value of contracts outstanding at January 1, 2014	$	(24	)	$	(120	)	$	(144	)
Items recognized or otherwise settled during the period⁽¹⁾⁽²⁾	(59		)	24			(35		)
Fair value attributable to new contracts	160			—			160
Changes in fair value attributable to price movements	77			(29		)	48
Changes in fair value attributable to nonperformance risk	(1		)	—			(1		)
Fair value of contracts outstanding at June 30, 2014⁽³⁾	$	153		$	(125	)	$	28

__________

(1)

Commodity contract settlements consist of roll-off of previously recognized gains on contracts not designated as hedging instruments of $78 million (represents a portion of Commodity revenue and Commodity expense as reported on our Consolidated Condensed Statements of Operations) and $19 million related to current period changes in derivative assets and liabilities not reflected in OCI or earnings.


(2)	Interest rate settlements consist of $14 million related to roll-off of losses from settlements of designated cash flow hedges and $10 million related to roll-off of 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 June 30,				Six Months Ended June 30,
	2014		2013		2014			2013
Realized gain (loss)⁽¹⁾
Commodity derivative instruments	$	18	$	5	$	(21	)	$	33
Total realized gain (loss)	$	18	$	5	$	(21	)	$	33

Mark-to-market gain (loss)⁽²⁾
Commodity derivative instruments	$	141	$	29	$	68		$	(28	)
Interest rate swaps	1		2		2			4
Total mark-to-market gain (loss)	$	142	$	31	$	70		$	(24	)
Total activity, net	$	160	$	36	$	49		$	9

____________


(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 June 30,				Six Months Ended June 30,
	2014		2013		2014			2013
Realized and mark-to-market gain (loss)
Derivatives contracts included in operating revenues	$	158	$	15	$	(79	)	$	(59	)
Derivatives contracts included in fuel and purchased energy expense	1		19		126			64
Interest rate swaps included in interest expense	1		2		2			4
Total activity, net	$	160	$	36	$	49		$	9

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

The net fair value of outstanding derivative commodity instruments at June 30, 2014, based on price source and the period during which the instruments will mature, are summarized in the table below (in millions):



Fair Value Source	2014			2015-2016			2017-2018		After 2018			Total
Prices actively quoted	$	(41	)	$	74		$	8	$	—		$	41
Prices provided by other external sources	88			31			—		—			119
Prices based on models and other valuation methods	(2		)	(4		)	1		(2		)	(7		)
Total fair value	$	45		$	101		$	9	$	(2	)	$	153

We measure the energy commodity price risks 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 which is comprised of energy commodity derivatives, expected generation and natural gas consumption from our power plants, PPAs, and other physical and financial transactions. We measure VAR using a variance/covariance approach based on a confidence level of 95%, a one-day holding period and actual observed historical correlation. While we believe that our VAR assumptions and approximations are reasonable, different assumptions and/or approximations could produce materially different estimates.

The table below presents the high, low and average of our daily VAR for the three and six months ended June 30, 2014 and 2013 (in millions):



	2014		2013
Three months ended June 30:
High	$	44	$	47
Low	$	34	$	33
Average	$	38	$	41
Six months ended June 30:
High	$	52	$	80
Low	$	34	$	33
Average	$	42	$	52
As of June 30	$	39	$	37

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 tests, scenario tests, stress tests, and daily position reports.

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 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 commercial customers, primarily independent electric system operators, relating to our sales of power, steam and 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 June 30, 2014, and the period during which the instruments will mature are summarized in the table below (in millions):



Credit Quality (Based on Standard & Poor’s Ratings as of June 30, 2014)	2014			2015-2016			2017-2018		After 2018			Total
Investment grade	$	42		$	100		$	9	$	—		$	151
Non-investment grade	(1		)	(3		)	—		—			(4		)
No external ratings	4			4			—		(2		)	6
Total fair value	$	45		$	101		$	9	$	(2	)	$	153

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 $(10) million at June 30, 2014.

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 2013 Form 10-K.


Item 4.	Controls and Procedures

Disclosure Controls and Procedures

As of the end of the period covered by this Report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rule 13a-15(e) and Rule 15d-15(e) of the Exchange Act. Based upon, and as of the date of, this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective such that the information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the second quarter of 2014, 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 12 of the Notes to Consolidated Condensed Financial Statements for a description of our legal proceedings.


Item 1A.	Risk Factors

There were no material changes to the description of the risk factors associated with our business previously disclosed in Part I, Item 1A “Risk Factors” of our 2013 Form 10-K.


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

Repurchase of Equity Securities



Period	(a) Total Number of Shares Purchased⁽¹⁾	(b) Average Price Paid Per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs⁽²⁾	(d) Maximum Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs (in millions)
April	1,648	$	20.76	—	$	755
May	5,144,663	$	22.35	5,141,021	$	640
June	1,760,578	$	23.72	1,758,148	$	598
Total	6,906,889	$	22.70	6,899,169	$	598

___________


(1)	Upon vesting of restricted stock awarded by us to employees, we withhold shares to cover employees’ tax withholding obligations, other than for employees who have chosen to satisfy their tax withholding obligations in cash. During the second quarter of 2014, we withheld a total of 7,720 shares that are included in total number of shares purchased.

(2)


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		Restricted Stock Agreement Pursuant to the Amended and Restated 2008 Equity Incentive Plan, dated May 13, 2014 among John B. Hill and Calpine Corporation, incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 15, 2014. †

10.2		Purchase and Sale Agreement, dated April 17, 2014, among Calpine Corporation, Calpine Project Holdings, Inc., Calgen Expansion Company, LLC and NatGen Southeast Power LLC, incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 8, 2014.

10.3		Calpine Guarantee, dated April 17, 2014, incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 8, 2014.

10.4		LS Power Equity Partners Guarantee, dated April 17, 2014, incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 8, 2014.

10.5		Confidentiality and Non-Disclosure Agreement, dated February 19, 2014, incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 8, 2014.

10.6		Amendment to Confidentiality and Non-disclosure Agreement, dated April 17, 2014 incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 8, 2014.

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.

_______________


†	Management contract or compensatory plan, contract or arrangement.


*	Furnished herewith.

SIGNATURES

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



CALPINE CORPORATION
(Registrant)

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

Date: July 31, 2014

EXHIBIT INDEX



Exhibit Number		Description
10.1		Restricted Stock Agreement Pursuant to the Amended and Restated 2008 Equity Incentive Plan, dated May 13, 2014 among John B. Hill and Calpine Corporation, incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 15, 2014. †

10.2		Purchase and Sale Agreement, dated April 17, 2014, among Calpine Corporation, Calpine Project Holdings, Inc., Calgen Expansion Company, LLC and NatGen Southeast Power LLC, incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 8, 2014.

10.3		Calpine Guarantee, dated April 17, 2014, incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 8, 2014.

10.4		LS Power Equity Partners Guarantee, dated April 17, 2014, incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 8, 2014.

10.5		Confidentiality and Non-Disclosure Agreement, dated February 19, 2014, incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 8, 2014.

10.6		Amendment to Confidentiality and Non-disclosure Agreement, dated April 17, 2014 incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 8, 2014.

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.

_______________


†	Management contract or compensatory plan, contract or arrangement.


*	Furnished herewith.

Attached files

Stock widget

Investing forum

CALPINE CORP Reports

Also read