CALPINE CORP - FORM 10-Q - April 30, 2015

Attached files

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EX-31.2 - SECTION 302 CERTIFICATION OF CHIEF FINANCIAL OFFICER - CALPINE CORP	cpn_exhibit312x03312015.htm
EX-31.1 - SECTION 302 CERTIFICATION OF CHIEF EXECUTIVE OFFICER - CALPINE CORP	cpn_exhibit311x03312015.htm
EX-32.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER - CALPINE CORP	cpn_exhibit321x03312015.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 March 31, 2015

		Or

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

For the transition period from to

Commission File No. 001-12079

______________________

Calpine Corporation

(A Delaware Corporation)

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

717 Texas Avenue, Suite 1000, Houston, Texas 77002

Telephone: (713) 830-2000

Not Applicable

(Former Address)

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):



Large accelerated filer	[X]		Accelerated filer	[ ]
Non-accelerated filer	[ ]	(Do not check if a smaller reporting company)	Smaller reporting company	[ ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X]

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: 372,345,009 shares of common stock, par value $0.001, were outstanding as of April 29, 2015.

CALPINE CORPORATION AND SUBSIDIARIES

REPORT ON FORM 10-Q

For the Quarter Ended March 31, 2015

INDEX




	Page

Definitions	ii

Forward-Looking Statements	vi

Where You Can Find Other Information	vii

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements	1
Consolidated Condensed Statements of Operations for the Three Months Ended March 31, 2015 and 2014	1
Consolidated Condensed Statements of Comprehensive Loss for the Three Months Ended March 31, 2015 and 2014	2
Consolidated Condensed Balance Sheets at March 31, 2015 and December 31, 2014	3
Consolidated Condensed Statements of Cash Flows for the Three Months Ended March 31, 2015 and 2014	4
Notes to Consolidated Condensed Financial Statements	6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Forward-Looking Information	25
Introduction and Overview	25
Results of Operations	28
Commodity Margin and Adjusted EBITDA	29
Liquidity and Capital Resources	34
Risk Management and Commodity Accounting	40
New Accounting Standards and Disclosure Requirements	44
Item 3. Quantitative and Qualitative Disclosures About Market Risk	44
Item 4. Controls and Procedures	44

PART II – OTHER INFORMATION

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

DEFINITIONS

As used in this report for the quarter ended March 31, 2015 (this “Report”), the following abbreviations and terms have the meanings as listed below. Additionally, the terms “Calpine,” “we,” “us” and “our” refer to Calpine Corporation and its consolidated subsidiaries, unless the context clearly indicates otherwise. The term “Calpine Corporation” refers only to Calpine Corporation and not to any of its subsidiaries. Unless and as otherwise stated, any references in this Report to any agreement means such agreement and all schedules, exhibits and attachments in each case as amended, restated, supplemented or otherwise modified to the date of filing this Report.



ABBREVIATION		DEFINITION
2014 Form 10-K		Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2014, filed with the SEC on February 13, 2015

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

2019 First Lien Term Loan		The $835 million first lien senior secured term loan, dated October 9, 2012, among Calpine Corporation, as borrower, 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 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

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

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

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

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

AOCI		Accumulated Other Comprehensive Income

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

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



ABBREVIATION		DEFINITION
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

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

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

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

CO₂		Carbon dioxide

COD		Commercial operations date

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

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

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

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

Company		Calpine Corporation, a Delaware corporation, and its subsidiaries

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

CPUC		California Public Utilities Commission

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

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

EPA		U.S. Environmental Protection Agency

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

ERCOT		Electric Reliability Council of Texas

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

iii



ABBREVIATION		DEFINITION
FASB		Financial Accounting Standards Board

FDIC		U.S. Federal Deposit Insurance Corporation

FERC		U.S. Federal Energy Regulatory Commission

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

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

GE		General Electric International, Inc.

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

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

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

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

IRS		U.S. Internal Revenue Service

ISO(s)		Independent System Operator(s)

ISO-NE		ISO New England Inc., an independent nonprofit RTO serving states in the New England area, including Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont

KWh		Kilowatt hour(s), a measure of power produced, purchased or sold

LIBOR		London Inter-Bank Offered Rate

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

MMBtu		Million Btu

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



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

PUCT		Public Utility Commission of Texas

REC(s)		Renewable energy credit(s)

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

RTO(s)		Regional Transmission Organization(s)

SEC		U.S. Securities and Exchange Commission

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

Senior Unsecured Notes		Collectively, the 2023 Senior Unsecured Notes, the 2024 Senior Unsecured Notes and the 2025 Senior Unsecured Notes

Spark Spread(s)		The difference between the sales price of power per MWh and the cost of natural gas to produce it

Steam Adjusted Heat Rate		The adjusted Heat Rate for our natural gas-fired power plants, excluding peakers, calculated by dividing (a) the fuel consumed in Btu reduced by the net equivalent Btu in steam exported to a third party by (b) the KWh generated. Steam Adjusted Heat Rate is a measure of fuel efficiency, so the lower our Steam Adjusted Heat Rate, the lower our cost of generation

TSR		Total shareholder return

U.S. GAAP		Generally accepted accounting principles in the U.S.

VAR		Value-at-risk

VIE(s)		Variable interest entity(ies)

Whitby		Whitby Cogeneration Limited Partnership, a 50% partnership interest between certain of our subsidiaries and a third party, which operates Whitby, a 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada

Forward-Looking Statements

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 and extent to which we hedge risks;


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


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


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

•

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


•	Competition, including risks associated with marketing and selling power in the evolving energy markets;


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


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


•	Future capacity revenues may not occur at expected levels;


•	Natural disasters, such as hurricanes, earthquakes, droughts 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 that may arise from noncompliance with market rules promulgated by the SEC, CFTC, FERC and other regulatory bodies; and


•	Other risks identified in this Report, in our 2014 Form 10-K and in other reports filed by us with the SEC.

Given the risks and uncertainties surrounding forward-looking statements, you should not place undue reliance on these statements. Many of these factors are beyond our ability to control or predict. Our forward-looking statements speak only as of the date of this Report. Other than as required by law, we undertake no obligation to update or revise forward-looking statements, whether as a result of new information, future events, or otherwise.

Where You Can Find Other Information

Our website is www.calpine.com. Information contained on our website is not part of this Report. Information that we furnish or file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to, or exhibits included in, these reports are available for download, free of charge, on our website soon after such reports are filed with or furnished to the SEC. Our SEC filings, including exhibits filed therewith, are also available 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 March 31,
		2015			2014
	(in millions, except share and per share amounts)
Operating revenues:
Commodity revenue		$	1,638		$	2,048
Mark-to-market gain (loss)		3			(86		)
Other revenue		5			3
Operating revenues		1,646			1,965
Operating expenses:
Fuel and purchased energy expense:
Commodity expense		1,077			1,370
Mark-to-market (gain)		(67		)	(13		)
Fuel and purchased energy expense		1,010			1,357
Plant operating expense		260			265
Depreciation and amortization expense		158			153
Sales, general and other administrative expense		37			33
Other operating expenses		20			22
Total operating expenses		1,485			1,830
(Income) from unconsolidated investments in power plants		(5		)	(9		)
Income from operations		166			144
Interest expense		154			166
Interest (income)		(1		)	(1		)
Debt extinguishment costs		19			1
Other (income) expense, net		2			10
Loss before income taxes		(8		)	(32		)
Income tax benefit		(1		)	(19		)
Net loss		(7		)	(13		)
Net income attributable to the noncontrolling interest		(3		)	(4		)
Net loss attributable to Calpine		$	(10	)	$	(17	)

Basic and diluted loss per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands)		372,935			420,105
Net loss per common share attributable to Calpine — basic and diluted		$	(0.03	)	$	(0.04	)

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

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE LOSS

(Unaudited)



		Three Months Ended March 31,
		2015			2014
	(in millions)
Net loss		$	(7	)	$	(13	)
Cash flow hedging activities:
Loss on cash flow hedges before reclassification adjustment for cash flow hedges realized in net loss		(18		)	(13		)
Reclassification adjustment for loss on cash flow hedges realized in net loss		12			13
Foreign currency translation loss		(12		)	(6		)
Income tax expense		—			—
Other comprehensive loss		(18		)	(6		)
Comprehensive loss		(25		)	(19		)
Comprehensive (income) attributable to the noncontrolling interest		(2		)	(4		)
Comprehensive loss attributable to Calpine		$	(27	)	$	(23	)

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

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited)



	March 31,			December 31,
	2015			2014
	(in millions, except share and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents ($296 and $229 attributable to VIEs)	$	796		$	717
Accounts receivable, net of allowance of $5 and $4	503			648
Inventories	486			447
Margin deposits and other prepaid expense	150			148
Restricted cash, current ($99 and $106 attributable to VIEs)	162			195
Derivative assets, current	1,858			2,058
Other current assets	17			7
Total current assets	3,972			4,220
Property, plant and equipment, net ($4,300 and $4,342 attributable to VIEs)	13,178			13,190
Restricted cash, net of current portion ($46 and $48 attributable to VIEs)	47			49
Investments in power plants	88			95
Long-term derivative assets	711			439
Other assets ($161 and $164 attributable to VIEs)	386			385
Total assets	$	18,382		$	18,378
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	456		$	580
Accrued interest payable	163			165
Debt, current portion ($146 and $150 attributable to VIEs)	197			199
Derivative liabilities, current	1,643			1,782
Other current liabilities	385			473
Total current liabilities	2,844			3,199
Debt, net of current portion ($3,199 and $3,242 attributable to VIEs)	11,520			11,083
Long-term derivative liabilities	572			444
Other long-term liabilities	241			221
Total liabilities	15,177			14,947

Commitments and contingencies (see Note 10)
Stockholders’ equity:
Preferred stock, $0.001 par value per share; authorized 100,000,000 shares, none issued and outstanding	—			—
Common stock, $0.001 par value per share; authorized 1,400,000,000 shares, 504,015,575 and 502,287,022 shares issued, respectively, and 373,837,359 and 381,921,264 shares outstanding, respectively	1			1
Treasury stock, at cost, 130,178,216 and 120,365,758 shares, respectively	(2,557		)	(2,345		)
Additional paid-in capital	12,453			12,440
Accumulated deficit	(6,550		)	(6,540		)
Accumulated other comprehensive loss	(195		)	(178		)
Total Calpine stockholders’ equity	3,152			3,378
Noncontrolling interest	53			53
Total stockholders’ equity	3,205			3,431
Total liabilities and stockholders’ equity	$	18,382		$	18,378

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

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)



	Three Months Ended March 31,
	2015			2014
	(in millions)
Cash flows from operating activities:
Net loss	$	(7	)	$	(13	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation and amortization expense⁽¹⁾	171			164
Deferred income taxes	—			(13		)
Mark-to-market activity, net	(71		)	72
(Income) from unconsolidated investments in power plants	(5		)	(9		)
Return on unconsolidated investments in power plants	—			13
Stock-based compensation expense	11			10
Other	(2		)	(2		)
Change in operating assets and liabilities:
Accounts receivable	120			(75		)
Derivative instruments, net	(17		)	(87		)
Other assets	(28		)	29
Accounts payable and accrued expenses	(204		)	106
Other liabilities	15			(72		)
Net cash provided by (used in) operating activities	(17		)	123
Cash flows from investing activities:
Purchases of property, plant and equipment	(162		)	(119		)
Purchase of Guadalupe Energy Center	—			(656		)
Decrease in restricted cash	35			6
Other	(1		)	—
Net cash used in investing activities	(128		)	(769		)
Cash flows from financing activities:
Borrowings under CCFC Term Loans	—			420
Repayment of CCFC Term Loans and First Lien Term Loans	(11		)	(11		)
Borrowings under Senior Unsecured Notes	650			—
Repurchase of First Lien Notes	(147		)	—
Repayments of project financing, notes payable and other	(58		)	(43		)
Financing costs	(11		)	(10		)
Stock repurchases	(202		)	(140		)
Proceeds from exercises of stock options	3			4
Net cash provided by financing activities	224			220
Net increase (decrease) in cash and cash equivalents	79			(426		)
Cash and cash equivalents, beginning of period	717			941
Cash and cash equivalents, end of period	$	796		$	515

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

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS — (CONTINUED)

(Unaudited)



	Three Months Ended March 31,
	2015			2014
	(in millions)
Cash paid during the period for:
Interest, net of amounts capitalized	$	146		$	225
Income taxes	$	6		$	8

Supplemental disclosure of non-cash investing activities:
Change in capital expenditures included in accounts payable	$	(22	)	$	(9	)

____________


(1)	Includes depreciation and amortization included in fuel and purchased energy expense and interest expense on our Consolidated Condensed Statements of Operations.

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

CALPINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

March 31, 2015

(Unaudited)


1.	Basis of Presentation and Summary of Significant Accounting Policies

We are a wholesale power generation company engaged in the ownership and operation of primarily natural gas-fired and geothermal power plants in North America. We have a significant presence in major competitive wholesale power markets in California (included in our West segment), Texas (included in our Texas segment) and the Northeast region (included in our East segment) of the U.S. We sell wholesale power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities, power marketers and others. We purchase primarily natural gas and some fuel oil as fuel for our power plants and engage in related natural gas transportation and storage transactions. We purchase electric transmission rights to deliver power to our customers. Additionally, consistent with our Risk Management Policy, we enter into natural gas, power and other physical and financial contracts to hedge certain business risks and optimize our portfolio of power plants.

Basis of Interim Presentation — The accompanying unaudited, interim Consolidated Condensed Financial Statements of Calpine Corporation, a Delaware corporation, and consolidated subsidiaries have been prepared pursuant to the rules and regulations of the SEC. In the opinion of management, the Consolidated Condensed Financial Statements include the normal, recurring adjustments necessary for a fair statement of the information required to be set forth therein. Certain information and note disclosures, normally included in financial statements prepared in accordance with U.S. GAAP, have been condensed or omitted from these statements pursuant to such rules and regulations and, accordingly, these financial statements should be read in conjunction with our audited Consolidated Financial Statements for the year ended December 31, 2014, included in our 2014 Form 10-K. The results for interim periods are not indicative of the results for the entire year primarily due to acquisitions and disposals of assets, seasonal fluctuations in our revenues, timing of major maintenance expense, variations resulting from the application of the method to calculate the provision for income tax for interim periods, volatility of commodity prices and mark-to-market gains and losses from commodity and interest rate derivative contracts.

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

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.

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

The table below represents the components of our restricted cash as of March 31, 2015 and December 31, 2014 (in millions):



	March 31, 2015						December 31, 2014
	Current		Non-Current		Total		Current		Non-Current		Total
Debt service	$	12	$	24	$	36	$	10	$	25	$	35
Rent reserve	2		—		2		4		—		4
Construction/major maintenance	60		17		77		54		17		71
Security/project/insurance	88		4		92		127		5		132
Other	—		2		2		—		2		2
Total	$	162	$	47	$	209	$	195	$	49	$	244

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



	March 31, 2015		December 31, 2014		Depreciable Lives
Buildings, machinery and equipment	$	16,092	$	16,059	3 – 47 Years
Geothermal properties	1,314		1,294		13 – 59 Years
Other	205		203		3 – 47 Years
	17,611		17,556
Less: Accumulated depreciation	5,122		4,984
	12,489		12,572
Land	119		120
Construction in progress	570		498
Property, plant and equipment, net	$	13,178	$	13,190

Capitalized Interest — The total amount of interest capitalized was $5 million and $6 million for the three months ended March 31, 2015 and 2014, respectively.

Treasury Stock — During the three months ended March 31, 2015, we repurchased a total of 9.3 million shares of our outstanding common stock for approximately $202 million at an average price of $21.57 per share. Additionally, we withheld shares with a value of $10 million to satisfy tax withholding obligations associated with the vesting of restricted stock awarded to employees under the Equity Plan.

Acquisition of Fore River Energy Center — During the three months ended March 31, 2015, there were no material adjustments made to the initial purchase price allocation recorded in the fourth quarter of 2014 related to our acquisition of Fore River Energy Center. 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.

New Accounting Standards and Disclosure Requirements

Revenue Recognition — In May 2014, the FASB issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers.” The comprehensive new revenue recognition standard will supersede all existing revenue recognition guidance. The core principle of the standard is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard 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.

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

Debt Issuance Costs — In April 2015, the FASB issued Accounting Standards Update 2015-03, “Simplifying the Presentation of Debt Issuance Costs.” The standard requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, which is consistent with the presentation of debt discounts. The standard is effective for fiscal years beginning after December 15, 2015, including interim periods within that reporting period and requires retrospective adoption with early adoption permitted. We do not anticipate a material impact on our financial condition, results of operations or cash flows as a result of adopting this standard.

Cloud Computing Arrangements — In April 2015, the FASB issued Accounting Standards Update 2015-05, “Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement.” This standard provides guidance regarding whether a cloud computing arrangement represents a software license or a service contract. The standard is effective for fiscal years beginning after December 15, 2015, including interim periods and allows for either prospective or retrospective adoption with early adoption permitted. We are currently assessing the future impact this standard may have on our financial condition, results of operations or cash flows.


2.	Variable Interest Entities and Unconsolidated Investments

We consolidate all of our VIEs where we have determined that we are the primary beneficiary. There were no changes to our determination of whether we are the primary beneficiary of our VIEs for the three months ended March 31, 2015. See Note 5 in our 2014 Form 10-K for further information regarding our VIEs.

VIE Disclosures

Our consolidated VIEs include natural gas-fired power plants with an aggregate capacity of 10,365 MW at both March 31, 2015 and December 31, 2014. 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 months ended March 31, 2015 and 2014, respectively.

Unconsolidated VIEs and Investments in Power Plants

We have a 50% partnership interest in Greenfield LP and in Whitby. Greenfield LP and Whitby are also VIEs; however, we do not have the power to direct the most significant activities of these entities and therefore do not consolidate them. Greenfield LP is a limited partnership between certain subsidiaries of ours and of Mitsui & Co., Ltd., which operates the Greenfield Energy Centre, a 1,038 MW natural gas-fired, combined-cycle power plant located in Ontario, Canada. We and Mitsui & Co., Ltd. each hold a 50% interest in Greenfield LP. Whitby is a limited partnership between certain of our subsidiaries and Atlantic Packaging Ltd., which operates the Whitby facility, a 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada. We and Atlantic Packaging Ltd. each hold a 50% partnership interest in Whitby.

We account for these entities under the equity method of accounting and include our net equity interest in investments in power plants on our Consolidated Condensed Balance Sheets. At March 31, 2015 and December 31, 2014, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):



	Ownership Interest as of March 31, 2015	March 31, 2015		December 31, 2014
Greenfield LP	50%	$	69	$	78
Whitby	50%	19		17
Total investments in power plants		$	88	$	95

Our risk of loss related to our unconsolidated VIEs is limited to our investment balance. Holders of the debt of our unconsolidated investments do not have recourse to Calpine Corporation and its other subsidiaries; therefore, the debt of our unconsolidated investments is not reflected on our Consolidated Condensed Balance Sheets. At March 31, 2015 and December 31, 2014, equity method investee debt was approximately $310 million and $342 million, respectively, and based on our pro rata share of each of the investments, our share of such debt would be approximately $155 million and $171 million at March 31, 2015 and December 31, 2014, respectively.

Our equity interest in the net income from Greenfield LP and Whitby for the three months ended March 31, 2015 and 2014, is recorded in (income) from unconsolidated investments in power plants on our Consolidated Condensed Statements of Operations. The following table sets forth details of our (income) from unconsolidated investments in power plants for the periods indicated (in millions):



	Three Months Ended March 31,
	2015			2014
Greenfield LP	$	(2	)	$	(5	)
Whitby	(3		)	(4		)
Total	$	(5	)	$	(9	)

Distributions from Greenfield LP were nil during each of the three months ended March 31, 2015, and 2014. Distributions from Whitby were nil and $13 million during the three months ended March 31, 2015 and 2014, respectively.

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

Significant Unconsolidated Subsidiary — Whitby met the criteria of a significant unconsolidated subsidiary for the three months ended March 31, 2015, based upon the relationship of our equity income from our investment to our consolidated net loss before taxes. The summarized financial data for Whitby for the three months ended March 31, 2015 and 2014, are set forth below (in millions):

Whitby

Condensed Statements of Operations

(Unaudited)



	Three Months Ended March 31,
	2015		2014
Revenues	$	15	$	15
Operating expenses	9		7
Net income	$	6	$	8


3.	Debt

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



	March 31, 2015		December 31, 2014
Senior Unsecured Notes	$	3,450	$	2,800
First Lien Term Loans	2,792		2,799
First Lien Notes	1,928		2,075
Project financing, notes payable and other	1,762		1,810
CCFC Term Loans	1,592		1,596
Capital lease obligations	193		202
Subtotal	11,717		11,282
Less: Current maturities	197		199
Total long-term debt	$	11,520	$	11,083

Our effective interest rate on our consolidated debt, excluding the impacts of capitalized interest and mark-to-market gains (losses) on interest rate swaps, decreased to 5.5% for the three months ended March 31, 2015, from 6.2% for the same period in 2014. The issuance of our Senior Unsecured Notes in July 2014 and February 2015 allowed us to reduce our overall cost of debt by replacing a portion of our First Lien Notes with unsecured debt carrying lower interest rates.

Senior Unsecured Notes

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



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

In February 2015, we issued $650 million in aggregate principal amount of 5.5% senior unsecured notes due 2024 in a public offering. The 2024 Senior Unsecured Notes bear interest at 5.5% per annum with interest payable semi-annually on February 1 and August 1 of each year, beginning on August 1, 2015. The 2024 Senior Unsecured Notes were issued at par, mature on February 1, 2024 and contain substantially similar covenants, qualifications, exceptions and limitations as our 2023 Senior Unsecured Notes and 2025 Senior Unsecured Notes. We used the net proceeds received from the issuance of our 2024 Senior Unsecured Notes to replenish cash on hand used for the acquisition of Fore River Energy Center in the fourth quarter of 2014, to repurchase approximately $147 million of our 2023 First Lien Notes and for general corporate purposes. During the first quarter of 2015, we recorded approximately $9 million in deferred financing costs related to the issuance of our 2024 Senior Unsecured Notes and approximately $19 million in debt extinguishment costs related to the partial repurchase of our 2023 First Lien Notes.

First Lien Term Loans

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



	March 31, 2015		December 31, 2014
2018 First Lien Term Loans	$	1,593	$	1,597
2019 First Lien Term Loan	814		816
2020 First Lien Term Loan	385		386
Total First Lien Term Loans	$	2,792	$	2,799

First Lien Notes

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



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

____________


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

Corporate Revolving Facility and Other Letters of Credit Facilities

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



	March 31, 2015		December 31, 2014
Corporate Revolving Facility⁽¹⁾	$	202	$	223
CDHI	235		214
Various project financing facilities	186		207
Total	$	623	$	644

____________


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

Fair Value of Debt

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



	March 31, 2015				December 31, 2014
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Unsecured Notes	$	3,462	$	3,450	$	2,832	$	2,800
First Lien Term Loans	2,795		2,792		2,769		2,799
First Lien Notes	2,091		1,928		2,247		2,075
Project financing, notes payable and other⁽¹⁾	1,691		1,655		1,734		1,688
CCFC Term Loans	1,580		1,592		1,540		1,596
Total	$	11,619	$	11,417	$	11,122	$	10,958

____________


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

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


4.	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 March 31, 2015 and December 31, 2014, by level within the fair value hierarchy:



	Assets and Liabilities with Recurring Fair Value Measures as of March 31, 2015
	Level 1		Level 2		Level 3		Total
	(in millions)
Assets:
Cash equivalents⁽¹⁾	$	965	$	—	$	—	$	965
Margin deposits	107		—		—		107
Commodity instruments:
Commodity exchange traded futures and swaps contracts	2,037		—		—		2,037
Commodity forward contracts⁽²⁾	—		295		233		528
Interest rate swaps	—		4		—		4
Total assets	$	3,109	$	299	$	233	$	3,641
Liabilities:
Margin deposits posted with us by our counterparties	$	40	$	—	$	—	$	40
Commodity instruments:
Commodity exchange traded futures and swaps contracts	1,814		—		—		1,814
Commodity forward contracts⁽²⁾	—		253		30		283
Interest rate swaps	—		118		—		118
Total liabilities	$	1,854	$	371	$	30	$	2,255



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

___________


(1)	As of March 31, 2015 and December 31, 2014, we had cash equivalents of $757 million and $679 million included in cash and cash equivalents and $208 million and $217 million included in restricted cash, respectively.


(2)	Includes OTC swaps and options.

At March 31, 2015 and December 31, 2014, the derivative instruments classified as level 3 primarily included commodity contracts, which are classified as level 3 because the contract terms relate to a delivery location or tenor for which observable market rate information is not available. The fair value of the net derivative position classified as level 3 is predominantly driven by market commodity prices. The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at March 31, 2015 and December 31, 2014:



	Quantitative Information about Level 3 Fair Value Measurements
	March 31, 2015
	Fair Value, Net Asset			Significant Unobservable
	(Liability)		Valuation Technique	Input	Range
	(in millions)
Power Contracts	$	201	Discounted cash flow	Market price (per MWh)	$13.43 — $123.25/MWh

	December 31, 2014
	Fair Value, Net Asset			Significant Unobservable
	(Liability)		Valuation Technique	Input	Range
	(in millions)
Power Contracts	$	74	Discounted cash flow	Market price (per MWh)	$14.00 — $122.79/MWh
Natural Gas Contracts	$	5	Discounted cash flow	Market price (per MMBtu)	$1.00 — $10.86/MMBtu
Power Congestion Products	$	9	Discounted cash flow	Market price (per MWh)	$(19.56) — $19.56/MWh

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



	Three Months Ended March 31,
	2015			2014
Balance, beginning of period	$	85		$	14
Realized and mark-to-market gains (losses):
Included in net loss:
Included in operating revenues⁽¹⁾	131			(10		)
Included in fuel and purchased energy expense⁽²⁾	3			5
Purchases and settlements:
Purchases	2			1
Settlements	(10		)	(3		)
Transfers in and/or out of level 3⁽³⁾:
Transfers into level 3⁽⁴⁾	(1		)	—
Transfers out of level 3⁽⁵⁾	(7		)	1
Balance, end of period	$	203		$	8
Change in unrealized gains (losses) relating to instruments still held at end of period	$	134		$	(5	)

___________


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


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


(3)	We transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no transfers into or out of level 1 for each of the three months ended March 31, 2015 and 2014.


(4)	We had $(1) million in losses transferred out of level 2 into level 3 for the three months ended March 31, 2015. There were no transfers out of level 2 into level 3 for the three months ended March 31, 2014.


(5)	We had $(7) million in gains and $1 million in losses transferred out of level 3 into level 2 for the three months ended March 31, 2015 and 2014, respectively, due to changes in market liquidity in various power markets.


5.	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 months ended March 31, 2015 and 2014.

Interest Rate Swaps — A portion of our debt is indexed to base rates, primarily LIBOR. We have historically used interest rate swaps to adjust the mix between fixed and floating rate debt to hedge our interest rate risk for potential adverse changes in interest rates. As of March 31, 2015, 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 March 31, 2015 and December 31, 2014, the net forward notional buy (sell) position of our outstanding commodity and interest rate swap contracts that did not qualify or were not designated under the normal purchase normal sale exemption were as follows (in millions):



Derivative Instruments	Notional Amounts
Derivative Instruments	March 31, 2015			December 31, 2014
Power (MWh)	(79		)	(62		)
Natural gas (MMBtu)	693			291
Environmental credits (Tonnes)	1			—
Interest rate swaps	$	1,419		$	1,431

Certain of our derivative instruments contain credit risk-related contingent provisions that require us to maintain collateral balances consistent with our credit ratings. If our credit rating were to be downgraded, it could require us to post additional collateral or could potentially allow our counterparty to request immediate, full settlement on certain derivative instruments in liability positions. Currently, we do not believe that it is probable that any additional collateral posted as a result of a one credit notch downgrade from its current level would be material. The aggregate fair value of our derivative liabilities with credit risk-related contingent provisions as of March 31, 2015, was $16 million for which we have posted collateral of $10 million by posting margin deposits or granting additional first priority liens on the assets currently subject to first priority liens under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. However, if our credit rating were downgraded by one notch from its current level, we estimate that additional collateral of $8 million would be required and that no counterparty could request immediate, full settlement.

Accounting for Derivative Instruments

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

Cash Flow Hedges — We 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 months ended March 31, 2015 and 2014, 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 Heat Rate swaps and options) and fuel and purchased energy expense (for natural gas contracts, environmental product contracts, swaps and options). Changes in fair value of interest rate derivatives not designated as hedging instruments are recognized currently in earnings as interest expense.

Derivatives Included on Our Consolidated Condensed Balance Sheets

The following tables present the fair values of our derivative instruments recorded on our Consolidated Condensed Balance Sheets by location and hedge type at March 31, 2015 and December 31, 2014 (in millions):



	March 31, 2015
	Commodity Instruments		Interest Rate Swaps			Total Derivative Instruments
Balance Sheet Presentation
Current derivative assets	$	1,858	$	—		$	1,858
Long-term derivative assets	707		4			711
Total derivative assets	$	2,565	$	4		$	2,569

Current derivative liabilities	$	1,600	$	43		$	1,643
Long-term derivative liabilities	497		75			572
Total derivative liabilities	$	2,097	$	118		$	2,215
Net derivative asset (liabilities)	$	468	$	(114	)	$	354



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

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



	March 31, 2015				December 31, 2014
	Fair Value of Derivative Assets		Fair Value of Derivative Liabilities		Fair Value of Derivative Assets		Fair Value of Derivative Liabilities
Derivatives designated as cash flow hedging instruments:
Interest rate swaps	$	4	$	117	$	4	$	112
Total derivatives designated as cash flow hedging instruments	$	4	$	117	$	4	$	112

Derivatives not designated as hedging instruments:
Commodity instruments	$	2,565	$	2,097	$	2,493	$	2,112
Interest rate swaps	—		1		—		2
Total derivatives not designated as hedging instruments	$	2,565	$	2,098	$	2,493	$	2,114
Total derivatives	$	2,569	$	2,215	$	2,497	$	2,226

We elected not to offset fair value amounts recognized as derivative instruments on our Consolidated Condensed Balance Sheets that are executed with the same counterparty under master netting arrangements or other contractual netting provisions negotiated with the counterparty. Our netting arrangements include a right to set off or net together purchases and sales of similar products in the margining or settlement process. In some instances, we have also negotiated cross commodity netting rights which allow for the net presentation of activity with a given counterparty regardless of product purchased or sold. We also post cash collateral in support of our derivative instruments which may also be subject to a master netting arrangement with the same counterparty. The tables below set forth our net exposure to derivative instruments after offsetting amounts subject to a master netting arrangement with the same counterparty at March 31, 2015 and December 31, 2014 (in millions):



	March 31, 2015
	Gross Amounts Not Offset on the Consolidated Condensed Balance Sheets
	Gross Amounts Presented on our Consolidated Condensed Balance Sheets			Derivative Asset (Liability) not Offset on the Consolidated Condensed Balance Sheets			Margin/Cash (Received) Posted⁽¹⁾			Net Amount
Derivative assets:
Commodity exchange traded futures and swaps contracts	$	2,037		$	(1,810	)	$	(227	)	$	—
Commodity forward contracts	528			(263		)	(1		)	264
Interest rate swaps	4			—			—			4
Total derivative assets	$	2,569		$	(2,073	)	$	(228	)	$	268
Derivative (liabilities):
Commodity exchange traded futures and swaps contracts	$	(1,814	)	$	1,810		$	4		$	—
Commodity forward contracts	(283		)	263			10			(10		)
Interest rate swaps	(118		)	—			—			(118		)
Total derivative (liabilities)	$	(2,215	)	$	2,073		$	14		$	(128	)
Net derivative assets (liabilities)	$	354		$	—		$	(214	)	$	140



	December 31, 2014
	Gross Amounts Not Offset on the Consolidated Condensed Balance Sheets
	Gross Amounts Presented on our Consolidated Condensed Balance Sheets			Derivative Asset (Liability) not Offset on the Consolidated Condensed Balance Sheets			Margin/Cash (Received) Posted⁽¹⁾			Net Amount
Derivative assets:
Commodity exchange traded futures and swaps contracts	$	2,134		$	(1,865	)	$	(269	)	$	—
Commodity forward contracts	359			(222		)	—			137
Interest rate swaps	4			—			—			4
Total derivative assets	$	2,497		$	(2,087	)	$	(269	)	$	141
Derivative (liabilities):
Commodity exchange traded futures and swaps contracts	$	(1,870	)	$	1,865		$	5		$	—
Commodity forward contracts	(242		)	222			10			(10		)
Interest rate swaps	(114		)	—			—			(114		)
Total derivative (liabilities)	$	(2,226	)	$	2,087		$	15		$	(124	)
Net derivative assets (liabilities)	$	271		$	—		$	(254	)	$	17

____________

(1)

Negative balances represent margin deposits posted with us by our counterparties related to our derivative activities that are subject to a master netting arrangement. Positive balances reflect margin deposits and natural gas and power prepayments posted by us with our counterparties related to our derivative activities that are subject to a master netting arrangement. See Note 6 for a further discussion of our collateral.

Derivatives Included on Our Consolidated Condensed Statements of Operations

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

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



	Three Months Ended March 31,
	2015		2014
Realized gain (loss)⁽¹⁾
Commodity derivative instruments	$	59	$	(39	)
Total realized gain (loss)	$	59	$	(39	)

Mark-to-market gain (loss)⁽²⁾
Commodity derivative instruments	$	70	$	(73	)
Interest rate swaps	1		1
Total mark-to-market gain (loss)	$	71	$	(72	)
Total activity, net	$	130	$	(111	)

___________


(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 March 31,
	2015		2014
Realized and mark-to-market gain (loss)
Derivatives contracts included in operating revenues	$	119	$	(237	)
Derivatives contracts included in fuel and purchased energy expense	10		125
Interest rate swaps included in interest expense	1		1
Total activity, net	$	130	$	(111	)

Derivatives Included in OCI and AOCI

We do not have any commodity derivative instruments that were designated as cash flow hedges during the three months ended March 31, 2015 and 2014. The following table details the effect of our net derivative instruments that qualified for hedge accounting treatment and are included in OCI and AOCI for the periods indicated (in millions):



	Three Months Ended March 31,					Three Months Ended March 31,
	Gain (Loss) Recognized in OCI (Effective Portion)					Gain (Loss) Reclassified from AOCI into Income (Effective Portion)⁽³⁾⁽⁴⁾
	2015			2014		2015			2014			Affected Line Item on the Consolidated Condensed Statements of Operations
Interest rate swaps⁽¹⁾⁽²⁾	$	(6	)	$	—	$	(12	)	$	(13	)	Interest expense

____________


(1)	We did not record any gain (loss) on hedge ineffectiveness related to our interest rate swaps designated as cash flow hedges during the three months ended March 31, 2015 and 2014.


(2)	We recorded an income tax expense of nil for each of the three months ended March 31, 2015 and 2014, 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 $154 million and $149 million at March 31, 2015 and December 31, 2014, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $13 million and $12 million at March 31, 2015 and December 31, 2014, respectively.


(4)	Includes a loss of nil and $5 million for the three months ended March 31, 2015 and 2014, respectively, that was reclassified from AOCI to interest expense, where the hedged transactions are no longer expected to occur.

We estimate that pre-tax net losses of $46 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.


6.	Use of Collateral

We use margin deposits, prepayments and letters of credit as credit support with and from our counterparties for commodity procurement and risk management activities. In addition, we have granted additional first priority liens on the assets currently subject to first priority liens under various debt agreements as collateral under certain of our power and natural gas agreements and certain of our interest rate swap agreements in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to the counterparties under such agreements. The counterparties under such agreements share the benefits of the collateral subject to such first priority liens pro rata with the lenders under our various debt agreements.

The table below summarizes the balances outstanding under margin deposits, natural gas and power prepayments, and exposure under letters of credit and first priority liens for commodity procurement and risk management activities as of March 31, 2015 and December 31, 2014 (in millions):



	March 31, 2015		December 31, 2014
Margin deposits⁽¹⁾	$	107	$	96
Natural gas and power prepayments	21		22
Total margin deposits and natural gas and power prepayments with our counterparties⁽²⁾	$	128	$	118

Letters of credit issued	$	459	$	450
First priority liens under power and natural gas agreements	33		48
First priority liens under interest rate swap agreements	120		116
Total letters of credit and first priority liens with our counterparties	$	612	$	614

Margin deposits posted with us by our counterparties⁽¹⁾⁽³⁾	$	40	$	47
Letters of credit posted with us by our counterparties	60		61
Total margin deposits and letters of credit posted with us by our counterparties	$	100	$	108

___________

(1)

Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated Condensed Balance Sheets. We do not offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation, and we do not offset amounts recognized for the right to reclaim, or the obligation to return, cash collateral with corresponding derivative instrument fair values. See Note 5 for further discussion of our derivative instruments subject to master netting arrangements.


(2)	At March 31, 2015 and December 31, 2014, $115 million and $109 million, respectively, were included in margin deposits and other prepaid expense and $13 million and $9 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets.


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

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


7.	Income Taxes

Income Tax Benefit

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



	Three Months Ended March 31,
	2015			2014
Income tax benefit	$	(1	)	$	(19	)
Effective tax rate	9		%	53		%

Our income tax rates do not bear a customary relationship to statutory income tax rates primarily as a result of the impact of our NOLs, changes in unrecognized tax benefits and valuation allowances. For the three months ended March 31, 2015 and 2014, our income tax 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 2014 Form 10-K for further information regarding our NOLs.

Income Tax Audits — We remain subject to periodic audits and reviews by taxing authorities; however, we do not expect these audits will have a material effect on our tax provision. Any NOLs we claim in future years to reduce taxable income could

be subject to IRS examination regardless of when the NOLs occurred. Any adjustment of state or federal returns would likely result in a reduction of deferred tax assets rather than a cash payment of income taxes in tax jurisdictions where we have NOLs.

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

Unrecognized Tax Benefits — At March 31, 2015, we had unrecognized tax benefits of $54 million. If recognized, $13 million of our unrecognized tax benefits could impact the annual effective tax rate and $41 million, related to deferred tax assets, could be offset against the recorded valuation allowance resulting in no impact on our effective tax rate. We had accrued interest and penalties of $11 million for income tax matters at March 31, 2015. We recognize interest and penalties related to unrecognized tax benefits in income tax benefit on our Consolidated Condensed Statements of Operations.


8.	Loss per Share

We include restricted stock units for which no future service is required as a condition to the delivery of the underlying common stock in our calculation of weighted average shares outstanding. As we incurred a net loss for the three months ended March 31, 2015 and 2014, 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. We excluded the following items from diluted loss per common share for the three months ended March 31, 2015 and 2014, because they were anti-dilutive (shares in thousands):



	Three Months Ended March 31,
	2015	2014
Share-based awards	8,947	8,995


9.	Stock-Based Compensation

Equity Classified Share-Based Awards

Stock-based compensation expense recognized for our equity classified share-based awards was $9 million for each of the three months ended March 31, 2015 and 2014, respectively. We did not record any significant tax benefits related to stock-based compensation expense in any period as we are not benefiting from a significant portion of our deferred tax assets, including deductions related to stock-based compensation expense. In addition, we did not capitalize any stock-based compensation expense as part of the cost of an asset for the three months ended March 31, 2015 and 2014. At March 31, 2015, there was unrecognized compensation cost of $44 million related to restricted stock which is expected to be recognized over a weighted average period of 1.7 years.

A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the three months ended March 31, 2015, is as follows:



	Number of Restricted Stock Awards	Weighted Average Grant-Date Fair Value
Nonvested — December 31, 2014	4,201,868	$	18.01
Granted	1,510,546	$	21.46
Forfeited	70,901	$	18.80
Vested	1,515,774	$	16.36
Nonvested — March 31, 2015	4,125,739	$	19.86

The total fair value of our restricted stock and restricted stock units that vested during the three months ended March 31, 2015 and 2014, was approximately $32 million and $29 million, respectively.

Liability Classified Share-Based Awards

Performance share units granted under the Equity Plan are settled in cash with payouts based on the relative performance of Calpine’s TSR over a three-year performance period compared with the TSR performance of the S&P 500 companies over the same period. The performance share units vest on the last day of the performance period and will be settled in cash; thus, these awards are classified as a liability and measured at fair value using a Monte Carlo simulation model at each reporting date until settlement. Stock-based compensation expense recognized related to our liability classified share-based awards was $2 million and $1 million for the three months ended March 31, 2015 and 2014, respectively.

A summary of our performance share unit activity for the three months ended March 31, 2015, is as follows:



	Number of Performance Share Units	Weighted Average Grant-Date Fair Value
Nonvested — December 31, 2014	867,479	$	21.93
Granted	340,730	$	23.91
Forfeited	37,235	$	21.99
Vested⁽¹⁾	8,254	$	22.56
Nonvested — March 31, 2015	1,162,720	$	22.50

___________


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

For a further discussion of the Calpine Equity Incentive Plans, see Note 12 in our 2014 Form 10-K.


10.	Commitments and Contingencies

Litigation

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

On a quarterly basis, we review our litigation activities and determine if an unfavorable outcome to us is considered “remote,” “reasonably possible” or “probable” as defined by U.S. GAAP. Where we determine an unfavorable outcome is probable and is reasonably estimable, we accrue for potential litigation losses. The liability we may ultimately incur with respect to such litigation matters, in the event of a negative outcome, may be in excess of amounts currently accrued, if any; however, we do not expect that the reasonably possible outcome of these litigation matters would, individually or in the aggregate, have a material adverse effect on our financial condition, results of operations or cash flows. Where we determine an unfavorable outcome is not probable or reasonably estimable, we do not accrue for any potential litigation loss. The ultimate outcome of these litigation matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated. As a result, we give no assurance that such litigation matters would, individually or in the aggregate, not have a material adverse effect on our financial condition, results of operations or cash flows.

Environmental Matters

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

Bay Area Air Quality Management District (“BAAQMD”). On March 13, 2014, the Hearing Board of the BAAQMD entered into a stipulated conditional order for abatement agreed to by Russell City Energy Company, LLC (“RCEC”), our indirect, majority-owned subsidiary, and the BAAQMD concerning a violation of the vendor-guaranteed water droplet drift rate for RCEC’s cooling tower discovered during initial performance testing. RCEC installed additional drift eliminators and came into compliance with its water droplet drift rate on April 17, 2014. The BAAQMD 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.


11.	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. During the third quarter of 2014, we altered the composition of our geographic segments to combine our former North and Southeast segments into one segment which was renamed the East segment. This change reflects the manner in which our geographic information is presented internally to our chief operating decision maker following the sale of six power plants in July 2014 from what was formerly our Southeast segment. Thus, beginning in the third quarter of 2014, our reportable segments were West (including geothermal), Texas and East (including Canada). We continue to evaluate the manner in which we assess our performance, including our segments, which may result in future changes to the composition of our geographic segments.

Commodity Margin is a key operational measure reviewed by our chief operating decision maker to assess the performance of our segments. The tables below show our financial data for our segments for the periods indicated (in millions).



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



	Three Months Ended March 31, 2014
	West		Texas			East			Consolidation and Elimination			Total
Revenues from external customers	$	491	$	647		$	827		$	—		$	1,965
Intersegment revenues	2		12			17			(31		)	—
Total operating revenues	$	493	$	659		$	844		$	(31	)	$	1,965
Commodity Margin⁽²⁾	$	202	$	121		$	322		$	—		$	645
Add: Mark-to-market commodity activity, net and other⁽¹⁾	29		(46		)	(11		)	(9		)	(37		)
Less:
Plant operating expense	105		90			79			(9		)	265
Depreciation and amortization expense	60		42			51			—			153
Sales, general and other administrative expense	10		12			12			(1		)	33
Other operating expenses	12		2			7			1			22
(Income) from unconsolidated investments in power plants	—		—			(9		)	—			(9		)
Income (loss) from operations	44		(71		)	171			—			144
Interest expense, net of interest income												165
Debt extinguishment costs and other (income) expense, net												11
Loss before income taxes												$	(32	)

_________


(1)	Includes $(24) million and $(29) million of lease levelization and $4 million and $4 million of amortization expense for the three months ended March 31, 2015 and 2014, respectively.


(2)	Commodity Margin related to the six power plants sold in our East segment on July 3, 2014, was $39 million for the three months ended March 31, 2014.


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

Forward-Looking Information

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

Introduction and Overview

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

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

Our capital allocation philosophy seeks to maximize levered cash returns to equity on a per share basis. We currently consider the repurchases of our own shares of common stock as an attractive investment opportunity, and we utilize the expected returns from this investment as the benchmark against which we evaluate all other capital allocation decisions. We believe this philosophy closely aligns our objectives with those of our shareholders.

Our goal is to be recognized as the premier power generation company in the U.S. as measured by our employees, shareholders, customers and policy-makers as well as the communities in which our facilities are located. We seek to achieve sustainable growth through financially disciplined power plant development, construction, acquisition, operation and ownership, and by pursuing opportunities to improve our fleet performance and reduce operating costs. We continue to make significant progress to deliver financially disciplined growth, to enhance shareholder value through disciplined capital allocation including the return of capital to shareholders and to manage the balance sheet for future growth and success with the following achievements during 2015:


•	We produced more than 26 million MWh of electricity during the first quarter of 2015, a record high for our fleet for the first quarter.


•	Our entire fleet achieved a forced outage factor of 1.4% and a starting reliability of 97.8% during the three months ended March 31, 2015.


•	In 2015, through the filing of this Report, we repurchased a total of 10.8 million shares of our common stock for approximately $236 million at an average price of $21.73 per share.


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


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

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 and East (including Canada).

Our portfolio, including partnership interests, consists of 87 power plants, including one under construction located throughout 18 states in the U.S. and in Canada, with an aggregate current generation capacity of 26,548 MW and 309 MW under construction. Our fleet, including projects under construction, consists of 71 natural gas-fired combustion turbine-based plants, one fuel oil-fired steam-based plant, 14 geothermal steam turbine-based plants and one photovoltaic solar plant. Our segments have an aggregate generation capacity of 7,524 MW in the West, 9,427 MW in Texas and 9,597 MW with an additional 309 MW under construction in the East.

Legislative and Regulatory Update

We are subject to complex and stringent energy, environmental and other laws and regulations at the federal, state and local levels as well as rules within the ISO and RTO markets in which we participate. Federal and state legislative and regulatory actions, including those by ISO/RTOs, continue to change how our business is regulated. We are actively participating in these debates at the federal, regional, state and ISO/RTO levels. Significant updates are discussed below. For a further discussion of the environmental and other governmental regulations that affect us, see “— Governmental and Regulatory Matters” in Part I, Item 1 of our 2014 Form 10-K.

CAISO

The CPUC and CAISO continue to evaluate capacity procurement policies and products for the California power market. With the expectation of significant increases in renewables, both entities are evaluating the need for operational flexibility, including the ability to start and ramp quickly as well as the ability to operate efficiently at low output levels or cycle off. We are an active participant in these discussions and support products and policies that would provide appropriate compensation for the required attributes. As these proceedings are ongoing, we cannot predict the ultimate impact on our financial condition, results of operations or cash flows, 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 that increases as reserve capacity declines. As follow up to the ORDC, stakeholders have approved a rule change that will create a reliability deployment adder and will reflect the value of ISO out of merit actions and correct real time price reversals which is scheduled to be implemented prior to the 2015 peak summer season. The PUCT continues to consider the appropriate reliability standard that should be used to set ERCOT’s planning reserve margin. As these proceedings are ongoing and the timing of these changes is uncertain, we cannot predict the ultimate impact on our financial condition, results of operations or cash flows.

PJM

PJM experienced several unusual cold weather events during January 2014. PJM maintained system reliability, but the system was challenged. In order to address some of these challenges, PJM filed proposed capacity market rule changes in December 2014. If approved by the FERC, these rules would significantly change PJM’s Reliability Pricing Model. PJM’s proposed changes include stronger performance incentives and more significant penalties for failure to perform during peak power system conditions. On March 31, 2015, the FERC requested more information from PJM regarding its proposed changes. Because the request for additional information will delay the FERC in issuing an order on PJM’s proposal, PJM subsequently requested that the FERC allow PJM to postpone the start of its capacity auction from May 11, 2015 to no later than August 10, 2015. On April 24, 2015, the FERC granted PJM’s request. We support PJM’s proposed changes and believe that, overall, they enhance the competitiveness and reliability 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.

ISO-NE

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

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

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 U.S. Court of Appeals for the District of Columbia Circuit (“D.C. Circuit”) invalidating CSAPR. On October 23, 2014, the D.C. Circuit lifted the stay so that CSAPR can be fully implemented. On December 3, 2014, the EPA issued administrative regulations and a Notice of Data Availability that clearly defined requirements for implementation of CSAPR. As a result of the U.S. Supreme Court ruling and the EPA’s subsequent regulations, CSAPR became effective on January 1, 2015, including all of the original provisions of CSAPR, with a three year delay on the timelines proposed in the original rule provisions. The D.C. Circuit heard oral arguments regarding the remaining legal issues on February 25, 2015.

On April 15, 2014, the D.C. Circuit rejected all legal challenges to the EPA’s MATS regulation in the White Stallion Energy Center, LLC, et al v. EPA. case, which included challenges by over 20 states, industry groups and companies. On July 14, 2014, three petitions for a writ of certiorari were filed with the U.S. Supreme Court in conjunction with the D.C. Circuit’s action. On November 25, 2014, the U.S. Supreme Court granted the petitions on the limited issue of the consideration of costs in the determination of the regulation of hazardous air pollutants. The U.S. Supreme Court heard oral arguments on March 25, 2015.

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

GHG Emissions

In 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 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. 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. In June 2014, the EPA also proposed GHG NSPS provisions for modified and reconstructed sources (the “Modification/Reconstruction Rule”). In January 2015, the EPA announced that the GHG NSPS, the Modification/Reconstruction Rule and the Clean Power Plan would be finalized by summer 2015. We believe that our competitive position is enhanced by regulations that ensure all power plants take the necessary steps to reduce their pollutant emissions.

Demand Response Resources

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

RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 2015 AND 2014

Below are our results of operations for the three months ended March 31, 2015 as compared to the same period in 2014 (in millions, except for percentages and operating performance metrics). In the comparative tables below, increases in revenue/income or decreases in expense (favorable variances) are shown without brackets while decreases in revenue/income or increases in expense (unfavorable variances) are shown with brackets.



	2015			2014			Change			% Change
Operating revenues:
Commodity revenue	$	1,638		$	2,048		$	(410	)	(20	)
Mark-to-market gain (loss)	3			(86		)	89			#
Other revenue	5			3			2			67
Operating revenues	1,646			1,965			(319		)	(16	)
Operating expenses:
Fuel and purchased energy expense:
Commodity expense	1,077			1,370			293			21
Mark-to-market (gain)	(67		)	(13		)	54			#
Fuel and purchased energy expense	1,010			1,357			347			26
Plant operating expense	260			265			5			2
Depreciation and amortization expense	158			153			(5		)	(3	)
Sales, general and other administrative expense	37			33			(4		)	(12	)
Other operating expenses	20			22			2			9
Total operating expenses	1,485			1,830			345			19
(Income) from unconsolidated investments in power plants	(5		)	(9		)	(4		)	(44	)
Income from operations	166			144			22			15
Interest expense	154			166			12			7
Interest (income)	(1		)	(1		)	—			—
Debt extinguishment costs	19			1			(18		)	#
Other (income) expense, net	2			10			8			80
Loss before income taxes	(8		)	(32		)	24			75
Income tax benefit	(1		)	(19		)	(18		)	(95	)
Net loss	(7		)	(13		)	6			46
Net income attributable to the noncontrolling interest	(3		)	(4		)	1			25
Net loss attributable to Calpine	$	(10	)	$	(17	)	$	7		41



	2015		2014		Change		% Change
Operating Performance Metrics:
MWh generated (in thousands)⁽¹⁾	25,567		22,977		2,590		11
Average availability	89.4	%	88.4	%	1.0	%	1
Average total MW in operation⁽¹⁾	25,768		27,693		(1,925	)	(7	)
Average capacity factor, excluding peakers	52.0	%	43.2	%	8.8	%	20
Steam Adjusted Heat Rate	7,262		7,353		91		1

__________


#	Variance of 100% or greater


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

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

Commodity revenue, net of Commodity expense, decreased $117 million for the three months ended March 31, 2015, compared to the same period in 2014, primarily due to:


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


•	the sale of six power plants with a total capacity of 3,498 MW in our East segment in July 2014, partially offset by the acquisition of our Guadalupe and Fore River Energy Centers in February and November 2014, respectively, and the completion of the expansions of our Deer Park and Channel Energy Centers in June 2014; and


•	lower regulatory capacity revenue in PJM; partially offset by


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

Generation increased 11% primarily due to the acquisition of our Guadalupe and Fore River Energy Centers in February and November of 2014, respectively, the completion of the expansions of our Deer Park and Channel Energy Centers in June 2014 and higher off-peak Spark Spreads in our Texas segment partially offset by the sale of six power plants in July 2014. Our average total MW in operation decreased by 1,925 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 increased favorably by $143 million for the three months ended March 31, 2015, compared to the same period in 2014, primarily driven by a decrease in forward power prices resulting from lower natural gas prices, which favorably impacted our power hedges.

Plant operating expense decreased by $5 million for the three months ended March 31, 2015, compared to the same period in 2014, primarily due to the aforementioned changes in our power plant portfolio.

Income from unconsolidated investments in power plants decreased by $4 million for the three months ended March 31, 2015, compared to the same period in 2014, primarily due to a decrease in power and natural gas prices as well as an 11% decrease in the Canadian-U.S. dollar exchange rate.

Interest expense decreased by $12 million for the three months ended March 31, 2015, compared to the same period in 2014, primarily due to a decrease in our annual effective interest rate on our consolidated debt, excluding the impacts of capitalized interest and mark-to-market gains (losses) on interest rate swaps, to 5.5% for the three months ended March 31, 2015, from 6.2% for the three months ended March 31, 2014. The issuance of our Senior Unsecured Notes in July 2014 and February 2015 allowed us to reduce our overall cost of debt by replacing a portion of our First Lien Notes with unsecured debt carrying lower interest rates.

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

Other (income) expense, net decreased by $8 million for the three months ended March 31, 2015, compared to the same period in 2014, primarily due to an increase in an estimate for a legal reserve during the three months ended March 31, 2014.

During the three months ended March 31, 2015, we recorded an income tax benefit of $1 million compared to an income tax benefit of $19 million for the same period in 2014. The unfavorable period-over-period change primarily resulted from the recognition of a one-time tax benefit during the first quarter of 2014 associated with reorganization of certain Calpine subsidiaries.

COMMODITY MARGIN AND ADJUSTED EBITDA

Management’s Discussion and Analysis of Financial Condition and Results of Operations includes financial information prepared in accordance with U.S. GAAP, as well as the non-GAAP financial measures, Commodity Margin and Adjusted EBITDA, discussed below, which we use as measures of our performance. Generally, a non-GAAP financial measure is a numerical measure

of financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with U.S. GAAP.

We use Commodity Margin, a non-GAAP financial measure, to assess our performance by our reportable segments. Commodity Margin includes our power and steam revenues, sales of purchased power and physical natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, environmental compliance expense, and realized settlements from our marketing, hedging, optimization and trading activities, but excludes mark-to-market activity and other revenues. We believe that Commodity Margin is a useful tool for assessing the performance of our core operations and is a key operational measure reviewed by our chief operating decision maker. Commodity Margin is not a measure calculated in accordance with U.S. GAAP and should be viewed as a supplement to and not a substitute for our results of operations presented in accordance with U.S. GAAP. Commodity Margin does not intend to represent income from operations, the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. See Note 11 of the Notes to Consolidated Condensed Financial Statements for a reconciliation of Commodity Margin to income (loss) from operations by segment.

Commodity Margin by Segment for the Three Months Ended March 31, 2015 and 2014

The following tables show our Commodity Margin and related operating performance metrics by segment for the three months ended March 31, 2015 and 2014 (exclusive of the noncontrolling interest). In the comparative tables below, favorable variances are shown without brackets while unfavorable variances are shown with brackets. The MWh generated by segment below represent generation from power plants that we both consolidate and operate.



West:	2015			2014			Change			% Change
Commodity Margin (in millions)	$	218		$	202		$	16		8
Commodity Margin per MWh generated	$	30.06		$	22.87		$	7.19		31

MWh generated (in thousands)	7,253			8,831			(1,578		)	(18	)
Average availability	88.3		%	89.0		%	(0.7		)%	(1	)
Average total MW in operation	7,524			7,524			—			—
Average capacity factor, excluding peakers	47.7		%	58.2		%	(10.5		)%	(18	)
Steam Adjusted Heat Rate	7,301			7,248			(53		)	(1	)

West — Commodity Margin in our West segment increased by $16 million, or 8%, for the three months ended March 31, 2015 compared to the three months ended March 31, 2014, primarily due to higher contribution from hedges and higher REC revenues associated with our Geysers Assets resulting from more favorable REC pricing in 2015. Generation decreased 18% during the first quarter of 2015 compared to the first quarter of 2014 primarily due to lower generation at power plants contracted and dispatched by third parties, an increase in hydroelectric generation in the Pacific Northwest and lower market Spark Spreads resulting from lower natural gas prices, despite relatively unchanged Market Heat Rates.



Texas:	2015			2014			Change			% Change
Commodity Margin (in millions)	$	149		$	121		$	28		23
Commodity Margin per MWh generated	$	12.91		$	17.59		$	(4.68	)	(27	)

MWh generated (in thousands)	11,544			6,877			4,667			68
Average availability	88.1		%	82.7		%	5.4		%	7
Average total MW in operation	9,191			8,157			1,034			13
Average capacity factor, excluding peakers	58.2		%	39.0		%	19.2		%	49
Steam Adjusted Heat Rate	7,096			7,151			55			1

Texas — Commodity Margin in our Texas segment increased by $28 million, or 23%, for the three months ended March 31, 2015 compared to the three months ended March 31, 2014, due to the acquisition of our 1,000 MW Guadalupe Energy Center on February 26, 2014, the expansions of our Deer Park and Channel Energy Centers which were completed in June 2014, higher contribution from hedges and higher off-peak Spark Spreads driven by lower system-wide coal-fired generation during the first quarter of 2015. The increase in Commodity Margin was partially offset by lower on-peak Spark Spreads resulting from lower natural gas prices during the first quarter of 2015 compared to the first quarter of 2014. Our average capacity factor, excluding

peakers, increased 49% resulting from higher off-peak Spark Spreads driven by lower coal-fired generation during the first quarter of 2015.



East:	2015			2014			Change			% Change
Commodity Margin (in millions)	$	168		$	322		$	(154	)	(48	)
Commodity Margin per MWh generated	$	24.82		$	44.30		$	(19.48	)	(44	)

MWh generated (in thousands)	6,770			7,269			(499		)	(7	)
Average availability	91.7		%	92.2		%	(0.5		)%	(1	)
Average total MW in operation	9,053			12,012			(2,959		)	(25	)
Average capacity factor, excluding peakers	47.9		%	35.3		%	12.6		%	36
Steam Adjusted Heat Rate	7,516			7,663			147			2

East — Commodity Margin in our East segment decreased by $115 million for the three months ended March 31, 2015 compared to the three months ended March 31, 2014, after excluding a decrease of $39 million resulting from the sale of six power plants with a total capacity of 3,498 MW on July 3, 2014. The decrease in Commodity Margin was primarily due to a significant decrease in power and natural gas prices in the first quarter of 2015 compared to the prior year period, given the unusually high price levels experienced during the polar vortex events in the first quarter of 2014, as well as lower regulatory capacity revenues in PJM. The decrease in Commodity Margin was partially offset by the acquisition of our 731 MW Fore River Energy Center in November 2014 and higher contribution from hedges during the first quarter of 2015 compared to the first quarter of 2014. Generation decreased 7% primarily due to the sale of six power plants in 2014, partially offset by the acquisition of Fore River Energy Center, which were also the primary drivers of a 2,959 MW, or 25%, decrease in our average total MW in operation as well as the 36% increase in our average capacity factor, excluding peakers.

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 agreements and any extraordinary, unusual or non-recurring items plus adjustments to reflect the Adjusted EBITDA from our unconsolidated investments. We adjust for these items in our Adjusted EBITDA as our management believes that these items would distort their ability to efficiently view and assess our core operating trends.

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

During the third quarter of 2014, we altered the composition of our geographic segments to combine our former North and Southeast segments into one segment which was renamed the East segment. This change reflects the manner in which our geographic information is presented internally to our chief operating decision maker following the sale of six power plants in July

2014 from what was formerly our Southeast segment. Thus, beginning in the third quarter of 2014, our reportable segments are West (including geothermal), Texas and East (including Canada). The tables below have been revised to present our segments on this revised basis for all periods.

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



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



	Three Months Ended March 31, 2014
	West			Texas			East⁽³⁾			Consolidation and Elimination		Total
Net loss attributable to Calpine												$	(17	)
Net income attributable to the noncontrolling interest												4
Income tax benefit												(19		)
Debt extinguishment costs and other (income) expense, net												11
Interest expense, net of interest income												165
Income (loss) from operations	$	44		$	(71	)	$	171		$	—	$	144
Add:
Adjustments to reconcile income (loss) from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs⁽¹⁾	58			42			51			—		151
Major maintenance expense	28			37			16			—		81
Operating lease expense	2			—			7			—		9
Mark-to-market loss on commodity derivative activity	4			53			16			—		73
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude noncontrolling interest⁽²⁾	(4		)	—			7			—		3
Stock-based compensation expense	4			3			3			—		10
Acquired contract amortization	—			—			4			—		4
Other	(23		)	—			(6		)	—		(29		)
Total Adjusted EBITDA	$	113		$	64		$	269		$	—	$	446

____________


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


(2)	Adjustments to reflect Adjusted EBITDA from unconsolidated investments include (gain) loss on mark-to-market activity of nil for the three months ended March 31, 2015 and 2014.


(3)	Adjusted EBITDA related to the six power plants sold in our East segment on July 3, 2014 was $20 million for the three months ended March 31, 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 March 31, 2015 and December 31, 2014 (in millions):



	March 31, 2015		December 31, 2014
Cash and cash equivalents, corporate⁽¹⁾	$	717	$	460
Cash and cash equivalents, non-corporate	79		257
Total cash and cash equivalents	796		717
Restricted cash	209		244
Corporate Revolving Facility availability	1,298		1,277
CDHI letter of credit facility availability	65		86
Total current liquidity availability	$	2,368	$	2,324

____________


(1)	Includes $40 million and $47 million of margin deposits posted with us by our counterparties at March 31, 2015 and December 31, 2014, respectively.

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

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

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

We have never paid cash dividends on our common stock. Future cash dividends, if any, may be authorized at the discretion of our Board of Directors and will depend upon, among other things, our future operations and earnings, capital requirements, general financial condition, contractual and financing restrictions and such other factors as our Board of Directors may deem relevant.

Liquidity Sensitivity

Significant changes in commodity prices and Market Heat Rates can have an impact on our liquidity as we use margin deposits, cash prepayments and letters of credit as credit support (collateral) with and from our counterparties for commodity procurement and risk management activities. Utilizing our portfolio of transactions subject to collateral exposure, we estimate that as of April 15, 2015, an increase of $1/MMBtu in natural gas prices would result in an increase of collateral required by approximately $233 million. If natural gas prices decreased by $1/MMBtu, we estimate that our collateral requirements would decrease by approximately $224 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 April 15, 2015, an increase of 500 Btu/KWh in the Market Heat Rate would result in an increase in collateral required by approximately $37 million. If Market Heat Rates were to fall at a similar rate, we estimate that our collateral required would

decrease by $37 million. These amounts are not necessarily indicative of the actual amounts that could be required, which may be higher or lower than the amounts estimated above, and also exclude any correlation between the changes in natural gas prices and Market Heat Rates that may occur concurrently. These sensitivities will change as new contracts or hedging activities are executed.

In order to effectively manage our future Commodity Margin, we have economically hedged a portion of our generation and natural gas portfolio mostly through power and natural gas forward physical and financial transactions; however, we currently remain susceptible to significant price movements for 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.

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 March 31, 2015 and December 31, 2014 (in millions):



	March 31, 2015		December 31, 2014
Corporate Revolving Facility	$	202	$	223
CDHI	235		214
Various project financing facilities	186		207
Total	$	623	$	644

Capital Management

In connection with our goals of enhancing long-term shareholder value, we have completed, made progress toward completing or initiated certain key capital management transactions during 2015, as further described below.

Share Repurchase Program

In 2015, through the filing of this Report, we have repurchased a total of 10.8 million shares of our common stock for approximately $236 million at an average price of $21.73 per share.

2024 Senior Unsecured Notes

In February 2015, we issued $650 million in aggregate principal amount of 5.5% senior unsecured notes due 2024 in a public offering and used the net proceeds to replenish cash on hand used for the acquisition of Fore River Energy Center in the fourth quarter of 2014, to repurchase approximately $147 million of our 2023 First Lien Notes and for general corporate purposes. See Note 3 of the Notes to Consolidated Condensed Financial Statements for a further description of our 2024 Senior Unsecured Notes.

Managing and Growing our Portfolio

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

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. Once complete, the power plant will feature one combustion turbine, one heat recovery steam generator and one steam turbine. 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 of the Garrison Energy Center.

York 2 Energy Center — York 2 Energy Center is a 760 MW dual fuel combined-cycle project that will be co-located with our York Energy Center in Peach Bottom Township, Pennsylvania. Once complete, the power plant will feature two combustion turbines, two heat recovery steam generators and one steam turbine. The project’s capacity cleared PJM’s 2017/2018 base residual auction and we expect COD during the second quarter of 2017. We executed a preliminary notice to proceed for the engineering, procurement and construction agreement during the fourth quarter of 2014 and are currently pursuing key permits and approvals for the project. PJM has completed the feasibility study for increasing York 2 Energy Center’s planned capacity by 120 MW and the queue position has entered the system impact study stage.

Guadalupe Peaking Energy Center — In April 2015, we executed an agreement with Guadalupe Valley Electric Cooperative (“GVEC”) that will facilitate the construction of a 418 MW natural gas-fired peaking power plant to be co-located with our Guadalupe Energy Center. Under the terms of the agreement, construction of the Guadalupe Peaking Energy Center (“GPEC”) may commence at our discretion, so long as the power plant reaches COD between the dates of June 1, 2017, and June 1, 2019. When the power plant begins commercial operation, GVEC will purchase a 50% ownership interest in GPEC. Once built, GPEC will feature two fast-ramping combustion turbines capable of responding to peaks in power demand. This project represents a mutually beneficial response to our customer’s desire to have direct access to peaking generation resources, as it leverages the benefits of our existing site and development rights and our construction and operating expertise, as well as our customer’s ability to fund its investment at attractive rates, all while affording us the flexibility of timing the plant’s construction in response to market pricing signals.

Mankato Power Plant Expansion — By order dated February 5, 2015, the Minnesota Public Utilities Commission concluded a competitive resource acquisition proceeding and selected a 345 MW expansion of our Mankato Power Plant, authorizing execution of a 20-year PPA between Calpine and Xcel Energy. The PPA was executed in April 2015 and remains subject to approval by the North Dakota Public Service Commission. Commercial operation of the expanded capacity may commence as early as June 2018, subject to requisite regulatory approvals and applicable contract conditions.

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

Osprey Energy Center — We executed an asset sale agreement during the fourth quarter of 2014 for the sale of our Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million, excluding working capital and other adjustments. In accordance with the asset sale agreement, the sale will be consummated in January 2017 upon the conclusion of a 27-month PPA. The asset sale agreement is subject to federal and state regulatory approval and represents a strategic disposition of a power plant in a wholesale power market dominated by regulated utilities. During the first quarter of 2015, we made the appropriate filings with the FERC requesting approval of the asset sale.

Turbine Modernization — We continue to move forward with our turbine modernization program. Through March 31, 2015, we have completed the upgrade of thirteen Siemens and eight GE turbines totaling approximately 210 MW and have committed to upgrade three additional turbines. In addition, we have begun a program to update our dual-fueled turbines at certain of our power plants in our East segment.

Customer-Oriented Origination Business

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

West


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


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

Texas


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


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


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

East


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

NOLs

We have significant NOLs that will provide future tax deductions when we generate sufficient taxable income during the applicable carryover periods. At December 31, 2014, our consolidated federal NOLs totaled approximately $6.9 billion.

Cash Flow Activities

The following table summarizes our cash flow activities for the three months ended March 31, 2015 and 2014 (in millions):



	2015			2014
Beginning cash and cash equivalents	$	717		$	941
Net cash provided by (used in):
Operating activities	(17		)	123
Investing activities	(128		)	(769		)
Financing activities	224			220
Net increase (decrease) in cash and cash equivalents	79			(426		)
Ending cash and cash equivalents	$	796		$	515

Net Cash Provided By (Used In) Operating Activities

Cash used in operating activities for the three months ended March 31, 2015, was $17 million compared to cash provided by operating activities of $123 million for the three months ended March 31, 2014. The decrease was primarily due to:

•

Income from operations — Income from operations, adjusted for non-cash items, decreased by $110 million for the three months ended March 31, 2015, compared to the three months ended March 31, 2014. Non-cash items consist primarily of depreciation and amortization, income from unconsolidated investments in power plants, net and mark-to-market activity. The decrease in income from operations was primarily driven by a decrease in Commodity revenue, net of Commodity expense for the three months ended March 31, 2015, compared to the three months ended March 31, 2014, primarily from our East segment due to higher power and gas prices during the first quarter of 2014 resulting from extreme weather driven by the polar vortex.

•

Working capital employed — Working capital employed increased by $113 million for the three months ended March 31, 2015, compared to the three months ended March 31, 2014, after adjusting for change in debt, restricted cash and mark-to-market related balances which did not impact cash used in operating activities. The increase was primarily due to a decrease in net accounts receivable/accounts payable balances as a result of lower Commodity Margin in addition to an increase in margin requirements and an increase in inventory balance for the three months ended March 31, 2015 compared to the three months ended March 31, 2014.


•	Interest paid — Cash paid for interest decreased by $79 million to $146 million for the three months ended March 31, 2015, from $225 million for the three months ended March 31, 2014. The decrease was primarily due to the lower effective interest rates year-over-year due to our refinancing activity and the timing of interest payments.


•	Debt extinguishment payments — During the three months ended March 31, 2015, we made cash payments of $18 million related to repurchase penalties for our 2023 First Lien Notes. There was no similar activity for the three months ended March 31, 2014.


•	Return on Investments — During the three months ended March 31, 2014, we received distributions of $13 million from earnings on Whitby. There were no distributions during the first quarter of 2015.

Net Cash Used In Investing Activities

Cash used in investing activities for the three months ended March 31, 2015 was $128 million compared to $769 million for the three months ended March 31, 2014. The decrease was primarily due to:


•	Purchase of Guadalupe Energy Center — During the three months ended March 31, 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 first quarter of 2015.


•	Capital expenditures — Capital expenditures for the three months ended March 31, 2015 were $162 million, an increase of $43 million, compared to expenditures of $119 million for the three months ended March 31, 2014. The increase was primarily due to higher expenditures on construction projects and outages during the first quarter of 2015 as compared to the first quarter of 2014.

•

Restricted cash — Restricted cash decreased $35 million for the three months ended March 31, 2015, compared to a decrease of $6 million for the three months ended March 31, 2014. The decrease was primarily due to payments of principal and interest on project debt and an increase in payments of operating expenses for our Russell City Energy Center, in addition to an increase in funding of the major maintenance reserve account for our Pasadena Power Plant.

Net Cash Provided By Financing Activities

Cash provided by financing activities increased by $4 million to $224 million for the three months ended March 31, 2015, compared to cash provided by financing activities of $220 million for the three months ended March 31, 2014. The increase was primarily due to:


•	CCFC refinancing — During the three months ended March 31, 2014, we received proceeds of $420 million under the CCFC Term Loans, which were used to fund a portion of the purchase price paid in connection with the acquisition of the Guadalupe Energy Center. There was no similar activity during the first quarter of 2015.

•

Proceeds from Senior Unsecured Notes and repurchase of First Lien Notes — During the three months ended March 31, 2015, we received proceeds of $650 million which were used to replenish cash on hand used for the acquisition of the Fore River Energy Center in the fourth quarter of 2014, repay $147 million of our 2023 First Lien Notes and other general corporate purposes. There was no similar activity during the first quarter of 2014.


•	Repayments of project debt, notes payable and other — During the three months ended March 31, 2015, we made repayments of $58 million compared to $43 million for the three months ended March 31, 2014. The increase is primarily related to the repayments on project debt for Russell City Energy Center.


•	Stock repurchases — During the three months ended March 31, 2015, we made payments of $202 million to repurchase our common stock compared to $140 million during the three months ended March 31, 2014.

Off Balance Sheet Arrangements

There have been no material changes to our off balance sheet arrangements from those disclosed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2014 Form 10-K.

RISK MANAGEMENT AND COMMODITY ACCOUNTING

Our commercial hedging and optimization strategies are designed to maximize our risk-adjusted Commodity Margin by leveraging our knowledge, experience and fundamental views on natural gas and power. We actively manage our risk exposures with a variety of physical and financial instruments with varying time horizons. These instruments include PPAs, tolling arrangements, Heat Rate swaps and options, load sales, steam sales, buying and selling standard physical products, buying and selling exchange traded instruments, gas transportation and storage arrangements, electric transmission service and other contracts for the sale and purchase of power products.

We conduct our hedging and optimization activities within a structured risk management framework based on controls, policies and procedures. We monitor these activities through active and ongoing management and oversight, defined roles and responsibilities, and daily risk estimates and reporting. Additionally, we seek to manage the associated risks through diversification, by controlling position sizes, by using portfolio position limits, and by entering into offsetting positions that lock in a margin. We also are exposed to commodity price movements (both profits and losses) in connection with these transactions. These positions are included in and subject to our consolidated risk management portfolio position limits and controls structure. Changes in fair value of commodity positions that do not qualify for or we do not elect either hedge accounting or the normal purchase normal sale exemption are recognized currently in earnings and are separately stated on our Consolidated Condensed Statements of Operations in mark-to-market gain/loss as a component of operating revenues (for power and Heat Rate swaps and options) and fuel and purchased energy expense (for natural gas contracts, environmental product contracts, swaps and options). Our future hedged status and marketing and optimization activities are subject to change as determined by our commercial operations group, Chief Risk Officer, senior management and Board of Directors.

At any point in time, the relative quantity of our products hedged or sold under longer-term contracts is determined by the availability of forward product sales opportunities and our view of the attractiveness of the pricing available for forward sales. We have economically hedged a portion of our expected generation and natural gas portfolio mostly through power and natural gas forward physical and financial transactions; however, we currently remain susceptible to significant price movements for 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 5 of the Notes to Consolidated Condensed Financial Statements for further discussion of our derivative instruments.

The primary factors affecting our market risk and the fair value of our derivatives at any point in time are the volume of open derivative positions (MMBtu, MWh and $ notional amounts); changing commodity market prices, primarily for power and natural gas; our credit standing and that of our counterparties for energy commodity derivatives; and prevailing interest rates for our interest rate swaps. Since prices for power and natural gas and interest rates are volatile, there may be material changes in the fair value of our derivatives over time, driven both by price volatility and the changes in volume of open derivative transactions. Our derivative assets have increased to approximately $2.6 billion at March 31, 2015, when compared to approximately $2.5 billion at December 31, 2014, and our derivative liabilities have remained unchanged at approximately $2.2 billion at both March 31, 2015, and December 31, 2014. The fair value of our level 3 derivative assets and liabilities at March 31, 2015 represent only a small portion of our total assets and liabilities measured at fair value (approximately 6% and 1%, respectively). See Note 4 of the Notes to Consolidated Condensed Financial Statements for further information related to our level 3 derivative assets and liabilities.

The change in fair value of our outstanding commodity and interest rate derivative instruments from January 1, 2015, through March 31, 2015, is summarized in the table below (in millions):



	Commodity Instruments			Interest Rate Swaps			Total
Fair value of contracts outstanding at January 1, 2015	$	381		$	(110	)	$	271
Items recognized or otherwise settled during the period⁽¹⁾⁽²⁾	(114		)	11			(103		)
Fair value attributable to new contracts	18			—			18
Changes in fair value attributable to price movements	189			(15		)	174
Changes in fair value attributable to nonperformance risk	(6		)	—			(6		)
Fair value of contracts outstanding at March 31, 2015⁽³⁾	$	468		$	(114	)	$	354

__________

(1)

Commodity contract settlements consist of the realization of previously recognized gains on contracts not designated as hedging instruments of $127 million (represents a portion of Commodity revenue and Commodity expense as reported on our Consolidated Condensed Statements of Operations) and $13 million related to current period changes in derivative assets and liabilities not reflected in OCI or earnings.


(2)	Interest rate settlements consist of $10 million related to realized losses from settlements of designated cash flow hedges and $1 million related to realized losses from settlements of undesignated interest rate swaps (represents a portion of interest expense as reported on our Consolidated Condensed Statements of Operations).


(3)	Net commodity and interest rate derivative assets and liabilities reported in Notes 4 and 5 of the Notes to Consolidated Condensed Financial Statements.

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



	Three Months Ended March 31,
	2015		2014
Realized gain (loss)⁽¹⁾
Commodity derivative instruments	$	59	$	(39	)
Total realized gain (loss)	$	59	$	(39	)

Mark-to-market gain (loss)⁽²⁾
Commodity derivative instruments	$	70	$	(73	)
Interest rate swaps	1		1
Total mark-to-market gain (loss)	$	71	$	(72	)
Total activity, net	$	130	$	(111	)

____________


(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 March 31,
	2015		2014
Realized and mark-to-market gain (loss)
Derivatives contracts included in operating revenues	$	119	$	(237	)
Derivatives contracts included in fuel and purchased energy expense	10		125
Interest rate swaps included in interest expense	1		1
Total activity, net	$	130	$	(111	)

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

The net fair value of outstanding derivative commodity instruments at March 31, 2015, based on price source and the period during which the instruments will mature, are summarized in the table below (in millions):



Fair Value Source	2015		2016-2017		2018-2019			After 2019		Total
Prices actively quoted	$	184	$	40	$	(1	)	$	—	$	223
Prices provided by other external sources	40		7		1			—		48
Prices based on models and other valuation methods	21		46		43			87		197
Total fair value	$	245	$	93	$	43		$	87	$	468

We measure the energy commodity price risk in our portfolio on a daily basis using a VAR model to estimate the potential one-day risk of loss based upon historical experience resulting from market movements in comparison to internally established thresholds. Our VAR is calculated for our entire portfolio 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 months ended March 31, 2015 and 2014 (in millions):



	2015		2014
Three months ended March 31:
High	$	38	$	52
Low	$	21	$	37
Average	$	30	$	45
As of March 31	$	21	$	39

Due to the inherent limitations of statistical measures such as VAR, the VAR calculation may not capture the full extent of our commodity price exposure. As a result, actual changes in the value of our energy commodity portfolio could be different from the calculated VAR, and could have a material impact on our financial results. In order to evaluate the risks of our portfolio on a comprehensive basis and augment our VAR analysis, we also measure the risk of the energy commodity portfolio using several analytical methods including sensitivity analysis, non-statistical scenario analysis, including stress testing, and daily position report analysis.

Since the fourth quarter of 2012, we have experienced diminished liquidity in the forward commodity markets resulting from a decrease in participation of counterparties in the marketplace with which to transact our hedging activities. Although this occurrence of diminished liquidity has not had a material adverse impact on our results of operations or financial condition, should these conditions persist, it could decrease our ability to hedge our forward commodity price risk and create 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 6 of the Notes to Consolidated Condensed Financial Statements.

Credit Risk — Credit risk relates to the risk of loss resulting from nonperformance or non-payment by our counterparties related to their contractual obligations with us. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. We also have credit risk if counterparties are unable to provide collateral or post margin. We monitor and manage our credit risk through credit policies that include:


•	credit approvals;


•	routine monitoring of counterparties’ credit limits and their overall credit ratings;


•	limiting our marketing, hedging and optimization activities with high risk counterparties;


•	margin, collateral, or prepayment arrangements; and


•	payment netting arrangements, or master netting arrangements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty.

We have concentrations of credit risk with a few of our customers relating to our sales of power, 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 March 31, 2015, and the period during which the instruments will mature are summarized in the table below (in millions):



Credit Quality (Based on Standard & Poor’s Ratings as of March 31, 2015)	2015			2016-2017			2018-2019		After 2019		Total
Investment grade	$	246		$	87		$	34	$	77	$	444
Non-investment grade	(5		)	(4		)	—		—		(9		)
No external ratings	4			10			9		10		33
Total fair value	$	245		$	93		$	43	$	87	$	468

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 $(7) million at March 31, 2015.

New Accounting Standards and Disclosure Requirements

See Note 1 of the Notes to Consolidated Condensed Financial Statements for a discussion of new accounting standards and disclosure requirements.


Item 3.	Quantitative and Qualitative Disclosures About Market Risk

The information required to be disclosed under this Item 3 is set forth under Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Risk Management and Commodity Accounting.” This information should be read in conjunction with the information disclosed in our 2014 Form 10-K.


Item 4.	Controls and Procedures

Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

During the first quarter of 2015, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION


Item 1.	Legal Proceedings

See Note 10 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 2014 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)⁽²⁾
January	4,790,107	$	21.75	4,789,309	$	732
February	2,096,555	$	21.50	1,628,889	$	697
March	2,925,796	$	21.28	2,925,166	$	635
Total	9,812,458	$	21.56	9,343,364	$	635

___________


(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 first quarter of 2015, we withheld a total of 469,094 shares that are included in the total number of shares purchased.


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


Item 3.	Defaults Upon Senior Securities

None.


Item 4.	Mine Safety Disclosures

Not applicable.


Item 5.	Other Information

None.


Item 6.	Exhibits

EXHIBIT INDEX



Exhibit Number		Description
4.1		Third Supplemental Indenture, dated as of February 3, 2015, between the Company and the Trustee, governing the Notes (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed with the SEC on February 3, 2015).

4.2		Form of 2024 Note (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K filed with the SEC on February 3, 2015).

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

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

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

101.INS		XBRL Instance Document.

101.SCH		XBRL Taxonomy Extension Schema.

101.CAL		XBRL Taxonomy Extension Calculation Linkbase.

101.DEF		XBRL Taxonomy Extension Definition Linkbase.

101.LAB		XBRL Taxonomy Extension Label Linkbase.

101.PRE		XBRL Taxonomy Extension Presentation Linkbase.

_______________


*	Furnished herewith.

SIGNATURES

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



CALPINE CORPORATION
(Registrant)

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

Date: April 30, 2015

EXHIBIT INDEX



Exhibit Number		Description
4.1		Third Supplemental Indenture, dated as of February 3, 2015, between the Company and the Trustee, governing the Notes (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed with the SEC on February 3, 2015).

4.2		Form of 2024 Note (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K filed with the SEC on February 3, 2015).

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

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

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

101.INS		XBRL Instance Document.

101.SCH		XBRL Taxonomy Extension Schema.

101.CAL		XBRL Taxonomy Extension Calculation Linkbase.

101.DEF		XBRL Taxonomy Extension Definition Linkbase.

101.LAB		XBRL Taxonomy Extension Label Linkbase.

101.PRE		XBRL Taxonomy Extension Presentation Linkbase.

_______________


*	Furnished herewith.

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