UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

____________________

Form 10-Q

(Mark One)

[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
	OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2012
	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 by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.    Yes [X]    No [    ]

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: 465,563,811 shares of common stock, par value $0.001, were outstanding as of November 1, 2012.

CALPINE CORPORATION AND SUBSIDIARIES

REPORT ON FORM 10-Q

For the Quarter Ended September 30, 2012

INDEX

	Page
Definitions	ii
Forward-Looking Statements	viii
Where You Can Find Other Information	ix
PART I – FINANCIAL INFORMATION
Item 1. Financial Statements	1
Consolidated Condensed Statements of Operations for the Three and Nine Months Ended September 30, 2012 and 2011	1
Consolidated Condensed Statements of Comprehensive Income (Loss) for the Three and Nine Months Ended September 30, 2012 and 2011	2
Consolidated Condensed Balance Sheets at September 30, 2012 and December 31, 2011	3
Consolidated Condensed Statements of Cash Flows for the Nine Months Ended September 30, 2012 and 2011	4
Notes to Consolidated Condensed Financial Statements	6
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	31
Forward-Looking Information	31
Introduction and Overview	31
Results of Operations	39
Commodity Margin and Adjusted EBITDA	44
Liquidity and Capital Resources	52
Risk Management and Commodity Accounting	58
New Accounting Standards and Disclosure Requirements	63
Item 3. Quantitative and Qualitative Disclosures About Market Risk	63
Item 4. Controls and Procedures	63
PART II – OTHER INFORMATION
Item 1. Legal Proceedings	64
Item 1A. Risk Factors	64
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	64
Item 3. Defaults Upon Senior Securities	64
Item 4. Mine Safety Disclosures	64
Item 5. Other Information	64
Item 6. Exhibits	65
Signatures	66

i

DEFINITIONS

As used in this Quarterly Report for the quarter ended September 30, 2012 (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
2011 Form 10-K	Calpine Corporation's Annual Report on Form 10-K for the year ended December 31, 2011, filed with the SEC on February 9, 2012
2017 First Lien Notes	The $1.2 billion aggregate principal amount of 7.25% senior secured notes due 2017, issued October 21, 2009, in exchange for a like principal amount of term loans under the First Lien Credit Facility
2019 First Lien Notes	The $400 million aggregate principal amount of 8.0% senior secured notes due 2019, issued May 25, 2010
2019 First Lien Term Loan	The $835 million first lien senior secured term loan, dated October 9, 2012, among Calpine Corporation, as borrower, and the lenders party hereto, and Morgan Stanley Senior Funding, Inc., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent
2020 First Lien Notes	The $1.1 billion aggregate principal amount of 7.875% senior secured notes due 2020, issued July 23, 2010
2021 First Lien Notes	The $2.0 billion aggregate principal amount of 7.50% senior secured notes due 2021, issued October 22, 2010
2023 First Lien Notes	The $1.2 billion aggregate principal amount of 7.875% senior secured notes due 2023, issued January 14, 2011
AB 32	California Assembly Bill 32
Adjusted EBITDA	EBITDA as adjusted for the effects of (a) impairment charges, (b) major maintenance expense, (c) operating lease expense, (d) unrealized gains or losses on commodity derivative mark-to-market activity, (e) adjustments to reflect only the Adjusted EBITDA from our unconsolidated investments, (f) stock-based compensation expense, (g) gains or losses on sales, dispositions or retirements of assets, (h) non-cash gains and losses from foreign currency translations, (i) gains or losses on the repurchase or extinguishment of debt and (j) 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 generation as a percent of total potential 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
Broad River	Broad River Energy LLC, an indirect, wholly owned subsidiary of Calpine Corporation that leases the Broad River Energy Center from the BR Owner Lessors
Broad River Entities	Collectively, Broad River and the BR Owner Lessors

ii

ABBREVIATION	DEFINITION
BR Owner Lessors	Broad River OL-1, LLC, a Delaware limited liability company, Broad River OL-2, LLC, a Delaware limited liability company, Broad River OL-3, LLC, a Delaware limited liability company, and Broad River OL-4, LLC, a Delaware limited liability company, each of which is an indirect, wholly owned subsidiary of Calpine Corporation, which lease the Broad River Energy Center (i) from Cherokee County, South Carolina and (ii) to Broad River
Broad River Power	Broad River Power, LLC, a wholly owned subsidiary of Energy Capital Partners, LLC
Btu	British thermal unit(s), a measure of heat content
CAA	Federal Clean Air Act, U.S. Code Title 42, Chapter 85
CAIR	Clean Air Interstate Rule
CAISO	California Independent System Operator
Calpine Equity Incentive Plans	Collectively, the Director Plan and the Equity Plan, which provide for grants of equity awards to Calpine non-union employees and non-employee members of Calpine’s Board of Directors
Cap-and-trade	A government imposed emissions reduction program that would place a cap on the amount of emissions that can be emitted from certain sources, such as power plants. In its simplest form, the cap amount is set as a reduction from the total emissions during a base year and for each year over a period of years the cap amount would be reduced to achieve the targeted overall reduction by the end of the period. Allowances or credits for emissions in an amount equal to the cap would be issued or auctioned to companies with facilities, permitting them to emit up to a certain amount of emissions during each applicable period. After allowances have been distributed or auctioned, they can be transferred or traded
CARB	California Air Resources Board
CCFC	Calpine Construction Finance Company, L.P., an indirect, wholly owned subsidiary
CCFC Finance	CCFC Finance Corp.
CCFC Notes	The $1.0 billion aggregate principal amount of 8.0% senior secured notes due 2016, issued May 19, 2009, by CCFC and CCFC Finance
CDHI	Calpine Development Holdings, Inc., an indirect, wholly owned subsidiary
CFTC	U.S. Commodities Futures Trading Commission
Chapter 11	Chapter 11 of the U.S. Bankruptcy Code
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 and cash settlements from our marketing, hedging and optimization activities including natural gas transactions hedging future power sales that are included in our mark-to-market activity in fuel and purchased energy expense, but excludes the unrealized portion of our mark-to-market activity

iii

ABBREVIATION	DEFINITION
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 emissions allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, RGGI compliance and other environmental costs, and cash settlements from our marketing, hedging and optimization activities including natural gas transactions hedging future power sales that are included in mark-to-market activity, but excludes the unrealized portion of 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 emissions allowances, transmission revenue, and cash settlements from our marketing, hedging and optimization activities that are included in our mark-to-market activity in operating revenues, but excludes the unrealized portion of our mark-to-market activity
Company	Calpine Corporation, a Delaware corporation, and its subsidiaries
Corporate Revolving Facility	The $1.0 billion aggregate amount revolving credit facility credit agreement, dated as of December 10, 2010, 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
Creed	Creed Energy Center, LLC
Director Plan	The Amended and Restated Calpine Corporation 2008 Director Incentive Plan
Dodd-Frank Act	The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
EBITDA	Net income (loss) attributable to Calpine before net (income) loss attributable to the noncontrolling interest, interest, taxes, depreciation and amortization
Effective Date	January 31, 2008, the date on which the conditions precedent enumerated in the Plan of Reorganization were satisfied or waived and the Plan of Reorganization became effective
Emergence Date Market Capitalization	Calpine Corporation's market capitalization calculated using the weighted average trading price of Calpine Corporation’s common stock over the 30-day period following the date on which it emerged from Chapter 11 bankruptcy protection, as defined in and calculated pursuant to Calpine Corporation’s amended and restated certificate of incorporation and reported in its Current Report on Form 8-K filed with the SEC on March 25, 2008
EPA	U.S. Environmental Protection Agency
Equity Plan	The Amended and Restated Calpine Corporation 2008 Equity Incentive Plan
ERCOT	Electric Reliability Council of Texas
Exchange Act	U.S. Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FDIC	U.S. Federal Deposit Insurance Corporation
FERC	U.S. Federal Energy Regulatory Commission
First Lien Credit Facility	Credit Agreement, dated as of January 31, 2008, as amended by the First Amendment to Credit Agreement and Second Amendment to Collateral Agency and Intercreditor Agreement, dated as of August 20, 2009, among Calpine Corporation, as borrower, certain subsidiaries of the Company named therein, as guarantors, the lenders party thereto, Goldman Sachs Credit Partners L.P., as administrative agent and collateral agent, and the other agents named therein

iv

ABBREVIATION	DEFINITION
First Lien Notes	Collectively, the 2017 First Lien Notes, the 2019 First Lien Notes, the 2020 First Lien Notes, the 2021 First Lien Notes and the 2023 First Lien Notes
First Lien Term Loans	Collectively, the $1.3 billion first lien senior secured term loans dated March 9, 2011 and the $360 million first lien senior secured term loans dated June 17, 2011
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 15 operating power plants and one plant not in operation
GHG(s)	Greenhouse gas(es), primarily carbon dioxide (CO2), and including methane (CH4), nitrous oxide (N2O), sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs) and perfluorocarbons (PFCs)
Goose Haven	Goose Haven Energy Center, LLC
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
IOUs	Investor Owned Utilities
IRC	Internal Revenue Code
ISO(s)	Independent System Operator(s)
KWh	Kilowatt hour(s), a measure of power produced, purchased or sold
LIBOR	London Inter-Bank Offered Rate
Los Esteros Project Debt	Credit Agreement, dated August 23, 2011, between Los Esteros Critical Energy Facility, LLC, as borrower, and the lenders named therein
Market Capitalization	As of any date, Calpine Corporation’s then market capitalization calculated using the rolling 30-day weighted average trading price of Calpine Corporation’s common stock, as defined in and calculated in accordance with the Calpine Corporation amended and restated certificate of incorporation
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
NDH	New Development Holdings, LLC, an indirect, wholly owned subsidiary
NDH Project Debt	The $1.3 billion senior secured term loan facility and the $100 million revolving credit facility issued on July 1, 2010, under the credit agreement, dated as of June 8, 2010, among NDH, as borrower, Credit Suisse AG, as administrative agent, collateral agent, issuing bank and syndication agent, Credit Suisse Securities (USA) LLC, Citigroup Global Markets Inc. and Deutsche Bank Securities Inc., as joint book-runners and joint lead arrangers, Credit Suisse AG, Citibank, N.A., and Deutsche Bank Trust Company Americas, as co-documentation agents and the lenders party thereto repaid on March 9, 2011

v

ABBREVIATION	DEFINITION
NOL(s)	Net operating loss(es)
NOX	Nitrogen oxides
NYMEX	New York Mercantile Exchange
OCI	Other Comprehensive Income
OTC	Over-the-Counter
PG&E	Pacific Gas & Electric Company
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
Plan of Reorganization	Sixth Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the Bankruptcy Code filed by the U.S. Debtors with the U.S. Bankruptcy Court on December 19, 2007, as amended, modified, or supplemented
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
PUHCA 2005	U.S. Public Utility Holding Company Act of 2005
PURPA	U.S. Public Utility Regulatory Policies Act of 1978
QF(s)	Qualifying facility(ies), which are cogeneration facilities and certain small power production facilities eligible to be “qualifying facilities” under PURPA, provided that they meet certain power and thermal energy production requirements and efficiency standards. QF status provides an exemption from the books and records requirement of PUHCA 2005 and grants certain other benefits to the QF
REC(s)	Renewable energy credit(s)
Reserve margin(s)	The measure of how much the total generating capacity installed in a region exceeds the peak demand for power in that region
RGGI	Regional Greenhouse Gas Initiative
Risk Management Policy	Calpine's policy applicable to all employees, contractors, representatives and agents which defines the risk management framework and corporate governance structure for commodity risk, interest rate risk, currency risk and other risks
RPS	Renewable Portfolio Standards
RTO(s)	Regional Transmission Organization(s)
Russell City Project Debt	Credit Agreement dated June 24, 2011, between Russell City Energy Company, LLC, as borrower, and the lenders named therein
SEC	U.S. Securities and Exchange Commission
Securities Act	U.S. Securities Act of 1933, as amended

vi

ABBREVIATION	DEFINITION
SO2	Sulfur dioxide
Spark Spread(s)	The difference between the sales price of power per MWh and the cost of fuel to produce it
Steam Adjusted Heat Rate	The adjusted Heat Rate for our natural gas-fired power plants, excluding peakers, calculated by dividing (a) the fuel consumed in Btu reduced by the net equivalent Btu in steam exported to a third party by (b) the KWh generated. Steam Adjusted Heat Rate is a measure of fuel efficiency, so the lower our Steam Adjusted Heat Rate, the lower our cost of generation
U.S. Bankruptcy Court	U.S. Bankruptcy Court for the Southern District of New York
U.S. Debtor(s)	Calpine Corporation and each of its subsidiaries and affiliates that filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court, which matter was jointly administered in the U.S. Bankruptcy Court under the caption In re Calpine Corporation, et al., Case No. 05-60200 (BRL) and was dismissed on December 19, 2011
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
WP&L	Wisconsin Power and Light Company, a wholly owned subsidiary of Alliant Energy Corporation
York Energy Center	565 MW dual fuel, combined-cycle generation power plant (formerly known as the Delta Project) located in Peach Bottom Township, Pennsylvania which achieved COD on March 2, 2011

vii

Forward-Looking Statements

In addition to historical information, this Quarterly Report on Form 10-Q (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, fluctuations in prices for commodities such as natural gas and power, changes in U.S. macroeconomic conditions, fluctuations in liquidity and volatility in the energy commodities markets and our ability to hedge risks;

• Laws, 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;

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

• Our ability to manage our liquidity needs and to comply with covenants under our First Lien Notes, Corporate Revolving Facility, First Lien Term Loans, 2019 First Lien Term Loan, CCFC Notes and other existing financing obligations;

• Risks associated with the continued economic and financial conditions affecting certain countries in Europe including financial institutions located within those countries and their ability to fund their financial commitments;

• 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 wastewater 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;

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

• Future capacity revenues may not occur at expected levels;

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

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

• Our ability to manage our customer and counterparty exposure and credit risk, including our commodity positions;

• Our ability to attract, motivate and retain key employees;

• Present and possible future claims, litigation and enforcement actions; and

• Other risks identified in this Report and in our 2011 Form 10-K.

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

viii

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.

ix

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(in millions, except share and per share amounts)
Operating revenues	$	1,996		$	2,209		$	4,111		$	5,341
Operating expenses:
Fuel and purchased energy expense	893			1,401			2,137			3,470
Plant operating expense	207			212			699			711
Depreciation and amortization expense	140			143			418			405
Sales, general and other administrative expense	36			33			104			99
Other operating expenses	22			22			67			64
Total operating expenses	1,298			1,811			3,425			4,749
(Income) from unconsolidated investments in power plants	(7		)	(5		)	(21		)	(12		)
Income from operations	705			403			707			604
Interest expense	183			192			552			575
Loss on interest rate derivatives	—			3			14			149
Interest (income)	(2		)	(2		)	(7		)	(7		)
Debt extinguishment costs	—			(4		)	12			94
Other (income) expense, net	6			4			14			14
Income (loss) before income taxes	518			210			122			(221		)
Income tax expense (benefit)	81			20			23			(45		)
Net income (loss)	437			190			99			(176		)
Net income attributable to the noncontrolling interest	—			—			—			(1		)
Net income (loss) attributable to Calpine	$	437		$	190		$	99		$	(177	)
Basic earnings (loss) per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands)	462,307			486,420			470,589			486,363
Net income (loss) per common share attributable to Calpine — basic	$	0.95		$	0.39		$	0.21		$	(0.36	)
Diluted earnings (loss) per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands)	465,953			489,062			474,131			486,363
Net income (loss) per common share attributable to Calpine — diluted	$	0.94		$	0.39		$	0.21		$	(0.36	)

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

1

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(in millions)
Net income (loss)	$	437		$	190		$	99		$	(176	)
Cash flow hedging activities:
Loss on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income (loss)	(22		)	(74		)	(56		)	(60		)
Reclassification adjustment for (gain) loss on cash flow hedges realized in net income (loss)	(1		)	(20		)	(15		)	24
Foreign currency translation gain (loss)	6			(4		)	5			(4		)
Income tax benefit	3			34			7			18
Other comprehensive loss	(14		)	(64		)	(59		)	(22		)
Comprehensive income (loss)	423			126			40			(198		)
Comprehensive (income) attributable to the noncontrolling interest	—			—			—			(1		)
Comprehensive income (loss) attributable to Calpine	$	423		$	126		$	40		$	(199	)

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

2

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited)

	September 30,			December 31,
	2012			2011
	(in millions, except share and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents ($228 and $285 attributable to VIEs)	$	1,097		$	1,252
Accounts receivable, net of allowance of $10 and $13	500			598
Margin deposits and other prepaid expense	143			193
Restricted cash, current ($92 and $57 attributable to VIEs)	163			139
Derivative assets, current	487			1,051
Inventory and other current assets	297			329
Total current assets	2,687			3,562
Property, plant and equipment, net ($4,535 and $4,313 attributable to VIEs)	13,129			13,019
Restricted cash, net of current portion ($62 and $53 attributable to VIEs)	63			55
Investments	79			80
Long-term derivative assets	146			113
Other assets	489			542
Total assets	$	16,593		$	17,371
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	361		$	435
Accrued interest payable ($47 and $19 attributable to VIEs)	163			200
Debt, current portion ($40 and $41 attributable to VIEs)	105			104
Derivative liabilities, current	457			1,144
Other current liabilities	265			279
Total current liabilities	1,351			2,162
Debt, net of current portion ($2,819 and $2,522 attributable to VIEs)	10,567			10,321
Long-term derivative liabilities	286			279
Other long-term liabilities	275			245
Total liabilities	12,479			13,007
Commitments and contingencies (see Note 11)
Stockholders’ equity:
Preferred stock, $0.001 par value per share; authorized 100,000,000 shares, none issued and outstanding	—			—
Common stock, $0.001 par value per share; authorized 1,400,000,000 shares, 492,072,137 and 490,468,815 shares issued, respectively, and 465,572,396 and 481,743,738 shares outstanding, respectively	1			1
Treasury stock, at cost, 26,499,741 and 8,725,077 shares, respectively	(439		)	(125		)
Additional paid-in capital	12,327			12,305
Accumulated deficit	(7,600		)	(7,699		)
Accumulated other comprehensive loss	(237		)	(178		)
Total Calpine stockholders’ equity	4,052			4,304
Noncontrolling interest	62			60
Total stockholders’ equity	4,114			4,364
Total liabilities and stockholders’ equity	$	16,593		$	17,371

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

3

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2012			2011
	(in millions)
Cash flows from operating activities:
Net income (loss)	$	99		$	(176	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization expense(1)	449			431
Debt extinguishment costs	—			82
Deferred income taxes	(7		)	(56		)
Loss on disposition of assets	10			18
Unrealized mark-to-market activities, net	(103		)	42
(Income) from unconsolidated investments in power plants	(21		)	(12		)
Return on unconsolidated investments in power plants	20			6
Stock-based compensation expense	19			18
Other	1			5
Change in operating assets and liabilities:
Accounts receivable	96			(87		)
Derivative instruments, net	(114		)	(6		)
Other assets	97			27
Accounts payable and accrued expenses	(119		)	95
Settlement of non-hedging interest rate swaps	156			147
Other liabilities	25			2
Net cash provided by operating activities	608			536
Cash flows from investing activities:
Purchases of property, plant and equipment	(509		)	(511		)
Settlement of non-hedging interest rate swaps	(156		)	(147		)
Return of investment in unconsolidated investment in power plants	5			—
(Increase) decrease in restricted cash	(32		)	9
Purchases of deferred transmission credits	(12		)	(16		)
Other	3			5
Net cash used in investing activities	(701		)	(660		)
Cash flows from financing activities:
Repayment of First Lien Term Loans	(12		)	—
Borrowings under First Lien Term Loans	—			1,657
Repayments on NDH Project Debt	—			(1,283		)
Issuance of 2023 First Lien Notes	—			1,200
Repayments on First Lien Credit Facility	—			(1,191		)
Borrowings from project financing, notes payable and other	312			223
Repayments of project financing, notes payable and other	(53		)	(476		)
Capital contributions from noncontrolling interest holder	—			34
Financing costs	(6		)	(78		)
Stock repurchases	(308		)	—
Other	5			(4		)
Net cash provided by (used in) financing activities	(62		)	82
Net decrease in cash and cash equivalents	(155		)	(42		)
Cash and cash equivalents, beginning of period	1,252			1,327
Cash and cash equivalents, end of period	$	1,097		$	1,285

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

4

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS — (CONTINUED)

(Unaudited)

	Nine Months Ended September 30,
	2012			2011
	(in millions)
Cash paid during the period for:
Interest, net of amounts capitalized	$	565		$	509
Income taxes	$	14		$	15
Supplemental disclosure of non-cash investing and financing activities:
Change in capital expenditures included in accounts payable	$	(3	)	$	(13	)
Additions to property, plant and equipment through assumption of long-term note payable	$	8		$	—

____________

(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.

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CALPINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

September 30, 2012

(Unaudited)

1. Basis of Presentation and Summary of Significant Accounting Policies

We are an independent 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 the major competitive wholesale power markets in California, Texas and the Mid-Atlantic region of the U.S. We sell wholesale power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities, power marketers and others. We engage in the purchase of natural gas and fuel oil as fuel for our power plants and in related natural gas transportation and storage transactions, and in the purchase of electric transmission rights to deliver power to our customers. We also enter into natural gas and power physical and financial contracts to economically hedge our 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, 2011, included in our 2011 Form 10-K. The results for interim periods are not necessarily indicative of the results for the entire year primarily due to acquisitions and disposals of assets, seasonal fluctuations in our revenues, timing of major maintenance expense, variations resulting from the application of the method to calculate the provision for income tax for interim periods, volatility of commodity prices and unrealized gains and losses from commodity and interest rate derivative contracts.

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

Cash and Cash Equivalents — We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts, which have been pledged as security in favor of the lenders under such project finance facilities, and the use of certain cash balances on deposit in such accounts is limited, at least temporarily, to the operations of the respective projects. At September 30, 2012 and December 31, 2011, we had cash and cash equivalents of $211 million and $306 million, respectively, that were subject to such project finance facilities and lease agreements.

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

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The table below represents the components of our restricted cash as of September 30, 2012 and December 31, 2011 (in millions):

	September 30, 2012						December 31, 2011
	Current		Non-Current		Total		Current		Non-Current		Total
Debt service(1)	$	22	$	42	$	64	$	11	$	42	$	53
Rent reserve	3		—		3		—		—		—
Construction/major maintenance	37		11		48		33		10		43
Security/project/insurance	101		8		109		79		—		79
Other	—		2		2		16		3		19
Total	$	163	$	63	$	226	$	139	$	55	$	194

___________

(1) At September 30, 2012 and December 31, 2011, amounts restricted for debt service included approximately $24 million and $25 million, respectively, of repurchase agreements with a financial institution containing maturity dates greater than one year.

Inventory— At September 30, 2012 and December 31, 2011, we had inventory of $269 million and $294 million, respectively. Inventory primarily consists of spare parts, stored natural gas and fuel oil, emission reduction credits and natural gas exchange imbalances. Inventory, other than spare parts, is stated primarily at the lower of cost or market value under the weighted average cost method. Spare parts inventory is valued at weighted average cost and is expensed to plant operating expense or capitalized to property, plant and equipment as the parts are utilized and consumed.

Property, Plant and Equipment, Net — At September 30, 2012 and December 31, 2011, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):

	September 30, 2012		December 31, 2011
Buildings, machinery and equipment	$	15,150	$	15,074
Geothermal properties	1,212		1,163
Other	158		156
	16,520		16,393
Less: Accumulated depreciation	4,518		4,158
	12,002		12,235
Land	91		91
Construction in progress	1,036		693
Property, plant and equipment, net	$	13,129	$	13,019

Capitalized Interest — The total amount of interest capitalized was $10 million and $6 million for the three months ended September 30, 2012 and 2011, respectively, and $27 million and $17 million for the nine months ended September 30, 2012 and 2011, respectively.

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Leases — We have contracts, such as certain tolling agreements, which we account for as operating leases under U.S. GAAP. Generally, we levelize certain components of these contract revenues on a straight-line basis over the term of the contract. The total contractual future minimum lease rentals for our contracts accounted for as operating leases, excluding tolling agreements related to power plants under construction, at September 30, 2012, are as follows (in millions):

2012	$	114
2013	527
2014	452
2015	461
2016	375
Thereafter	2,270
Total	$	4,199

Treasury Stock — During the nine months ended September 30, 2012, we repurchased common stock with a value of $308 million under our share repurchase program and withheld shares with a value of $6 million to satisfy tax withholding obligations associated with the vesting of restricted stock awarded to employees under the Equity Plan.

New Accounting Standards and Disclosure Requirements

Fair Value Measurement — In May 2011, the FASB issued Accounting Standards Update 2011-04, “Fair Value Measurement” to clarify and amend the application or requirements relating to fair value measurements and disclosures relating to fair value measurements. The update stems from the FASB and the International Accounting Standards Board project to develop common requirements for measuring fair value and for disclosing information about fair value measurements. The update did not impact any of our fair value measurements but did require disclosure of the following:

• quantitative information about the unobservable inputs used in a fair value measurement that is categorized within level 3 of the fair value hierarchy;

• for those fair value measurements categorized within level 3 of the fair value hierarchy, both the valuation processes used and the sensitivity of the fair value measurement to changes in unobservable inputs and the interrelationships between those unobservable inputs, if any; and

• the categorization by level of the fair value hierarchy for items that are not measured at fair value in the statement of financial position but for which the fair value is required to be disclosed.

The new requirements relating to fair value measurements are prospective and effective for interim and annual periods beginning after December 15, 2011, with early adoption prohibited. We adopted all of the requirements related to this update at January 1, 2012. Since this update did not impact any of our fair value measurements and only required additional disclosures, adoption of this standard did not have a material impact on our results of operations, cash flows or financial condition.

Disclosures about Offsetting Assets and Liabilities — In December 2011, the FASB issued Accounting Standards Update 2011-11, “Balance Sheet - Disclosures about Offsetting Assets and Liabilities” to enhance disclosure requirements relating to the offsetting of assets and liabilities on an entity's balance sheet. The update requires enhanced disclosures regarding assets and liabilities that are presented net or gross in the statement of financial position when the right of offset exists, or that are subject to an enforceable master netting arrangement. The new disclosure requirements relating to this update are retrospective and effective for annual and interim periods beginning on or after January 1, 2013. The update only requires additional disclosures, as such, the adoption of this standard will not have a material impact on our results of operations, cash flows or financial condition.

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2. Acquisition and Divestitures

Calpine Bosque Energy Center

On October 3, 2012, we, through our indirect, wholly owned subsidiary Calpine Bosque Energy Center, LLC, agreed to purchase a power plant with a nameplate capacity of 800 MW owned by Bosque Power Co., LLC, for approximately $432 million. The natural gas-fired, combined-cycle power plant will increase capacity in our Texas segment and is located in Central Texas near the unincorporated community of Laguna Park in Bosque County. The site includes a 250 MW generation block with one natural-gas turbine, one heat recovery steam generator and one steam turbine that achieved COD in June 2001 and a 550 MW generation block with two natural-gas turbines that went online in June 2000 as well as two heat recovery steam generators and one steam turbine that achieved COD in June 2011. We expect the transaction to close in November 2012, subject to regulatory approvals, and will fund the acquisition with cash on hand.

Riverside Energy Center

Our 603 MW Riverside Energy Center has a PPA that provides WP&L an option to purchase the power plant and plant-related assets for approximately $392 million upon written notice of exercise prior to May 31, 2012. On May 18, 2012, WP&L exercised their option to purchase Riverside Energy Center, LLC, one of our VIEs which owns Riverside Energy Center. The sale is expected to close in December 2012. The assets being disposed of did not meet the criteria for classification as held for sale under U.S. GAAP, and we do not expect a material gain (loss) on sale. At September 30, 2012, Riverside Energy Center, LLC had total assets of $436 million and total liabilities of $1 million, which includes working capital of approximately $42 million that will not be included in the sale.

Broad River Energy Center

On November 1, 2012, we, through our indirect, wholly owned subsidiary Calpine Power Company, entered into an agreement with Broad River Power to sell 100% of our ownership interests in each of the Broad River Entities for approximately $427 million, including a five year consulting agreement and subject to certain working capital adjustments at closing. Under the agreement, Calpine Power Company will use commercially reasonable efforts to cause Broad River Energy Center to continue to operate and maintain the power plant in the ordinary course of business through the closing of the transaction, which is expected to occur in December 2012, subject to regulatory approvals. We expect to use the sale proceeds to focus more resources on our core markets and for general corporate purposes.

3. Variable Interest Entities and Unconsolidated Investments

We consolidate all of our VIEs where we have determined that we are the primary beneficiary. There were no changes to our determination of whether we are the primary beneficiary of our VIEs for the nine months ended September 30, 2012. See Note 5 in our 2011 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 10,500 MW and 11,391 MW, at September 30, 2012 and December 31, 2011, respectively. For these VIEs, we may provide other operational and administrative support through various affiliate contractual arrangements among the VIEs, Calpine Corporation and its other wholly owned subsidiaries whereby we support the VIE through the reimbursement of costs and/or the purchase and sale of energy. In addition to amounts contractually required, Calpine Corporation provided support to these VIEs in the form of cash and other contributions of nil during each of the three and nine months ended September 30, 2012, and $15 million and $87 million during the three and nine months ended September 30, 2011, respectively.

U.S. GAAP requires separate disclosure on the face of our Consolidated Condensed Balance Sheets of the significant assets of a consolidated VIE that can be used only to settle obligations of the consolidated VIE and the significant liabilities of a consolidated VIE for which creditors (or beneficial interest holders) do not have recourse to the general credit of the primary beneficiary. In determining which assets of our VIEs meet the separate disclosure criteria, we consider that this separate disclosure requirement is met where Calpine Corporation is substantially limited or prohibited from access to assets (primarily cash and cash equivalents, restricted cash and property, plant and equipment), and where our VIEs had project financing that prohibits the VIE from providing guarantees on the debt of others. In determining which liabilities of our VIEs meet the separate disclosure criteria, we consider that this separate disclosure requirement is met where there are agreements that prohibit the debt holders of the VIEs from recourse to the general credit of Calpine Corporation and where the amounts were material to our financial statements.

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Unconsolidated VIEs and Investments

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. We account for these entities under the equity method of accounting and include our net equity interest in investments on our Consolidated Condensed Balance Sheets. At September 30, 2012 and December 31, 2011, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):

	Ownership Interest as of September 30, 2012	September 30, 2012		December 31, 2011
Greenfield LP	50%	$	70	$	72
Whitby	50%	9		8
Total investments		$	79	$	80

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 September 30, 2012 and December 31, 2011, equity method investee debt was approximately $460 million and $462 million, respectively, and based on our pro rata share of each of the investments, our share of such debt would be approximately $230 million and $231 million at September 30, 2012 and December 31, 2011, respectively.

Our equity interest in the net income from Greenfield LP and Whitby for the three and nine months ended September 30, 2012 and 2011 is recorded in (income) from unconsolidated investments in power plants. The following table sets forth details of our (income) from unconsolidated investments in power plants for the periods indicated (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Greenfield LP	$	(5	)	$	(4	)	$	(13	)	$	(5	)
Whitby	(2		)	(1		)	(8		)	(7		)
Total	$	(7	)	$	(5	)	$	(21	)	$	(12	)

Greenfield LP — 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. Greenfield LP holds an 18-year term loan with an original principal amount of CAD $648 million. Borrowings under the project finance facility bear interest at Canadian LIBOR plus 1.125% or Canadian prime rate plus 0.125%. Distributions from Greenfield LP were $9 million and $18 million during the three and nine months ended September 30, 2012, respectively, and nil and $2 million during the three and nine months ended September 30, 2011, respectively.

Whitby — Whitby is a limited partnership between certain subsidiaries of ours 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. Distributions from Whitby were nil and $7 million during the three and nine months ended September 30, 2012, respectively, and nil and $4 million during the three and nine months ended September 30, 2011, 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 which achieved COD on May 3, 2010) 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.

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4. Debt

At September 30, 2012 and December 31, 2011, our debt was as follows (in millions):

	September 30, 2012		December 31, 2011
First Lien Notes	$	5,892	$	5,892
Project financing, notes payable and other	1,949		1,691
First Lien Term Loans	1,634		1,646
CCFC Notes	976		972
Capital lease obligations	221		224
Total debt	10,672		10,425
Less: Current maturities	105		104
Debt, net of current portion	$	10,567	$	10,321

First Lien Notes

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

	September 30, 2012		December 31, 2011
2017 First Lien Notes	$	1,200	$	1,200
2019 First Lien Notes	400		400
2020 First Lien Notes	1,092		1,092
2021 First Lien Notes	2,000		2,000
2023 First Lien Notes	1,200		1,200
Total First Lien Notes	$	5,892	$	5,892

Our First Lien Notes are secured equally and ratably with indebtedness incurred under our Corporate Revolving Facility, First Lien Term Loans and 2019 First Lien Term Loan (discussed below), subject to certain exceptions and permitted liens, on substantially all of our and certain of the guarantors' existing and future assets. Additionally, our First Lien Notes rank equally in right of payment with all of our and the guarantors' other existing and future senior indebtedness, and will be effectively subordinated in right of payment to all existing and future liabilities of our subsidiaries that do not guarantee our First Lien Notes.

Subject to certain qualifications and exceptions, our First Lien Notes will, among other things, limit our ability and the ability of the guarantors to:

• incur or guarantee additional first lien indebtedness;

• enter into certain types of commodity hedge agreements that can be secured by first lien collateral;

• enter into sale and leaseback transactions;

• create or incur liens; and

• consolidate, merge or transfer all or substantially all of our assets and the assets of our restricted subsidiaries on a combined basis.

On October 9, 2012, we issued notice to the holders of our First Lien Notes of our intent to redeem 10% of the aggregate principal amount of each series of our existing First Lien Notes at a redemption price of 103% of the principal amount redeemed, plus accrued and unpaid interest. The redemption is expected to be completed in the fourth quarter of 2012 using proceeds received from the issuance of the 2019 First Lien Term Loan discussed further below.

First Lien Term Loans

Our First Lien Term Loans provide for a senior secured term loan facility and bear interest, at our option, at either (i) the base rate, equal to the higher of the Federal Funds effective rate plus 0.5% per annum or the Prime Rate (as such terms are defined in the First Lien Term Loans credit agreements), plus an applicable margin of 2.25%, or (ii) LIBOR plus 3.25% per annum subject to a LIBOR floor of 1.25%. An aggregate amount equal to 0.25% of the aggregate principal amount of the First Lien Term Loans

11

will be payable at the end of each quarter with the remaining balance payable on the maturity date (April 1, 2018). The First Lien Term Loans are subject to certain qualifications and exceptions, similar to our First Lien Notes.

2019 First Lien Term Loan

On October 9, 2012, we entered into and borrowed $835 million under our 2019 First Lien Term Loan, which bears interest at the same rate as our First Lien Term Loans (discussed above). We will use the net proceeds received to redeem 10% of the aggregate principal amount of each series of our existing First Lien Notes at a redemption price of 103% of the principal amount redeemed and to repay project debt totaling $218 million, plus accrued and unpaid interest in each case. The 2019 First Lien Term Loan allows us to reduce our overall cost of debt by replacing a portion of our First Lien Notes with fixed interest rates ranging from 7.25% to 8.0% with corporate level term loans carrying a lower variable interest rate currently at 4.5% and to repay variable rate project debt.

The 2019 First Lien Term Loan carries substantially the same terms as the First Lien Term Loans and matures on October 9, 2019. The 2019 First Lien Term Loan also contains very similar covenants, qualifications, exceptions and limitations as the First Lien Term Loans and First Lien Notes. We expect to record debt extinguishment costs of approximately $18 million associated with the redemption premium, the write-off of unamortized deferred financing costs and debt premium and discount during the fourth quarter of 2012.

Russell City Project Debt 

On June 24, 2011, we, through our indirect, partially owned subsidiary Russell City Energy Company, LLC, closed on our approximately $845 million Russell City Project Debt to finance construction of Russell City Energy Center, a 619 MW natural gas-fired, combined-cycle power plant under construction located in Hayward, California. The Russell City Project Debt is comprised of a $700 million construction loan facility, an approximately $77 million project letter of credit facility and a $68 million debt service reserve letter of credit facility. The construction loan converts to a ten year term loan when commercial operations commence. Borrowings bear interest initially at LIBOR plus 2.25%. At September 30, 2012, approximately $468 million had been drawn under the construction loan and approximately $61 million of letters of credit were issued under the letter of credit facilities. Calpine's pro rata share would be 75% and the pro rata share related to the noncontrolling interest would be 25%.

Los Esteros Project Debt

On August 23, 2011, we, through our indirect, wholly owned subsidiary Los Esteros Critical Energy Facility, LLC, closed on our $373 million Los Esteros Project Debt to finance the upgrade of our Los Esteros Critical Energy Facility from a 188 MW simple-cycle power plant to a 309 MW combined-cycle generation power plant. The upgrade will also increase the efficiency and environmental performance of the power plant by lowering the Heat Rate. The Los Esteros Project Debt is comprised of a $305 million construction loan facility, an approximately $38 million project letter of credit facility and an approximately $30 million debt service reserve letter of credit facility. The construction loan converts to a ten year term loan when commercial operations commence. Borrowings bear interest initially at LIBOR plus 2.25%. At September 30, 2012, approximately $171 million had been drawn under the construction loan and approximately $30 million of letters of credit were issued under the letter of credit facilities.

Corporate Revolving Facility and Other Letters of Credit Facilities

The table below represents amounts issued under our letter of credit facilities at September 30, 2012 and December 31, 2011 (in millions):

	September 30, 2012		December 31, 2011
Corporate Revolving Facility	$	280	$	440
CDHI	275		193
Various project financing facilities	130		130
Total	$	685	$	763

The Corporate Revolving Facility represents our primary revolving facility. Borrowings under the Corporate Revolving Facility bear interest, at our option, at either a base rate or LIBOR rate. Base rate borrowings shall be at the base rate, plus an applicable margin ranging from 2.00% to 2.25% as provided in the Corporate Revolving Facility credit agreement. Base rate is defined as the higher of (i) the Federal Funds Effective Rate, as published by the Federal Reserve Bank of New York, plus 0.50% and (ii) the rate the administrative agent announces from time to time as its prime per annum rate. LIBOR rate borrowings shall be at the British Bankers' Association Interest Settlement Rates for the interest period as selected by us as a one, two, three, six or, if agreed by all relevant lenders, nine or twelve month interest period, plus an applicable margin ranging from 3.00% to 3.25%.

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Interest payments are due on the last business day of each calendar quarter for base rate loans and the earlier of (i) the last day of the interest period selected or (ii) each day that is three months (or a whole multiple thereof) after the first day for the interest period selected for LIBOR rate loans. Letter of credit fees for issuances of letters of credit include fronting fees equal to that percentage per annum as may be separately agreed upon between us and the issuing lenders and a participation fee for the lenders equal to the applicable interest margin for LIBOR rate borrowings. Drawings under letters of credit shall be repaid within two business days or be converted into borrowings as provided in the Corporate Revolving Facility credit agreement. We incur an unused commitment fee ranging from 0.50% to 0.75% on the unused amount of commitments under the Corporate Revolving Facility.

The Corporate Revolving Facility does not contain any requirements for mandatory prepayments, except in the case of certain designated asset sales in excess of $3 billion in the aggregate. However, we may voluntarily repay, in whole or in part, the Corporate Revolving Facility, together with any accrued but unpaid interest, with prior notice and without premium or penalty. Amounts repaid may be re-borrowed, and we may also voluntarily reduce the commitments under the Corporate Revolving Facility without premium or penalty. The Corporate Revolving Facility matures December 10, 2015.

The Corporate Revolving Facility is guaranteed and secured by each of our current domestic subsidiaries that was a guarantor under the First Lien Credit Facility and will also be additionally guaranteed by our future domestic subsidiaries that are required to provide such a guarantee in accordance with the terms of the Corporate Revolving Facility. The Corporate Revolving Facility ranks equally in right of payment with all of our and the guarantors' other existing and future senior indebtedness and will be effectively subordinated in right of payment to all existing and future liabilities of our subsidiaries that do not guarantee the Corporate Revolving Facility. The Corporate Revolving Facility also requires compliance with financial covenants that include a minimum cash interest coverage ratio and a maximum net leverage ratio.

CDHI

We also have a letter of credit facility related to CDHI. On January 10, 2012, we increased the CDHI letter of credit facility to $300 million and extended the maturity date to January 2, 2016.

Fair Value of Debt

We record our debt instruments based on contractual terms, net of any applicable premium or discount. We did not elect to apply the alternative U.S. GAAP provisions of the fair value option for recording financial assets and financial liabilities. The following table details the fair values and carrying values of our debt instruments at September 30, 2012 and December 31, 2011 (in millions):

	September 30, 2012				December 31, 2011
	Fair Value		Carrying Value		Fair Value		Carrying Value
First Lien Notes	$	6,378	$	5,892	$	6,219	$	5,892
Project financing, notes payable and other(1)	1,750		1,789		1,467		1,504
First Lien Term Loans	1,644		1,634		1,615		1,646
CCFC Notes	1,073		976		1,070		972
Total	$	10,845	$	10,291	$	10,371	$	10,014

____________

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

On January 1, 2012, we adopted Accounting Standards Update 2011-04 “Fair Value Measurement” which requires the categorization by level of the fair value hierarchy for items not measured at fair value on our Consolidated Condensed Balance Sheets but for which fair value is required to be disclosed. We measure the fair value of our First Lien Notes, First Lien Term Loans and CCFC Notes 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.

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5. Assets and Liabilities with Recurring Fair Value Measurements

Cash Equivalents — Highly liquid investments which meet the definition of cash equivalents, primarily investments in money market accounts, are included in both our cash and cash equivalents and our restricted cash on our Consolidated Condensed Balance Sheets. Certain of our money market accounts invest in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities. Our cash equivalents are classified within level 1 of the fair value hierarchy.

Margin Deposits and Margin Deposits Held by Us Posted by Our Counterparties — Margin deposits and margin deposits held by us posted by our counterparties represent cash collateral paid between our counterparties and us to support our commodity contracts. Our margin deposits and margin deposits held by us posted 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 natural gas swaps, futures and options traded on the NYMEX.

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 primarily 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. In cases where there is no corroborating market information available to support significant model inputs, we initially use the transaction price as the best estimate of fair value. 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.

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At September 30, 2012, the derivative instruments classified as level 3 primarily included longer term OTC traded commodity contracts extending through 2014. These contracts are classified as level 3 as the contract terms exceed the period for which liquid market rate information is available. As such, the fair value of each contract incorporates extrapolation assumptions made in the determination of the market price for future delivery periods in which applicable commodity prices were either not observable or lacked corroborative market data. The fair value of the net derivative position classified as level 3 is predominantly driven by market commodity prices; however, given the nature of our net derivative position, we do not believe that a significant change in market commodity prices would have a material impact on our level 3 fair value. The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at September 30, 2012:

	Quantitative Information about Level 3 Fair Value Measurements
	September 30, 2012
	Fair Value, Net Asset			Significant Unobservable
	(Liability)		Valuation Technique	Input	Range
	(in millions)
Physical Power	$	15	Discounted cash flow	Market price (per MWh)	$20.95 — $56.78/MWh

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect our estimate of the fair value of our assets and liabilities and their placement within the fair value hierarchy levels. The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2012 and December 31, 2011, by level within the fair value hierarchy:

	Assets and Liabilities with Recurring Fair Value Measures as of September 30, 2012
	Level 1		Level 2		Level 3		Total
	(in millions)
Assets:
Cash equivalents(1)	$	1,275	$	—	$	—	$	1,275
Margin deposits	103		—		—		103
Commodity instruments:
Commodity exchange traded futures and swaps contracts	559		—		—		559
Commodity forward contracts(2)	—		47		22		69
Interest rate swaps	—		5		—		5
Total assets	$	1,937	$	52	$	22	$	2,011
Liabilities:
Margin deposits held by us posted by our counterparties	$	9	$	—	$	—	$	9
Commodity instruments:
Commodity exchange traded futures and swaps contracts	497		—		—		497
Commodity forward contracts(2)	—		32		6		38
Interest rate swaps	—		208		—		208
Total liabilities	$	506	$	240	$	6	$	752

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	Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2011
	Level 1		Level 2		Level 3		Total
	(in millions)
Assets:
Cash equivalents(1)	$	1,415	$	—	$	—	$	1,415
Margin deposits	140		—		—		140
Commodity instruments:
Commodity exchange traded futures and swaps contracts	1,043		—		—		1,043
Commodity forward contracts(2)	—		74		37		111
Interest rate swaps	—		10		—		10
Total assets	$	2,598	$	84	$	37	$	2,719
Liabilities:
Margin deposits held by us posted by our counterparties	$	34	$	—	$	—	$	34
Commodity instruments:
Commodity exchange traded futures and swaps contracts	899		—		—		899
Commodity forward contracts(2)	—		184		20		204
Interest rate swaps	—		320		—		320
Total liabilities	$	933	$	504	$	20	$	1,457

___________

(1) As of September 30, 2012 and December 31, 2011, we had cash equivalents of $1,074 million and $1,249 million included in cash and cash equivalents and $201 million and $166 million included in restricted cash, respectively.

(2) Includes OTC swaps and options.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Balance, beginning of period	$	(10	)	$	21		$	17		$	30
Realized and unrealized gains (losses):
Included in net income (loss):
Included in operating revenues(1)	1			(8		)	3			(1		)
Included in fuel and purchased energy expense(2)	1			1			1			1
Included in OCI	—			(2		)	1			3
Purchases, issuances and settlements:
Issuances	(1		)	—			(1		)	—
Settlements	25			16			(4		)	(6		)
Transfers in and/or out of level 3(3):
Transfers into level 3(4)	—			—			—			—
Transfers out of level 3(5)	—			(1		)	(1		)	—
Balance, end of period	$	16		$	27		$	16		$	27
Change in unrealized gains (losses) relating to instruments still held at end of period	$	2		$	(7	)	$	4		$	—

___________

(1) For power contracts and Heat Rate swaps and options, 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/out of level 1 during the three and nine months ended September 30, 2012 and 2011.

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(4) There were no transfers out of level 2 into level 3 for the three and nine months ended September 30, 2012 and 2011.

(5) We had nil and $1 million in gains transferred out of level 3 into level 2 for the three months ended September 30, 2012 and 2011, respectively. There were $1 million in gains and nil transferred out of level 3 into level 2 for the nine months ended September 30, 2012 and 2011, respectively.

6. Derivative Instruments

Types of Derivative Instruments and Volumetric Information

Commodity Instruments — We are exposed to changes in prices for the purchase and sale of power, natural gas 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.

Interest Rate Swaps — A portion of our debt is indexed to base rates, primarily LIBOR. We have historically used interest rate swaps to adjust the mix between fixed and floating rate debt to hedge our interest rate risk for potential adverse changes in interest rates. As of September 30, 2012, the maximum length of time over which we were hedging using interest rate derivative instruments designated as cash flow hedges was 11 years.

As of September 30, 2012 and December 31, 2011, the net forward notional buy (sell) position of our outstanding commodity and interest rate swap contracts that did not qualify under the normal purchase normal sale exemption were as follows (in millions):

Derivative Instruments	Notional Amounts
	September 30, 2012			December 31, 2011
Power (MWh)	(13		)	(21		)
Natural gas (MMBtu)	2			(200		)
Interest rate swaps(1)	$	1,629		$	5,639

____________

(1) Approximately $4.1 billion at December 31, 2011 was related to hedges of our First Lien Credit Facility's variable rate debt that was converted to fixed rate debt. On March 26, 2012, we terminated the interest rate swaps formerly hedging our First Lien Credit Facility.

Certain of our derivative instruments contain credit risk-related contingent provisions that require us to maintain collateral balances consistent with our credit ratings. If our credit rating were to be downgraded, it could require us to post additional collateral or could potentially allow our counterparty to request immediate, full settlement on certain derivative instruments in liability positions. Currently, we do not believe that it is probable that any additional collateral posted as a result of a one credit notch downgrade from its current level would be material. The aggregate fair value of our derivative liabilities with credit risk-related contingent provisions as of September 30, 2012, was $4 million for which we have posted collateral of $2 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, Corporate Revolving Facility, First Lien Term Loans and 2019 First Lien Term Loan. However, if our credit rating were downgraded by one notch from its current level, we estimate that no additional collateral would be required and that no counterparty could request immediate, full settlement.

Accounting for Derivative Instruments

We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Condensed Statements of Operations until the period of delivery. In order to simplify our reporting, we elected to discontinue the application of hedge accounting treatment during the first quarter of 2012 for all commodity derivatives, including the remaining commodity derivatives previously accounted for as cash flow hedges. Accordingly, prospective changes in fair value from the date of this election are reflected in earnings and could create more volatility in our earnings. Revenues and fuel costs derived from instruments that qualify for hedge accounting or represent an economic hedge are recorded in the same financial statement line

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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 (in the case of settlements for our interest rate swaps formerly hedging our First Lien Credit Facility term loans) 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 unrealized 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. Gains and losses due to ineffectiveness on hedging instruments are recognized currently in earnings as a component of operating revenues (for power contracts and swaps), fuel and purchased energy expense (for natural gas contracts and swaps) and interest expense (for interest rate swaps except as discussed below). 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 and interest rate 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 derivatives not designated as hedging instruments are recognized currently in earnings as a component of operating revenues (for power contracts and Heat Rate swaps and options), fuel and purchased energy expense (for natural gas contracts, swaps and options) and interest expense (for interest rate swaps except as discussed below).

Interest Rate Swaps Formerly Hedging our First Lien Credit Facility — In January 2011, we repaid approximately $1.2 billion of our First Lien Credit Facility term loans which had approximately $1.0 billion notional amount of interest rate swaps hedging the scheduled variable interest payments. With the repayment of these First Lien Credit Facility term loans, unrealized losses of approximately $91 million in AOCI related to the interest rate swaps formerly hedging the First Lien Credit Facility, were reclassified out of AOCI and into earnings as an additional loss on interest rate derivatives during the first quarter of 2011. We have presented the reclassification of unrealized losses from AOCI into earnings and the changes in fair value and settlements subsequent to the reclassification date of the interest rate swaps formerly hedging our First Lien Credit Facility described above separate from interest expense as loss on interest rate derivatives on our Consolidated Condensed Statements of Operations. On March 26, 2012, we terminated the legacy interest rate swaps formerly hedging our First Lien Credit Facility and paid the fair value of the swaps totaling approximately $156 million. Approximately $14 million of the settlement amount was recorded as a component of loss on interest rate derivatives on our Consolidated Condensed Statements of Operations for the nine months ended September 30, 2012 and approximately $142 million reflected the realization of losses recorded in prior periods.

Derivatives Included on Our Consolidated Condensed Balance Sheet

The following tables present the fair values of our net derivative instruments recorded on our Consolidated Condensed Balance Sheets by location and hedge type at September 30, 2012 and December 31, 2011 (in millions):

	September 30, 2012
	Interest Rate Swaps			Commodity Instruments		Total Derivative Instruments
Balance Sheet Presentation
Current derivative assets	$	—		$	487	$	487
Long-term derivative assets	5			141		146
Total derivative assets	$	5		$	628	$	633
Current derivative liabilities	$	36		$	421	$	457
Long-term derivative liabilities	172			114		286
Total derivative liabilities	$	208		$	535	$	743
Net derivative assets (liabilities)	$	(203	)	$	93	$	(110	)

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	December 31, 2011
	Interest Rate Swaps			Commodity Instruments		Total Derivative Instruments
Balance Sheet Presentation
Current derivative assets	$	—		$	1,051	$	1,051
Long-term derivative assets	10			103		113
Total derivative assets	$	10		$	1,154	$	1,164
Current derivative liabilities	$	166		$	978	$	1,144
Long-term derivative liabilities	154			125		279
Total derivative liabilities	$	320		$	1,103	$	1,423
Net derivative assets (liabilities)	$	(310	)	$	51	$	(259	)

	September 30, 2012				December 31, 2011
	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(1):
Interest rate swaps	$	5	$	189	$	10	$	149
Commodity instruments	17		2		51		18
Total derivatives designated as cash flow hedging instruments	$	22	$	191	$	61	$	167
Derivatives not designated as hedging instruments:
Interest rate swaps	$	—	$	19	$	—	$	171
Commodity instruments	611		533		1,103		1,085
Total derivatives not designated as hedging instruments	$	611	$	552	$	1,103	$	1,256
Total derivatives	$	633	$	743	$	1,164	$	1,423

____________

(1) Includes accumulated fair value of derivative instruments as of the date hedge accounting was discontinued, net of amortized fair value for settlement periods which have transpired.

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 mark-to-market activity for both the net realized gain (loss) and the net unrealized 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):

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	Three Months Ended September 30,					Nine Months Ended September 30,
	2012		2011			2012			2011
Realized gain (loss)
Interest rate swaps	$	—	$	(44	)	$	(157	)	$	(150	)
Commodity derivative instruments	113		65			325			117
Total realized gain (loss)	$	113	$	21		$	168		$	(33	)
Unrealized gain (loss)(1)
Interest rate swaps	$	3	$	43		$	152		$	5
Commodity derivative instruments	219		(8		)	(49		)	(47		)
Total unrealized gain (loss)	$	222	$	35		$	103		$	(42	)
Total mark-to-market activity, net	$	335	$	56		$	271		$	(75	)

___________

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2012		2011			2012			2011
Realized and unrealized gain (loss)
Power contracts included in operating revenues	$	329	$	18		$	149		$	9
Natural gas contracts included in fuel and purchased energy expense	3		39			127			61
Interest rate swaps included in interest expense	3		2			9			4
Loss on interest rate derivatives	—		(3		)	(14		)	(149		)
Total mark-to-market activity, net	$	335	$	56		$	271		$	(75	)

Derivatives Included in OCI and AOCI

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

	Three Months Ended September 30,
	Gain (Loss) Recognized  in OCI (Effective Portion)						Gain (Loss) Reclassified  from AOCI into Income (Effective Portion)(1)								Gain (Loss) Reclassified from AOCI into Income  (Ineffective Portion)
	2012			2011			2012				2011				2012		2011
Interest rate swaps	$	(14	)	$	(103	)	$	(8	)	(2)	$	(7	)	(2)	$	—	$	(1	)
Commodity derivative instruments	(9		)	9			9			(3)	27			(3)	—		(1		)
Total	$	(23	)	$	(94	)	$	1			$	20			$	—	$	(2	)

	Nine Months Ended September 30,
	Gain (Loss) Recognized  in OCI (Effective Portion)						Gain (Loss) Reclassified  from AOCI into Income (Effective Portion)(1)								Gain (Loss) Reclassified from AOCI into Income  (Ineffective Portion)
	2012			2011			2012				2011				2012		2011
Interest rate swaps	$	(48	)	$	(9	)	$	(23	)	(4)	$	(130	)	(4)	$	—	$	(2	)
Commodity derivative instruments	(23		)	(27		)	38			(3)	106			(3)	2		—
Total	$	(71	)	$	(36	)	$	15			$	(24	)		$	2	$	(2	)

____________

(1) Cumulative cash flow hedge losses, net of tax, remaining in AOCI were $236 million and $172 million at September 30, 2012 and December 31, 2011, respectively.

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(2) Reclassification of losses from OCI to earnings consisted of $8 million and $7 million from the reclassification of interest rate contracts due to settlement for the three months ended September 30, 2012 and 2011, respectively.

(3) Included in operating revenues and fuel and purchased energy expense on our Consolidated Condensed Statement of Operations.

(4) Reclassification of losses from OCI to earnings consisted of $23 million and $24 million from the reclassification of interest rate contracts due to settlement for the nine months ended September 30, 2012 and 2011, respectively, $15 million in losses from terminated interest rate contracts due to repayment of project debt in June 2011, and $91 million in losses from existing interest rate contracts reclassified from OCI into earnings due to the refinancing of variable rate First Lien Credit Facility term loans for the nine months ended September 30, 2011.

As a result of our election to discontinue hedge accounting treatment for our commodity derivatives accounted for as cash flow hedges, the fair value of our commodity derivative instruments residing in AOCI will be reclassified to earnings over the next three months as the related hedged transactions affect earnings. We estimate that pre-tax net losses of $21 million (comprised of amounts related to interest rate swaps and the commodity hedges previously discussed) would be reclassified from AOCI into earnings during the next 12 months as the hedged transactions settle; however, the actual amounts that will be reclassified will likely vary based on changes in interest rates. Therefore, we are unable to predict what the actual reclassification from AOCI into earnings (positive or negative) will be for the next 12 months.

7. Use of Collateral

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

The table below summarizes the balances outstanding under margin deposits, natural gas and power prepayments, and exposure under letters of credit and first priority liens for commodity procurement and risk management activities as of September 30, 2012 and December 31, 2011 (in millions):

	September 30, 2012		December 31, 2011
Margin deposits(1)	$	103	$	140
Natural gas and power prepayments	34		42
Total margin deposits and natural gas and power prepayments with our counterparties(2)	$	137	$	182
Letters of credit issued	$	525	$	581
First priority liens under power and natural gas agreements	13		1
First priority liens under interest rate swap agreements	214		318
Total letters of credit and first priority liens with our counterparties	$	752	$	900
Margin deposits held by us posted by our counterparties(1)(3)	$	9	$	34
Letters of credit posted with us by our counterparties	1		—
Total margin deposits and letters of credit posted with us by our counterparties	$	10	$	34

___________

(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.

(2) At September 30, 2012 and December 31, 2011, $115 million and $162 million, respectively, were included in margin deposits and other prepaid expense and $22 million and $20 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets.

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

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

8. Income Taxes

Income Tax Expense (Benefit)

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Income tax expense (benefit)	$	81		$	20		$	23		$	(45	)	(1	)
Imputed tax rate	16		%	10		%	19		%	20		%

_________

(1) Includes a tax benefit of approximately $76 million related to the election to consolidate our CCFC and Calpine groups for federal income tax reporting purposes for the nine months ended September 30, 2011.

Accounting for Income Taxes

Intraperiod Tax Allocation — In accordance with U.S. GAAP, intraperiod tax allocation provisions require allocation of a tax expense (benefit) to continuing operations due to current OCI gains with a partial offsetting amount recognized in OCI. The following table details the effects of our intraperiod tax allocations for the three and nine months ended September 30, 2012 and 2011 (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Intraperiod tax allocation expense included in continuing operations	$	3		$	36		$	7		$	20
Intraperiod tax allocation benefit included in OCI	$	(3	)	$	(34	)	$	(7	)	$	(18	)

NOL Carryforwards —Under federal income tax law, our NOL carryforwards can be utilized to reduce future taxable income subject to certain limitations, including if we were to undergo an ownership change as defined by Section 382 of the IRC. We experienced an ownership change on the Effective Date as a result of the cancellation of our old common stock and the distribution of our new common stock pursuant to our Plan of Reorganization. However, this ownership change and the resulting annual limitations are not expected to result in the expiration of our NOL carryforwards if we are able to generate sufficient future taxable income within the carryforward periods. When considering our cumulative annual Section 382 limitations, in addition to our post-Effective Date NOLs that are not limited, our total unrestricted NOLs were approximately $6.3 billion at December 31, 2011. If a subsequent ownership change were to occur as a result of future transactions in our common stock, accompanied by a significant reduction in our market value immediately prior to the ownership change, our ability to utilize the NOL carryforwards may be significantly limited.

Under state income tax laws, our NOL carryforwards can be utilized to reduce future taxable income subject to certain limitations, including if we were to undergo an ownership change as defined by Section 382 of the IRC. During 2011, we analyzed the effect of our change in ownership on the Effective Date for each of our significant states to determine the amount of our NOL limitation. The analysis determined that $640 million of our state NOLs are expected to expire unutilized as a result of statutory limitations on the use of some of our pre-emergence date NOLs as of the Effective Date or the cessation of business operations in various tax jurisdictions. We reduced our deferred tax asset for state NOLs that we are unable to utilize and made an equal reduction in our valuation allowance in 2011. The result did not have an impact on our income tax expense in 2011. As we had estimated, approximately $50 million of our state NOLs are expected to expire unutilized during 2012 as a result of statutory state limitations relating to the time period NOLs can be carried forward, and accordingly, we reduced our deferred tax asset and made an equal reduction in our valuation allowance. The reduction did not have an impact to our income tax expense in 2012. We will likely make future annual adjustments to our state NOLs that have expired or are limited under Section 382 of the IRC.

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To manage the risk of significant limitations on our ability to utilize our tax NOL carryforwards, our amended and restated certificate of incorporation requires our Board of Directors to meet to determine whether to impose certain transfer restrictions on our common stock if, prior to February 1, 2013, our Market Capitalization declines by at least 35% from our Emergence Date Market Capitalization of approximately $8.6 billion (in each case, as defined in and calculated pursuant to our amended and restated certificate of incorporation) and at least 25 percentage points of shift in ownership has occurred with respect to our equity for purposes of Section 382 of the IRC. We believe as of the filing of this Report, an ownership change exceeding 25 percentage points has occurred; however, we have not experienced declines in our stock price of more than 35% from our Emergence Date Market Capitalization. Accordingly, the transfer restrictions have not been put in place by our Board of Directors; however, if both of the foregoing events were to occur together and our Board of Directors was to elect to impose them, they could become operative in the future. There can be no assurance that the circumstances will not be met in the future, or in the event that they are met, that our Board of Directors would choose to impose these restrictions or that, if imposed, such restrictions would prevent an ownership change from occurring. Unless extended by a vote of the shareholders, the ability of the Board of Directors to impose transfer restrictions on our common stock terminates on January 31, 2013.

Should our Board of Directors elect to impose these restrictions, it will have the authority and discretion to determine and establish the definitive terms of the transfer restrictions, provided that the transfer restrictions apply to purchases by owners of 5% or more of our common stock, including any owners who would become owners of 5% or more of our common stock via such purchase. The transfer restrictions will not apply to the disposition of shares provided they are not purchased by a 5% or more owner.

Income Tax Audits — We remain subject to various audits and reviews by taxing authorities; however, we do not expect these will have a material effect on our tax provision. Any NOLs we claim in future years to reduce taxable income could be subject to U.S. Internal Revenue Service examination regardless of when the NOLs occurred. Due to significant NOLs, any adjustment of state returns or federal returns from 2007 and forward would likely result in a reduction of deferred tax assets rather than a cash payment of income taxes.

Canadian Tax Audits — In September 2009, we received notice from the Canadian Revenue Authority, or CRA, of their intent to conduct a limited scope income tax audit on four of our Canadian subsidiaries for the tax years 2005 through 2008. The CRA concluded that there were no adjustments on two of the entities, but further review was required on the remaining two subsidiaries. On April 23, 2012, the remaining two subsidiaries received proposed adjustments from the CRA regarding our tax transfer pricing positions. On June 21, 2012, we met with the CRA to discuss their proposed adjustments and provide clarification where we believed it was needed. In July 2012, we received additional questions from the CRA as a result of our meeting, and we responded to their request in September and October 2012.

We continue to evaluate the proposed adjustments; however, based on our preliminary analysis, we believe that our transfer pricing tax positions and policies are appropriate, and we intend to challenge the CRA's proposed adjustments. If we are unsuccessful in our challenge, any adjustment to Canadian taxable income would first be offset against any existing NOLs that are available; however, we do not believe any reassessment resulting in an adjustment to taxable income which is greater than our existing NOLs, or including interest or penalties which cannot be offset by existing NOLs, would have a material adverse effect on our financial condition, results of operations or cash flows.

Valuation Allowance — U.S. GAAP requires that we consider all available evidence, both positive and negative, and tax planning strategies to determine whether, based on the weight of that evidence, a valuation allowance is needed to reduce the value of deferred tax assets. Future realization of the tax benefit of an existing deductible temporary difference or carryforward ultimately depends on the existence of sufficient taxable income of the appropriate character within the carryback or carryforward periods available under the tax law. Due to our history of losses, we were unable to assume future profits; however, since our emergence from Chapter 11, we are able to consider available tax planning strategies.

Unrecognized Tax Benefits — At September 30, 2012, we had unrecognized tax benefits of $92 million. If recognized, $47 million of our unrecognized tax benefits could impact the annual effective tax rate and $45 million, related to deferred tax assets, could be offset against the recorded valuation allowance resulting in no impact to our effective tax rate. We also had accrued interest and penalties of $23 million for income tax matters at September 30, 2012. We recognize interest and penalties related to unrecognized tax benefits in income tax expense (benefit) on our Consolidated Condensed Statements of Operations. The amount of unrecognized tax benefits at September 30, 2012 increased by $18 million from December 31, 2011 primarily related to prior year tax positions. We believe it is reasonably possible that a decrease within the range of approximately nil and $23 million in unrecognized tax benefits could occur within the next 12 months primarily related to state and foreign tax issues.

U.S. Federal Income Tax Refund — In 2004, we deducted a portion of our foreign dividends as allowed by the IRC when we filed our federal income tax return. Upon further review and analysis, we determined our foreign dividends should have been

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offset against our current 2004 operating loss. In 2009, we filed an amended federal income tax return that reflected this change and would result in a refund of approximately $10 million. This amended federal return has been under audit by the U.S. Internal Revenue Service since it was filed. In October 2012, the U.S. Internal Revenue Service approved our amended tax return and we received a refund of approximately $13 million which included approximately $3 million in accrued interest. The benefit of this refund will be reflected in our financial statements in the fourth quarter of 2012.

9. Earnings (Loss) per Share

Pursuant to our Plan of Reorganization, all shares of our common stock outstanding prior to the Effective Date were canceled and the issuance of 485 million new shares of reorganized Calpine Corporation common stock was authorized to resolve allowed unsecured claims. A portion of the 485 million authorized shares was immediately distributed, and the remainder was reserved for distribution to holders of certain disputed claims that, although allowed as of the Effective Date, were unresolved. In June 2011, we settled the largest remaining claim outstanding and began the process of distributing the balance of the reserved shares, which was completed during the third quarter of 2011, pursuant to our Plan of Reorganization. Accordingly, although the reserved shares were not issued and outstanding for the entire balance of the three and nine months ended September 30, 2011, all conditions of distribution had been met for these reserved shares as of the Effective Date, and such shares are considered issued and are included in our calculation of weighted average shares outstanding. We also 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 nine months ended September 30, 2011, diluted loss per share for this period is computed on the same basis as basic loss per share, as the inclusion of any other potential shares outstanding would be anti-dilutive.

Reconciliations of the amounts used in the basic and diluted earnings (loss) per common share computations for the three and nine months ended September 30, 2012 and 2011, are as follows (shares in thousands):

	Three Months Ended September 30,		Nine Months Ended September 30,
	2012	2011	2012	2011
Diluted weighted average shares calculation:
Weighted average shares outstanding (basic)	462,307	486,420	470,589	486,363
Share-based awards	3,646	2,642	3,542	—
Weighted average shares outstanding (diluted)	465,953	489,062	474,131	486,363

We excluded the following items from diluted earnings (loss) per common share for the three and nine months ended September 30, 2012 and 2011, because they were anti-dilutive (shares in thousands):

	Three Months Ended September 30,		Nine Months Ended September 30,
	2012	2011	2012	2011
Share-based awards	9,356	12,696	11,677	15,202

10. Stock-Based Compensation

Calpine Equity Incentive Plans

The Calpine Equity Incentive Plans provide for the issuance of equity awards to all non-union employees as well as the non-employee members of our Board of Directors. The equity awards may include incentive or non-qualified stock options, restricted stock, restricted stock units, stock appreciation rights, performance compensation awards and other share-based awards. The equity awards granted under the Calpine Equity Incentive Plans include both graded and cliff vesting options which vest over periods between one and five years, contain contractual terms between approximately five and ten years and are subject to forfeiture provisions under certain circumstances, including termination of employment prior to vesting. At September 30, 2012, there were 567,000 and 27,533,000 shares of our common stock authorized for issuance to participants under the Director Plan and the Equity Plan, respectively.

We use the Black-Scholes option-pricing model or the Monte Carlo simulation model, as appropriate, to estimate the fair value of our employee stock options on the grant date, which takes into account the exercise price and expected term of the stock option, the current price of the underlying stock and its expected volatility, expected dividends on the stock and the risk-free interest rate for the expected term of the stock option as of the grant date. For our restricted stock and restricted stock units, we

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use our closing stock price on the date of grant, or the last trading day preceding the grant date for restricted stock granted on non-trading days, as the fair value for measuring compensation expense. Stock-based compensation expense is recognized over the period in which the related employee services are rendered. The service period is generally presumed to begin on the grant date and end when the equity award is fully vested. We use the graded vesting attribution method to recognize fair value of the equity award over the service period. For example, the graded vesting attribution method views onethree-year option grant with annual graded vesting as three separate sub-grants, each representing 33 1/3% of the total number of stock options granted. The first sub-grant vests over one year, the second sub-grant vests over two years and the third sub-grant vests over three years. A three-year option grant with cliff vesting is viewed as one grant vesting over three years.

Stock-based compensation expense recognized was $6 million for each of the three months ended September 30, 2012 and 2011, and $19 million and $18 million for the nine months ended September 30, 2012 and 2011, respectively. We did not record any significant tax benefits related to stock-based compensation expense in any period as we are not benefiting from a significant portion of our deferred tax assets, including deductions related to stock-based compensation expense. In addition, we did not capitalize any stock-based compensation expense as part of the cost of an asset for the nine months ended September 30, 2012 and 2011. At September 30, 2012, there was unrecognized compensation cost of $8 million related to options, $21 million related to restricted stock and nil related to restricted stock units, which is expected to be recognized over a weighted average period of 1.0 years for options, 1.4 years for restricted stock and 0.6 years for restricted stock units. We issue new shares from our share reserves set aside for the Calpine Equity Incentive Plans and employment inducement options when stock options are exercised and for other share-based awards.

A summary of all of our non-qualified stock option activity for the Calpine Equity Incentive Plans for the nine months ended September 30, 2012, is as follows:

	Number of Shares	Weighted Average Exercise Price		Weighted Average Remaining Term (in years)	Aggregate Intrinsic Value (in millions)
Outstanding — December 31, 2011	17,665,902	$	17.32	4.8	$	26
Granted	898,115	$	15.35
Exercised	276,300	$	15.16
Forfeited	171,267	$	13.17
Expired	114,300	$	17.72
Outstanding — September 30, 2012	18,002,150	$	17.29	4.3	$	35
Exercisable — September 30, 2012	10,356,198	$	19.13	3.8	$	9
Vested and expected to vest – September 30, 2012	17,668,022	$	17.34	4.2	$	34

The total intrinsic value of our employee stock options exercised was $1 million and nil for the nine months ended September 30, 2012 and 2011, respectively. The total cash proceeds received from our employee stock options exercised was $4 million and nil for the nine months ended September 30, 2012 and 2011, respectively.

The fair value of options granted during the nine months ended September 30, 2012 and 2011, was determined on the grant date using the Black-Scholes option-pricing model. Certain assumptions were used in order to estimate fair value for options as noted in the following table:

	2012			2011
Expected term (in years)(1)	6.5			6.5
Risk-free interest rate(2)	1.2 – 1.6		%	1.7 – 3.2		%
Expected volatility(3)	27.0 – 30.5		%	31.2 – 44.9		%
Dividend yield(4)	—			—
Weighted average grant-date fair value (per option)	$	5.18		$	5.49

___________

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

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

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

(4) We have never paid cash dividends on our common stock, and it is not anticipated that any cash dividends will be paid on our common stock in the near future.

No restricted stock or restricted stock units have been granted other than under the Calpine Equity Incentive Plans. A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the nine months ended September 30, 2012, is as follows:

	Number of Restricted Stock Awards	Weighted Average Grant-Date Fair Value
Nonvested — December 31, 2011	3,510,358	$	12.10
Granted	1,557,214	$	15.38
Forfeited	207,798	$	13.61
Vested	1,052,157	$	10.10
Nonvested — September 30, 2012	3,807,617	$	13.89

The total fair value of our restricted stock that vested during the nine months ended September 30, 2012 and 2011, was approximately $19 million and $7 million, respectively.

11. Commitments and Contingencies

Litigation

We are party to various litigation matters, including regulatory and administrative proceedings arising out of the normal course of business. At the present time, we do not expect that the outcome of any of these proceedings 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.

12. Segment Information

We assess our business on a regional basis due to the impact on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors impacting supply and demand. At September 30, 2012, our reportable segments were West (including geothermal), Texas, North (including Canada) and Southeast. We continue to evaluate the optimal manner in which we assess our performance including our segments and future changes may result.

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

	Three Months Ended September 30, 2012
	West			Texas			North			Southeast			Consolidation and Elimination			Total
Revenues from external customers	$	509		$	886		$	407		$	194		$	—		$	1,996
Intersegment revenues	2			(34		)	4			68			(40		)	—
Total operating revenues	$	511		$	852		$	411		$	262		$	(40	)	$	1,996
Commodity Margin(1)	$	330		$	218		$	266		$	83		$	—		$	897
Add: Mark-to-market commodity activity, net and other(2)(3)	(40		)	249			(26		)	27			(8		)	202
Less:
Plant operating expense	88			49			51			29			(10		)	207
Depreciation and amortization expense	52			35			33			21			(1		)	140
Sales, general and other administrative expense	9			12			8			8			(1		)	36
Other operating expenses(4)	10			1			6			(1		)	2			18
(Income) from unconsolidated investments in power plants	—			—			(7		)	—			—			(7		)
Income from operations	131			370			149			53			2			705
Interest expense, net of interest income																181
Other (income) expense, net																6
Income before income taxes																$	518

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	Three Months Ended September 30, 2011
	West		Texas			North			Southeast		Consolidation and Elimination			Total
Revenues from external customers	$	688	$	843		$	430		$	248	$	—		$	2,209
Intersegment revenues	3		3			(8		)	31		(29		)	—
Total operating revenues	$	691	$	846		$	422		$	279	$	(29	)	$	2,209
Commodity Margin(1)	$	329	$	162		$	259		$	75	$	—		$	825
Add: Mark-to-market commodity activity, net and other(2)(3)	20		(21		)	(11		)	—		(8		)	(20		)
Less:
Plant operating expense	94		50			44			33		(9		)	212
Depreciation and amortization expense	52		34			36			22		(1		)	143
Sales, general and other administrative expense	10		10			7			7		(1		)	33
Other operating expenses(4)	11		(1		)	7			—		2			19
(Income) from unconsolidated investments in power plants	—		—			(5		)	—		—			(5		)
Income from operations	182		48			159			13		1			403
Interest expense, net of interest income														190
Loss on interest rate derivatives														3
Debt extinguishment costs and other (income) expense, net														—
Income before income taxes														$	210

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	Nine Months Ended September 30, 2012
	West			Texas		North			Southeast			Consolidation and Elimination			Total
Revenues from external customers	$	1,183		$	1,430	$	974		$	524		$	—		$	4,111
Intersegment revenues	7			27		9			84			(127		)	—
Total operating revenues	$	1,190		$	1,457	$	983		$	608		$	(127	)	$	4,111
Commodity Margin(1)	$	748		$	472	$	591		$	212		$	—		$	2,023
Add: Mark-to-market commodity activity, net and other(2)(5)	(80		)	66		(17		)	(5		)	(22		)	(58		)
Less:
Plant operating expense	281			189		154			98			(23		)	699
Depreciation and amortization expense	151			104		100			66			(3		)	418
Sales, general and other administrative expense	23			36		22			23			—			104
Other operating expenses(4)	30			4		21			2			1			58
(Income) from unconsolidated investments in power plants	—			—		(21		)	—			—			(21		)
Income from operations	183			205		298			18			3			707
Interest expense, net of interest income															545
Loss on interest rate derivatives															14
Debt extinguishment costs and other (income) expense, net															26
Income before income taxes															$	122

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	Nine Months Ended September 30, 2011
	West		Texas			North			Southeast			Consolidation and Elimination			Total
Revenues from external customers	$	1,753	$	1,939		$	1,025		$	624		$	—		$	5,341
Intersegment revenues	7		13			5			116			(141		)	—
Total operating revenues	$	1,760	$	1,952		$	1,030		$	740		$	(141	)	$	5,341
Commodity Margin(1)	$	798	$	357		$	578		$	188		$	—		$	1,921
Add: Mark-to-market commodity activity, net and other(2)(5)	36		(54		)	(12		)	(4		)	(23		)	(57		)
Less:
Plant operating expense	297		193			136			107			(22		)	711
Depreciation and amortization expense	140		99			102			67			(3		)	405
Sales, general and other administrative expense	29		33			19			18			—			99
Other operating expenses(4)	30		2			23			3			(1		)	57
(Income) from unconsolidated investments in power plants	—		—			(12		)	—			—			(12		)
Income (loss) from operations	338		(24		)	298			(11		)	3			604
Interest expense, net of interest income															568
Loss on interest rate derivatives															149
Debt extinguishment costs and other (income) expense, net															108
Loss before income taxes															$	(221	)

_________

(1) Our North segment includes Commodity Margin related to Riverside Energy Center, LLC of $32 million and $31 million for the three months ended September 30, 2012 and 2011, respectively, and $64 million and $62 million for the nine months ended September 30, 2012 and 2011, respectively.

(2) Mark-to-market commodity activity represents the change in the unrealized portion of our mark-to-market activity, net, included in operating revenues and fuel and purchased energy expense on our Consolidated Condensed Statements of Operations.

(3) Includes $16 million and $11 million of lease levelization for the three months ended September 30, 2012 and 2011, respectively, and $4 million of amortization expense for each of the three months ended September 30, 2012 and 2011.

(4) Excludes $4 million and $3 million of RGGI compliance and other environmental costs for the three months ended September 30, 2012 and 2011, respectively, and $9 million and $7 million for the nine months ended September 30, 2012 and 2011, respectively, which are components of Commodity Margin.

(5) Includes $7 million and $15 million of lease levelization and $11 million and $5 million of amortization expense for the nine months ended September 30, 2012 and 2011, respectively.

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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 on page viii of this Report for a description of important factors that could cause actual results to differ from expected results.

Introduction and Overview

We are the largest independent wholesale power generation company in the U.S. measured by power produced. We own and operate primarily natural gas-fired and geothermal power plants in North America and have a significant presence in major competitive wholesale power markets in California, Texas and the Mid-Atlantic region of the U.S. We sell wholesale power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities, power marketers and others. We have invested in clean power generation to become a recognized leader in developing, constructing, owning and operating an environmentally responsible portfolio of power plants. We purchase natural gas and fuel oil as fuel for our power plants, engage in related natural gas transportation and storage transactions, and purchase electric transmission rights to deliver power to our customers. We also enter into natural gas and power physical and financial contracts to hedge certain business risks and optimize our portfolio of power plants. Our goal is to be recognized as the premier independent power company in the U.S. as measured by our employees, customers, regulators, shareholders and communities in which our facilities are located. We seek to achieve sustainable growth through financially disciplined power plant development, construction, acquisition, operation and ownership. We will continue to pursue opportunities to improve our fleet performance and reduce operating costs. In order to manage our various physical assets and contractual obligations, we will continue to execute commodity agreements within the guidelines of our Risk Management Policy.

We continue to make significant progress to maintain financially disciplined growth, to enhance long-term shareholder value through our capital allocation and share repurchases and to set the foundation for continued growth and success with the following achievements during 2012:

• We produced approximately 90 million MWh of electricity during the nine months ended September 30, 2012, 31% more than the same period in 2011 (includes generation from power plants owned but not operated by us and our share of generation from our unconsolidated power plants).

• Our entire fleet achieved a forced outage factor of 1.6% during the nine months ended September 30, 2012, our lowest on record for this period.

• Our entire fleet achieved a starting reliability of 98.5% during the nine months ended September 30, 2012, our highest on record for this period.

• During the nine months ended September 30, 2012, we achieved our best year-to-date safety performance on record.

• During the first quarter of 2012, we terminated our legacy interest rate swaps formerly hedging our First Lien Credit Facility for approximately $156 million.

• On October 3, 2012, we agreed to purchase a natural gas-fired, combined-cycle power plant with a nameplate capacity of 800 MW located in Bosque County, Texas for approximately $432 million which will increase capacity in our Texas segment.

• On October 9, 2012, we issued our 2019 First Lien Term Loan and will use the proceeds to reduce our overall cost of debt and simplify our capital structure by redeeming a portion of our First Lien Notes and repaying project debt.

• On November 1, 2012, we, through our indirect, wholly owned subsidiary Calpine Power Company, entered into an agreement with Broad River Power to sell 100% of our ownership interests in each of the Broad River Entities for approximately $427 million, including a five year consulting agreement and subject to certain working capital adjustments at closing. We expect to use the sale proceeds to focus more resources on our core markets and for general corporate purposes.

• Construction of our Russell City Energy Center and modernization at our Los Esteros Critical Energy Facility continue to move forward with expected completion dates during the summer of 2013.

• On August 23, 2011, we announced that our Board of Directors had authorized the repurchase of up to $300 million in shares of our common stock. In April 2012, our Board of Directors authorized us to double the size of our share

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repurchase program, increasing our permitted cumulative repurchases to $600 million in shares of our common stock. Through the filing of this Report, a total of 25,632,334 shares of our outstanding common stock have been repurchased under this program for approximately $427 million at an average price of $16.66 per share.

• We continue to grow our presence in core markets with an emphasis on expansions or upgrades at existing sites and power plants. We have continued to make progress with our turbine upgrade program and have ongoing development activities including the advanced development of the Garrison Energy Center located in Dover, Delaware and expansion of our Deer Park and Channel Energy Centers in Texas.

• We have entered into new long-term customer contracts including new PPAs associated with our Oneta Energy Center, new resource adequacy contracts and an amended PPA associated with our Los Medanos Energy Center and a new resource adequacy contract associated with our Gilroy Cogeneration Plant.

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

Our portfolio, including partnership interests, consists of 93 power plants, including 2 under construction, located throughout 20 states in the U.S. and in Canada, with an aggregate generation capacity of 28,009 MW and 773 MW under construction. Our fleet generation capacity, including projects under construction, consists of 75 combustion turbine-based plants, 2 fossil steam-based plants, 15 geothermal plants and 1 photovoltaic solar plant. Our segments have an aggregate generation capacity of 6,751 MW with an additional 773 MW under construction in the West, 7,252 MW in Texas, 7,923 MW in the North and 6,083 MW in the Southeast. Our Geysers Assets are included in our West segment.

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 within the RTO and ISO markets in which we participate in connection with the development, ownership and operation of our power plants. Federal and state legislative and regulatory actions continue to change how our business is regulated. We are actively participating in these debates at the federal, regional and state 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 2011 Form 10-K.

Mercury and Air Toxics Standards

On December 21, 2011, the EPA issued the National Emission Standards for Hazardous Air Pollutants from Coal- and Oil-fired Electric Utility Steam Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric Utility, Industrial-Commercial-Institutional, and Small Industrial-Commercial-Institutional Steam Generating Units, otherwise known as the Mercury and Air Toxics Standards (“MATS”). MATS will reduce emissions of all hazardous air pollutants emitted by coal- and oil-fired electric generating units, including mercury (Hg), arsenic (As), chromium (Cr), nickel (Ni) and acid gases.

The EPA estimates that there are approximately 1,400 units affected by MATS, consisting of approximately 1,100 existing coal-fired units and 300 oil-fired units at approximately 600 power plants. The CAA provides existing units three years from the effective date of MATS to come into compliance. As a result, existing coal-fired units without emissions controls will need to retire or install controls on acid gases, mercury and particulate matter emissions by April 16, 2015. State enforcement authorities also have discretion under the CAA to provide an additional year for technology installation. Further, the EPA issued a policy memorandum which indicates that the EPA may provide, in limited circumstances due to delays in the installation of controls, an additional year extension for MATS compliance where necessary to maintain electric system reliability. Accordingly, although the EPA’s analysis indicates that it should take no longer than three years for most existing units to comply, they may have up to five years, or until April 16, 2017, to install controls and comply with MATS.

We are not directly affected by MATS because it does not apply to natural gas-fired units, peaker units or units that use fuel oil as a backup fuel. We believe that the emission standards are sufficiently stringent to force existing coal-fired units without emissions controls to retire or to install the necessary controls by April 16, 2015 (unless an extension is granted), which could benefit our competitive position.

Prior to the April 16, 2012 filing deadline, a total of 30 petitions for review challenging MATS were filed in the U.S. Court of Appeals for the D.C. Circuit (“D.C. Circuit”) and subsequently consolidated under the case White Stallion Energy Center v. EPA. On March 19, 2012, Calpine, along with other energy companies, filed a motion for leave to intervene in the consolidated case in support of the EPA. Petitioners are expected to argue that the rule is arbitrary and capricious because the EPA failed to adequately demonstrate its threshold finding that the rule is “appropriate and necessary”; the EPA failed to address their concerns that MATS could damage electricity grid reliability; and the standards for new sources are not achievable.

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Several petitioners moved to sever the issues specific to the standards for new coal-fired power plants and expedite briefing on those issues. On June 28, 2012, the D.C. Circuit granted the motion to sever and expedite briefing, and the new unit case is being considered under a separate docket number. However, on July 20, 2012, the EPA granted partial administrative reconsideration of certain issues affecting new units, namely, measurement issues related to mercury and the data underlying particulate matter and hydrogen chloride emissions standards. As a consequence, on September 12, 2012, the D.C. Circuit stayed the severed case addressing standards for new units and held that case in abeyance pending the EPA’s administrative reconsideration of the new unit standards. The remaining challenges to MATS that are not being held in abeyance continue to progress.

Cross-State Air Pollution Rule

On July 6, 2011, the EPA finalized the Cross-State Air Pollution Rule (“CSAPR”) which would require a total of 28 states, primarily in the eastern U.S., to reduce annual SO2 emissions, annual NOx emissions and/or ozone season NOx emissions to assist in attaining three National Ambient Air Quality Standards (“NAAQS”): the 1997 annual PM2.5 NAAQS, the 1997 8-hour ozone NAAQS, and the 2006 24-hour PM2.5 NAAQS.

CSAPR established an unlimited intrastate and limited interstate trading program with allowances allocated to sources based on historic heat input but capped at maximum annual emissions from 2003 to 2010. At current capacity factors, Calpine would have been allocated sufficient allowances; thus, CSAPR was not expected to have a negative impact on our operations. We expected the overall impact of CSAPR to be positive for Calpine because the significant emissions reduction requirements would require coal-fired electric generating units to either purchase allowances, switch to more expensive fuels, install air pollution controls, or reduce or discontinue operations, thereby incenting the increased utilization of existing, and development of new, natural gas-fired power plants.

A number of power generation companies, states and other groups filed petitions for review in the D.C. Circuit challenging CSAPR. Calpine, other power generation companies, states, cities, and public health groups were granted intervenor status on behalf of respondent EPA. Oral arguments in the case took place on April 13, 2012.

On August 21, 2012, the D.C. Circuit (Judges Rogers, Griffith and Kavanaugh presiding), in a 2-1 split decision, vacated CSAPR in EME Homer City Generation v. EPA. The D.C. Circuit, in an opinion written by Judge Kavanaugh and joined by Judge Griffith, held that the EPA exceeded its statutory authority under the CAA because the EPA’s approach for identifying upwind states’ “significant contribution” to downwind nonattainment did not assure a close enough correlation between each state’s contribution and its required share of reductions. The majority also held that, by simultaneously promulgating Federal Implementation Plans (“FIP”) applicable to the upwind states along with CSAPR, the EPA erred because, in the majority’s view, states are not required by the CAA to submit State Implementation Plans (“SIP”) addressing transported pollution until after the EPA has first quantified their significant contribution. The D.C. Circuit ordered the EPA to continue administering CAIR, which the EPA has been implementing since the D.C. Circuit stayed CSAPR in December 2011 and which CSAPR was designed to replace due to the flaws in CAIR identified by the D.C. Circuit in North Carolina v. EPA.

Judge Rogers dissented, arguing that the SIP/FIP issue was not properly presented in this case at all, and that even if it were, the majority’s reasoning was flatly inconsistent with the statute. The dissent further argued that petitioners’ challenge to the EPA’s approach for identifying upwind states’ significant contributions to downwind nonattainment was waived by failure to raise this issue sufficiently in public comment and was foreclosed by the D.C. Circuit’s own precedents.

The EPA petitioned for en banc rehearing (i.e., by all active judges on the D.C. Circuit) on October 5, 2012 upon the basis that the ruling conflicts with prior rulings of the D.C. Circuit and raises issues of exceptional importance. Intervenors supporting the EPA also submitted three petitions for en banc rehearing upon similar grounds, including one submitted by a coalition of environmental and public health organizations, one by a group of cities and states (including the states of North Carolina, Connecticut, Delaware, Illinois, Maryland, Massachusetts, New York, Rhode Island and Vermont) and one jointly filed by Calpine and Exelon Corporation. To obtain en banc reconsideration, five of the eight judges on the D.C. Circuit must decide to rehear the case.

Assuming en banc rehearing is not granted and the decision is not reversed by the full court upon rehearing en banc and/or by the U.S. Supreme Court upon a petition for writ of certiorari, the EPA must continue to implement CAIR while it creates a replacement for CSAPR.

California: GHG — Cap-and-Trade Regulation

California's AB 32 creates a statewide cap on GHG emissions and requires the state to return to 1990 emissions levels by 2020. To meet these levels, CARB has approved the implementation of a number of measures including a Cap-and-trade program. In late 2011, CARB adopted final Cap-and-trade and mandatory reporting regulations, which took effect on January 1, 2012. The first compliance period for covered sources like Calpine is 2013-2015; however, in 2012, CARB is implementing other

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requirements of the Cap-and-trade regulation including registering covered entities and testing the necessary auction infrastructure. The first allowance auction will be held on November 14, 2012 and will include 2013 and 2015 vintage allowances. Litigation challenging the implementation of CARB's AB 32 Scoping Plan has been resolved. However, on March 28, 2012, two environmental organizations filed a lawsuit challenging the Cap-and-trade regulation, seeking to enjoin the use of emissions offsets to meet covered entities' compliance obligations. Briefing has been completed and oral argument is scheduled for November 6, 2012. We cannot predict the ultimate success of this lawsuit. Because the Cap-and-trade regulation includes a severability clause, even if the lawsuit is successful, it should not prevent the program from being implemented with respect to capped sectors. We cannot predict whether there will be any additional legal challenges filed against the regulation or what the associated impacts of any such litigation would be.

A number of parties continue to seek further refinements to improve the regulation. Concurrent with the adoption of the regulations, in October 2011, CARB also adopted Resolution 11-32, outlining the issues it will continue to address including, but not limited to, issues raised by Calpine on the market's auction purchase and holding limit provisions of the Cap-and-trade regulation and issues involving long-term contracts executed prior to AB 32. On June 28, 2012, the CARB Board adopted only minor amendments to the Cap-and-trade regulation and postponed the adoption of proposed amendments that would facilitate the linkage of California's and Quebec's Cap-and-trade programs until it can meet certain requirements set forth by recently enacted legislation. At its September 2012 meeting, the CARB Board directed its staff, by mid 2013, to propose amendments to the Cap-and-trade regulation that would, among other things, increase the auction purchase limit for obligated parties and provide allowances to obligated parties that have long-term contracts that do not allow the costs of compliance to be passed through to their customers. Overall, we support AB 32 and believe we are positioned to comply with these regulations.

New Jersey: NOX

New Jersey has enacted air regulations that further limit NOx emissions from turbines and boilers beginning in 2015. These regulations will require future investment in emissions controls on some of our peaking power plants. We have provided notice to PJM that our 158 MW Deepwater Energy Center, 68 MW Cedar Energy Center and 60 MW Missouri Avenue Energy Center will be physically unable to perform in the delivery year 2015 as a result of these air regulations and that we plan to retire the units before the commencement of the PJM Reliability Pricing Model 2015/2016 delivery year. We received PJM's response in May 2012 in which PJM indicated its agreement with our deactivation request provided certain planned transmission upgrades are completed as scheduled. In the event the transmission upgrades are not completed as planned, PJM may require one or more of the plants to continue to operate for a period of time, but we would be entitled to full cost recovery. We plan to install emissions controls equipment at our 73 MW Carll's Corner Energy Center and 67 MW Mickleton Energy Center as these power plants cleared PJM's 2015/2016 base residual auction. Our 77 MW Middle Energy Center did not clear PJM's 2015/2016 base residual auction and we have provided notice to PJM of our intent to retire this unit before the commencement of the PJM Reliability Pricing Model 2015/2016 delivery year. All six of our power plants impacted by the air regulations will be fully depreciated by June 2015. The retirement of these power plants or installation of emissions controls will not have a material impact on our financial condition, results of operations or cash flows.

Clean Water Act and Water Intake Rule

Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of cooling water intake structures reflect the best technology available for minimizing adverse environmental impact. The EPA proposed rules in March 2011 and subsequent revisions in June 2012 (the “Water Intake Rule”) that would allow states to require power plants employing older once-through cooling systems, particularly along biologically productive estuaries and rivers, to undertake major modifications to their cooling water intake structures or even install cooling towers to reduce impingement (fish and other aquatic life being trapped against the intake screens) and entrainment (small aquatic life passing through the intake screens and through the condenser at high temperatures). Calpine continues to participate in the rulemaking process; however, while these rules will likely affect our competitors, we do not expect these rules to have a material impact on our operations because we have only two peaking power plants that employ once-through cooling systems, one of which (Deepwater Energy Center) is scheduled to retire in 2015. The EPA has secured an additional year to finalize standards for cooling water intake structures under section 316(b) of the Clean Water Act, under a modified settlement agreement and is working to finalize the standards by June 27, 2013. The year long extension will allow the EPA to complete analysis of data, options and public comments on the Notice of Data Availability prior to finalizing the rule.

California RPS

On April 12, 2011, California's governor signed into law legislation establishing a new and higher RPS. The new law requires implementation of a 33% RPS by 2020, with intermediate targets between 2010 and 2020. The previous RPS legislation required certain retail power providers to generate or procure 20% of the power they sell to retail customers from renewable resources beginning in 2010. The new standard applies to all load-serving entities, including entities such as large municipal

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utilities that are not subject to CPUC jurisdiction. Under the new law, there are limits on different “buckets” of procurement that can be used to satisfy the RPS. Load-serving entities must satisfy at least a fraction of their compliance obligations with renewable power from resources located in California or delivered into California within the hour. Similarly, the legislation places limits on the use of “firmed and shaped” transactions and unbundled RECs – claims to the renewable aspect of the power produced by a renewable resource that can be traded separately from the underlying power. In general, the ability to use “firmed and shaped” transactions and unbundled RECs becomes more limited over the course of the implementation period. On December 1, 2011, the CPUC issued a decision on intermediate RPS procurement targets between the present and 2020. On December 15, 2011, the CPUC issued a decision clarifying exactly what transactions will fall into which bucket. Important additional details of the implementation of the 33% RPS are the subject of ongoing regulatory proceedings at both the CPUC and the California Energy Commission. In our role as an energy service provider, we are subject to the RPS requirements and continue to meet our compliance obligations. In general, we expect California’s RPS to maintain strong demand for our Geysers Assets. In addition, the increase in solar and wind generation on the state’s electrical grid has increased the need for flexible thermal generation which may be beneficial to Calpine.

QFs and California State Regulation of Power

A recently implemented CPUC settlement changes significant aspects of policy towards California QFs, including our non-renewable QF facilities. The settlement resolves issues related to QFs under existing QF contracts and establishes new energy pricing options for QFs under QF contracts, including the option to shed QF host and efficiency obligations and become dispatchable, and specifies mechanisms for the California IOUs to procure both existing combined heat and power (“CHP”) that is not otherwise under contract and new CHP. Pursuant to the QF Settlement, we have converted one of our former QFs to a dispatchable non-QF unit, and we offered some of our resources into the IOUs’ recent CHP solicitations. The IOUs selected our CHP offers for our Los Medanos Energy Center and Gilroy Cogeneration Plant and the deals are now awaiting regulatory approval. The impact of the larger CHP settlement has been positive to Calpine.

PJM Capacity Market

Certain states in the PJM market region have taken actions that could impact the PJM capacity market. In New Jersey, legislation enacted in 2011 required the New Jersey Board of Public Utilities (“BPU”) to issue a request for proposals (“RFP”) for new generation. As a result of the RFP, the BPU directed New Jersey's four public utilities to enter into standard offer capacity agreements with the winning generators for new capacity to be built in New Jersey. Several entities have appealed the BPU's order directing the public utilities to enter into long-term contracts with those generators. The appeal process continues. Also, on February 9, 2011, we joined a group of generators and utilities in filing a complaint in federal district court challenging the constitutionality of the New Jersey legislation. On September 28, 2012, the judge in the proceeding denied all Motions for Summary Judgment. Discovery is continuing but a trial date has not been set. The BPU has also initiated a proceeding and held hearings to investigate whether there is a need for New Jersey to pursue additional generation capacity beyond the 2,000 MW already contracted for pursuant to the legislation.

On September 29, 2011, the Maryland Public Service Commission (“MPSC”) issued a “Notice of Approval of Request for Proposals for New Generation to be Issued by Maryland Electric Distribution Companies” (the “Notice”). The Notice required the state's IOUs to issue RFPs for up to 1,500 MW of capacity. The Notice specifies that proposals must be for new natural gas-fired capacity capable of delivery into the PJM Southwest Mid-Atlantic Area Council (“SWMAAC”) delivery area. On April 12, 2012, the MPSC issued a further order in this proceeding, directing certain Maryland IOUs located in the SWMAAC area to enter into a contract for differences with CPV Maryland, LLC (“CPV”), a generation developer that is currently developing a 661 MW natural gas-fired, combined-cycle generation plant in SWMAAC. The facility's scheduled COD is June 1, 2015. In May 2012, we filed with the Circuit Court of Baltimore County, Maryland a Petition for Review of the MPSC's order, asking the court to review the order and declare it invalid. Several other parties filed similar appeals. The appeals have been consolidated with a hearing date scheduled for January 24, 2013.

Meanwhile, in response to a filing by PJM that was intended in part to address the negative implications from these state actions by revising the Minimum Offer Price Rule (“MOPR”) in its tariff, the FERC issued an order on April 12, 2011 approving PJM's MOPR tariff changes in time for PJM's 2015/2016 base residual auction in May 2012. The FERC's MOPR order is currently on appeal before the U.S. Court of Appeals for the Third Circuit. In addition, PJM has been working with a group of stakeholders, including Calpine, to revise certain aspects of the MOPR to address uncompetitive entry in future auctions. The stakeholder process continues and PJM has stated they expect to file changes to the MOPR in early December 2012, in order for the changes to be in effect for the next PJM Reliability Pricing Model base residual auction.

ERCOT Scarcity Pricing

The PUCT continues its very deliberative approach of considering design changes aimed at improving the ERCOT market's scarcity pricing signals. Of the two rulemakings undertaken in April 2012, the project dealing with near term system-

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wide offer cap (“SWOC”) resulted in the offer cap being raised from $3,000/MWh to $4,500/MWh and took effect on August 1, 2012. In October 2012, the PUCT approved other changes including raising the SWOC beginning June 1, 2013 to $5,000/MWh, to $7,000/MWh on June 1, 2014 and finally to $9,000/MWh on June 1, 2015. In addition, the Peaker Net Margin (“PNM”) will increase from $262,500 to $300,000 and in subsequent years it will be calculated at three-times the cost of new entry based on a simple-cycle natural gas turbine. If the PNM is exceeded in any given year, the SWOC is automatically lowered for the remainder of the year to the Low System Offer Cap (“LCAP”). The LCAP will change to the higher of $2,000/MWh, an increase from $500/MWh, or 50 times the daily Houston Ship Channel natural gas price index. Given the potential liquidity impacts of possibly higher offer caps, ERCOT stakeholders are considering the associated market credit and collateralization design changes in an effort to keep pace with the potential increase in the market's risk exposure. With these changes and proposed changes, we expect higher prices when scarcity pricing conditions occur which could have a positive impact on our Commodity Margin.

ERCOT Market Structure

The Brattle Group's (“Brattle”) June 1, 2012 release of its report on investment incentives and resource adequacy in the ERCOT market laid a solid foundation for continuing deliberation by the PUCT, ERCOT and market participants on two threshold issues. The first is whether the ERCOT region should have a mandated annual planning reserve margin or simply a reliability reserve margin target that is allowed to float in concert with the dynamics of the current energy-only market construct. The second threshold issue for the PUCT is to decide the best one of the five resource adequacy policy options offered by Brattle. At the request of the PUCT, Brattle prepared two separate resource adequacy proposals for its consideration: a modified energy-only proposal and the Texas Capacity Market, a centralized forward capacity market mechanism similar to PJM’s. Calpine filed comments with the PUCT in support of the Texas Capacity Market concept. In addition, Brattle provided a demand response analysis that shows how much and how quickly price responsive demand response can penetrate the ERCOT market. On October 25, 2012, the PUCT held a workshop to discuss the two Brattle proposals and receive Brattle's demand response analysis. The PUCT has not voted on either proposal or established a timetable for further consideration of the proposals or whether to adopt a reserve margin requirement versus continuing with the current reserve margin target. We believe a policy option decision from the PUCT by the end of 2012 will best serve the future reliability of ERCOT, but it seems more likely a decision from the PUCT will extend into 2013. We continue to support the development of a centralized forward capacity market, which, depending on implementation, we view as superior to any energy-only mechanism, to ensure ERCOT meets its reliability objective under any market conditions. As these proceedings are ongoing, we cannot predict what the ultimate impact may be nor the impact on our financial condition, results of operations or cash flows.

California Market Design

Prior to May 7, 2012, our Sutter power plant, which is a 578 MW natural gas-fired, combined-cycle power plant, had no contracts for its output in 2012. In late 2011, we determined that the power plant will be uneconomic and may have to be shutdown absent incremental compensation. Consequently, on November 22, 2011, we submitted a request to the CAISO to compensate us for our Sutter power plant under a provision of CAISO's current tariff that is intended to avoid retirement of needed generating units. Under this tariff provision, the Capacity Procurement Mechanism (“CPM”) allows the CAISO to compensate assets that are needed in the future, but are not currently receiving sufficient revenues to sustain operation. On March 29, 2012, the CPUC issued a resolution ordering California's three IOUs to negotiate to enter into contracts with us within the next thirty days. On May 7, 2012, we announced that contracts were executed with California's three IOUs for the purchase of resource adequacy from our Sutter power plant for the period from July 1 through December 31, 2012.

The CPUC and CAISO continue to evaluate long-term capacity procurement policies and products for the California power market. With the expectation of significant increases in renewables, both agencies are evaluating the need for generation flexibility attributes such as dispatchability, ramping and load following. In addition, both agencies may consider forward procurement mechanisms or obligations. In this light, the CAISO Board of Directors approved a backstop mechanism on September 13, 2012, which, if approved by FERC, will allow the CAISO to look forward five years and compensate generation units that are needed for capacity or generation attributes, but would otherwise retire. This proposal is similar to that which was filed by the CAISO with the FERC early in 2012 in an attempt to retain our Sutter power plant. The CPUC continues to review its resource adequacy and long-term procurement planning and may include forward procurement in the coming months.

Southwest Power Pool (“SPP”)

At the end of February 2012, SPP filed tariff changes with FERC to enact SPP's proposed “Day 2” wholesale energy markets. SPP, which currently conducts a basic real-time nodal balancing market, proposes to expand its market to a suite of new markets that will include centralized, security-constrained economic unit commitment with both a financially-binding, day-ahead nodal energy market and a physically-binding, real-time nodal energy market, a congestion management market using Transmission Congestion Rights, consolidate existing Balancing Areas and implement ancillary services markets for regulation and reserves. SPP will also have the authority to commit generation for reliability purposes and guarantee cost recovery for such units that are

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otherwise uneconomic. SPP will also have virtual load and generation markets that will permit hedging and speculation. SPP also plans to accommodate demand-side resource market participation. SPP does not propose any type of resource adequacy or capacity market in its filing. SPP has stated that it intends to implement the new market structure on March 1, 2014. On October 18, 2012, the FERC approved most of SPP’s proposed “Day 2” market design, subject to some conditions. These conditions should be achievable, and mostly relate to some unique aspects of SPP’s market design. We believe the market structure is generally beneficial to our Oneta Energy Center which is located in the SPP region.

Greenfield LP and Ontario Power Authority

Effective December 2009, the Independent Electricity System Operator (“IESO”) of Ontario implemented several rule changes that impacted Greenfield LP's financial performance in 2010 and 2011 and could impact Greenfield LP in future years. Greenfield LP's power supply contract with the Ontario Power Authority (“OPA”) provides it with a right to recover for financial consequences of market rule changes that negatively impact Greenfield LP. After extended negotiations with the OPA to modify the agreement to address the financial impacts, Greenfield LP initiated arbitration as provided for under the power supply contract to preserve its recovery rights. However, as a result of the recent decline in natural gas prices, we no longer expect the IESO market rule changes to materially impact our 50% partnership interest in Greenfield LP. Accordingly, during the third quarter of 2012, Greenfield LP rescinded its arbitration initiative with the OPA.

Federal Litigation on EPA Regulation of GHG Emissions

On April 2, 2007, the U.S. Supreme Court in Massachusetts v. EPA ruled that the EPA has the authority to regulate greenhouse gas emissions under the CAA. In response to Massachusetts, the EPA issued an endangerment finding for GHGs on December 7, 2009, determining that concentrations of six GHGs endanger the public health and welfare. Further, pursuant to the CAA’s requirement that the EPA establish motor-vehicle emission standards for “any air pollutant . . . which may reasonably be anticipated to endanger public health or welfare,” the EPA promulgated the so-called “Tailpipe Rule” for GHGs, which set GHG emission standards for cars and light trucks.

Under the EPA’s longstanding interpretation of the CAA, the Tailpipe Rule automatically triggered regulation of stationary sources of GHG emissions under the Prevention of Significant Deterioration (“PSD”) program (which requires state-issued construction permits for stationary sources that have the potential to emit over 100 or 250 tons per year (“tpy”), the applicable threshold depending on the type of source, of “any air pollutant”) and Title V (which requires state-issued operating permits for stationary sources that have the potential to emit at least 100 tpy of “any air pollutant”). Accordingly, the EPA issued two rules phasing in stationary source GHG regulation. In the Timing Rule, the EPA delayed when major stationary sources of GHGs would otherwise be subject to PSD and Title V permitting, concluding that these requirements would commence on January 2, 2011, the date on which the Tailpipe Rule became effective. In the Tailoring Rule, the EPA departed from the CAA’s 100/250 tpy emissions thresholds and provided that only the largest sources, those exceeding 75,000 or 100,000 tpy carbon dioxide equivalent (“CO2e”), depending on the program and project, would initially be subject to GHG permitting.

Under Step 1 of the Tailoring Rule (beginning in January 2011), new or modified sources already required to obtain a PSD permit due to their emissions of conventional regulated pollutants must satisfy best available control technology (“BACT”) requirements for GHGs if they emit or have the potential to emit at least 75,000 tpy CO2e. Under Step 2 of the Tailoring Rule (beginning in July 2011), new sources that emit or have the potential to emit at least 100,000 tpy CO2e and existing sources that emit at that level and that undertake modifications that increase emissions by at least 75,000 tpy CO2e must obtain a PSD permit and satisfy BACT requirements for GHGs, regardless of their emissions of any conventional pollutants. Tailoring Rule Step 3 was finalized in July 2012 and maintained the GHG PSD and Title V permitting thresholds specified under Step 2. The EPA has issued guidance to permitting authorities on the implementation of GHG BACT that focuses on energy efficiency. We believe that the impact of the Tailoring Rule will be neutral to us because we expect that our efficient power plants would be found to meet BACT for GHGs if required to undergo PSD review. Calpine’s Russell City Energy Center, a 619 MW combined-cycle power plant (Calpine's 75% net interest is 464 MW) being constructed in Hayward, California, voluntarily accepted GHG BACT limits in its PSD permit before such limits were required by law.

More than sixty petitions for review of these EPA rules were filed by industry and states, which were subsequently consolidated in the D.C. Circuit case Coalition for Responsible Regulation v. EPA. On June 26, 2012, the D.C. Circuit, in an unsigned per curiam opinion, upheld all of the challenged GHG regulations. Specifically, the D.C. Circuit denied the petitions relating to the Endangerment Finding and the Tailpipe Rule on the merits, while dismissing the petitions for review of the Timing Rule and the Tailoring Rule on constitutional standing grounds.

On August 10, 2012, industry groups requested rehearing en banc of the D.C. Circuit’s decision in Coalition for Responsible Regulation. On October 12, 2012, the EPA filed its response in opposition to the rehearing petition. In light of the rehearing petition, on October 9, 2012, the D.C. Circuit decided to hold in abeyance a related case regarding Step 3 of the EPA’s

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Tailoring Rule (American Petroleum Institute v. EPA). Should rehearing en banc be denied or the decision in Coalition not be reversed by the entire D.C. Circuit upon rehearing, the petitioners could petition for a writ of certiorari to the U.S. Supreme Court.

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

CFTC Regulation of Derivatives Transactions

The Dodd-Frank Act contains a variety of provisions designed to regulate financial markets, including credit and derivatives transactions. Title VII of the Dodd-Frank Act addresses regulatory reform of the OTC derivatives market in the U.S. and significantly changes the regulatory framework of this market. The current effective date for the CFTC to implement all final regulations related to Title VII is December 31, 2012. Certain Title VII regulations have been finalized; however, other key regulations have not been finalized as of this time or remain in draft form. Until all of these regulations have been finalized, the extent to which the provisions of Title VII might affect our derivatives activities is unknown. A number of features in the legislation may impact our existing business. One of these is the requirement for central clearing of many OTC derivative transactions with clearing organizations. Moreover, whereas our OTC transactions have traditionally been negotiated on a bilateral basis, including the collateral arrangements thereunder, they now may be subject to the collateral and margining procedures of the clearing organization. Other features of the Dodd-Frank Act which will have an impact on our derivatives activities include trade reporting and trade execution. The effect of the Dodd-Frank Act on traditional dealers and market-makers as well as the consequential effect on market liquidity and, hence, pricing is uncertain. Nevertheless, we expect to be able to continue to participate in financial markets for our derivative transactions.

Some of the key regulatory rulemakings regarding the definition of specific entity designations and the swap definition rules for the Dodd-Frank Act, which was signed into law on July 21, 2010, were finalized in the second and third quarters of 2012. The CFTC also recently issued several no-action letters and guidance documents impacting the implementation schedule and interpretations of key provisions in the CFTC’s Dodd-Frank Act implementation rules. We have reviewed our derivatives activities over a 12 month survey period, as a proxy for future activity, and our intended future activities, and have determined that we are not a swap dealer as defined under the CFTC’s final entity definition rule and, therefore, are not required to register as a swap dealer. We are currently completing a thorough evaluation of the impact and timing of these recent rulemakings on our operations as a non-swap dealer; however, it is difficult to fully assess the ultimate impact of the Dodd-Frank Act on us until all rulemakings are finalized and implemented.

Other Provisions

The Dodd-Frank Act also requires regulatory agencies, including the SEC, to establish regulations for implementation of many of the provisions of the Dodd-Frank Act. While we are closely monitoring this rulemaking process and no-action letters and guidance from the CFTC, the exact impact of any new rules on our business remains uncertain. We will continue to monitor all relevant developments and rulemaking initiatives, and we expect to successfully implement any new applicable requirements. At this time, we cannot predict the impact or possible additional costs to us related to the implementation of, or compliance with, the potential future requirements under the Dodd-Frank Act.

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RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2012 AND 2011

Below are our results of operations for the three months ended September 30, 2012, as compared to the same period in 2011 (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.

	2012			2011			Change			% Change
Operating revenues:
Commodity revenue	$	1,693		$	2,189		$	(496	)	(23	)
Mark-to-market activity(1)	304			21			283			#
Other(2)	(1		)	(1		)	—			—
Operating revenues	1,996			2,209			(213		)	(10	)
Operating expenses:
Fuel and purchased energy expense:
Commodity expense	808			1,372			564			41
Mark-to-market activity(1)	85			29			(56		)	#
Fuel and purchased energy expense	893			1,401			508			36
Plant operating expense	207			212			5			2
Depreciation and amortization expense	140			143			3			2
Sales, general and other administrative expense	36			33			(3		)	(9	)
Other operating expenses(3)	22			22			—			—
Total operating expenses	1,298			1,811			513			28
(Income) from unconsolidated investments in power plants	(7		)	(5		)	2			40
Income from operations	705			403			302			75
Interest expense	183			192			9			5
Loss on interest rate derivatives	—			3			3			#
Interest (income)	(2		)	(2		)	—			—
Debt extinguishment costs	—			(4		)	(4		)	#
Other (income) expense, net	6			4			(2		)	(50	)
Income before income taxes	518			210			308			#
Income tax expense	81			20			(61		)	#
Net income	437			190			247			#
Net income attributable to the noncontrolling interest	—			—			—			—
Net income attributable to Calpine	$	437		$	190		$	247		#

	2012		2011		Change		% Change
Operating Performance Metrics:
MWh generated (in thousands)(4)	32,291		28,400		3,891		14
Average availability	97.7	%	95.9	%	1.8	%	2
Average total MW in operation(4)	27,229		27,354		(125	)	—
Average capacity factor, excluding peakers	61.0	%	53.8	%	7.2	%	13
Steam Adjusted Heat Rate	7,404		7,464		60		1

__________

# Variance of 100% or greater

(1) Amount represents the change in the unrealized portion of our mark-to-market activity.

(2) Includes $4 million of amortization expense for each of the three months ended September 30, 2012 and 2011, related to an acquired contract that became effective in June 2011.

39

(3) Includes $4 million and $3 million of RGGI compliance and other environmental costs for the three months ended September 30, 2012 and 2011, respectively, which are components of Commodity Margin.

(4) 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% of Freestone 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 for power is generally determined by the variable operating cost of the next marginal generator to be dispatched to meet demand. The spread between our commodity revenue and commodity expense represents a significant portion of our Commodity Margin. Our financial performance is correlated to how we maximize our Commodity Margin through management of our portfolio of power plants, as well as our hedging and optimization activities. See additional segment discussion in “Commodity Margin and Adjusted EBITDA.”

Commodity revenue, net of commodity expense, increased $68 million for the three months ended September 30, 2012, compared to the three months ended September 30, 2011, primarily as a result of:

• higher contribution from hedges in our Texas segment during the third quarter of 2012 compared to the third quarter of 2011; and

• higher regulatory capacity revenue in the Mid-Atlantic market in the third quarter of 2012 compared to the third quarter of 2011.

Generation increased 14% due to lower hydroelectric generation and a nuclear power plant outage in California during the third quarter of 2012 as well as lower natural gas prices in our North segment. The increase in generation also resulted in a 1% decrease in our Steam Adjusted Heat Rate for the three months ended September 30, 2012, compared to the same period in 2011, as our power plants tend to operate more efficiently under baseload operations. Our average total MW in operation decreased by 125 MW primarily due to the temporary shutdown of our Los Esteros Critical Energy Facility associated with the upgrade from a simple-cycle power plant to a combined-cycle power plant partially offset by an increase in capacity resulting from our turbine upgrade program.

Unrealized mark-to-market earnings from commodity derivative instruments, primarily hedges of future generation and fuel needs, for the three months ended September 30, 2012, compared to the same period in 2011, had a favorable variance of $227 million primarily driven by the impact of a significant decrease in forward Market Heat Rates during the third quarter of 2012, compared to the change in forward Market Heat Rates that occurred during the third quarter of 2011.

Plant operating expense decreased by $5 million for the three months ended September 30, 2012, compared to the three months ended September 30, 2011, primarily due to a $2 million decrease in major maintenance expense resulting from our plant outage schedule and a $3 million decrease in costs from scrap parts related to outages. Our normal, recurring plant operating expense was largely unchanged, despite a 14% increase in generation in the third quarter of 2012 compared to the third quarter of 2011.

Interest expense decreased for the three months ended September 30, 2012, compared to the three months ended September 30, 2011, primarily resulting from a decrease in our annual effective interest rate on our consolidated debt, excluding the impacts of capitalized interest and unrealized gains (losses) on interest rate swaps, to 7.3% for the three months ended September 30, 2012, from 7.6% for the three months ended September 30, 2011.

During the three months ended September 30, 2012, we recorded an income tax expense of $81 million compared to an income tax expense of $20 million for the three months ended September 30, 2011. The unfavorable period over period change primarily resulted from a $95 million increase in various state and foreign jurisdiction income taxes resulting from an increase in pre-tax income in the current period and variations resulting from the application of the method to calculate the provision for income tax for interim periods. The overall increase in income tax expense was offset by a decrease in income tax expense of $33 million related to the application of intraperiod tax allocation.

40

RESULTS OF OPERATIONS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2012 AND 2011

Below are our results of operations for the nine months ended September 30, 2012, as compared to the same period in 2011 (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.

	2012			2011			Change			% Change
Operating revenues:
Commodity revenue	$	4,089		$	5,280		$	(1,191	)	(23	)
Mark-to-market activity(1)	24			56			(32		)	(57	)
Other(2)	(2		)	5			(7		)	#
Operating revenues	4,111			5,341			(1,230		)	(23	)
Operating expenses:
Fuel and purchased energy expense:
Commodity expense	2,064			3,367			1,303			39
Mark-to-market activity(1)	73			103			30			29
Fuel and purchased energy expense	2,137			3,470			1,333			38
Plant operating expense	699			711			12			2
Depreciation and amortization expense	418			405			(13		)	(3	)
Sales, general and other administrative expense	104			99			(5		)	(5	)
Other operating expenses(3)	67			64			(3		)	(5	)
Total operating expenses	3,425			4,749			1,324			28
(Income) from unconsolidated investments in power plants	(21		)	(12		)	9			75
Income from operations	707			604			103			17
Interest expense	552			575			23			4
Loss on interest rate derivatives	14			149			135			91
Interest (income)	(7		)	(7		)	—			—
Debt extinguishment costs	12			94			82			87
Other (income) expense, net	14			14			—			—
Income (loss) before income taxes	122			(221		)	343			#
Income tax expense (benefit)	23			(45		)	(68		)	#
Net income (loss)	99			(176		)	275			#
Net income attributable to the noncontrolling interest	—			(1		)	1			#
Net income (loss) attributable to Calpine	$	99		$	(177	)	$	276		#

	2012		2011		Change		% Change
Operating Performance Metrics:
MWh generated (in thousands)(4)	87,027		65,921		21,106		32
Average availability	91.5	%	89.8	%	1.7	%	2
Average total MW in operation(4)	27,207		27,191		16		—
Average capacity factor, excluding peakers	55.7	%	42.9	%	12.8	%	30
Steam Adjusted Heat Rate	7,357		7,434		77		1

__________

# Variance of 100% or greater

(1) Amount represents the change in the unrealized portion of our mark-to-market activity.

(2) Includes $11 million and $5 million of amortization expense for the nine months ended September 30, 2012 and 2011, respectively, related to an acquired contract that became effective in June 2011.

41

(3) Includes $9 million and $7 million of RGGI compliance and other environmental costs for the nine months ended September 30, 2012 and 2011, respectively, which are components of Commodity Margin.

(4) 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% of Freestone 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 for power is generally determined by the variable operating cost of the next marginal generator to be dispatched to meet demand. The spread between our commodity revenue and commodity expense represents a significant portion of our Commodity Margin. Our financial performance is correlated to how we maximize our Commodity Margin through management of our portfolio of power plants, as well as our hedging and optimization activities. See additional segment discussion in “Commodity Margin and Adjusted EBITDA.”

Commodity revenue, net of commodity expense, increased $112 million for the nine months ended September 30, 2012, compared to the nine months ended September 30, 2011, primarily due to:

• higher contribution from hedges primarily in our Texas segment during the third quarter of 2012 compared to the same period in 2011;

• higher generation due to increased market opportunities primarily driven by lower natural gas prices in all segments during the first half of 2012 compared to the same period in 2011 as well as lower hydroelectric generation and a nuclear power plant outage in California during the nine months ended September 30, 2012; and

• an extreme cold weather event in Texas that occurred on February 2, 2011, and resulted in unplanned outages at some of our power plants, negatively impacting our revenue in the nine months ended September 30, 2011, which did not reoccur in same period in 2012; partially offset by

• lower regulatory capacity revenue during the first half of 2012 compared to the same period in 2011; and

• the expiration of contracts which decreased revenue during the nine months ended September 30, 2012 compared to the same period in 2011.

Generation increased 32% primarily due to increased market opportunities primarily driven by lower natural gas prices in all segments during the first half of 2012 and in our North segment during the third quarter of 2012 as well as lower hydroelectric generation and a nuclear power plant outage in California during the nine months ended September 30, 2012. The increase in generation also resulted in a 1% decrease in our Steam Adjusted Heat Rate for the nine months ended September 30, 2012, compared to the same period in 2011, as our power plants tend to operate more efficiently under baseload operations. Our average total MW in operation increased by 16 MW primarily due to our 565 MW York Energy Center which achieved COD in March 2011 and an increase in capacity resulting from our turbine upgrade program partially offset by the temporary shutdown of our Los Esteros Critical Energy Facility associated with the upgrade from a simple-cycle power plant to a combined-cycle power plant.

Unrealized mark-to-market earnings from commodity derivative instruments, primarily hedges of future generation and fuel needs, for the nine months ended September 30, 2012, compared to the same period in 2011, had an unfavorable variance of $2 million primarily driven by the impact of a smaller decrease in forward natural gas prices during 2012, compared to the decrease in forward natural gas prices during 2011.

Other revenue decreased for the nine months ended September 30, 2012, compared to the nine months ended September 30, 2011, primarily resulting from a $6 million increase in amortization expense on intangible contract values related to an acquired contract that became effective in June 2011.

Plant operating expense decreased by $12 million for the nine months ended September 30, 2012, compared to the nine months ended September 30, 2011, due primarily to an $11 million decrease in major maintenance expense resulting from our plant outage schedule and an $8 million decrease in costs from scrap parts related to outages. The decrease was partially offset by a $6 million increase in property taxes resulting primarily from a nonrecurring settlement of a property tax dispute which positively impacted the nine months ended September 30, 2011. Otherwise, our normal, recurring plant operating expense was largely unchanged despite a 32% increase in generation in the nine months ended September 30, 2012, compared to the same period in 2011.

Depreciation and amortization expense increased for the nine months ended September 30, 2012, compared to the nine months ended September 30, 2011, primarily resulting from a decrease of $18 million in the nine months ended September 30, 2011 related to a revision in the expected settlement dates of the asset retirement obligations related to our natural gas-fired and geothermal power plants.

Income from unconsolidated investments in power plants increased for the nine months ended September 30, 2012, compared to the same period in 2011, due to an $8 million increase in earnings related to Greenfield LP primarily due to unscheduled outages during the nine months ended September 30, 2011.

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Interest expense decreased for the nine months ended September 30, 2012, compared to the nine months ended September 30, 2011, primarily due to a decrease in our annual effective interest rate on our consolidated debt, excluding the impacts of capitalized interest and unrealized gains (losses) on interest rate swaps, to 7.4% for the nine months ended September 30, 2012, from 7.7% for the nine months ended September 30, 2011.

Loss on interest rate derivatives had a favorable change of $135 million for the nine months ended September 30, 2012, compared to the nine months ended September 30, 2011, primarily resulting from $91 million of historical unrealized losses previously deferred in AOCI and reclassified into income in January 2011 in connection with the retirement of the First Lien Credit Facility term loans. Also contributing to the period over period change was a favorable change of $44 million resulting from interest rate swap breakage costs related to the repayment of project debt in June 2011 and changes in fair value and settlements subsequent to the reclassification date of the interest rate swaps formerly hedging our First Lien Credit Facility term loans, partially offset by swap breakage costs recorded in March 2012 related to the termination of our legacy interest swaps formerly hedging our First Lien Credit Facility. See Note 6 of the Notes to Consolidated Condensed Financial Statements for further discussion of our interest rate swaps formerly hedging our First Lien Credit Facility term loans.

Debt extinguishment costs for the nine months ended September 30, 2012, consisted of $12 million associated with the purchase of two of the three third party interests in GEC Holdings, LLC in March 2012 that were previously recorded as preferred interests and classified as debt under U.S. GAAP. Debt extinguishment costs for the nine months ended September 30, 2011, primarily consisted of $74 million associated with the repayment of the NDH Project Debt in March 2011, $19 million associated with the retirement of the First Lien Credit Facility term loans in January 2011 in connection with the issuance of the 2023 First Lien Notes and $5 million related to the write-off of unamortized deferred financing costs related to the repayment of project debt in June 2011.

During the nine months ended September 30, 2012, we recorded an income tax expense of $23 million compared to an income tax benefit of $45 million for the nine months ended September 30, 2011. The unfavorable period over period change primarily resulted from a one-time $76 million benefit to reduce our valuation allowance due to the election to consolidate the CCFC group with the Calpine group for 2011 federal income tax reporting purposes. Also contributing to the unfavorable period over period change was an increase in various state and foreign jurisdiction income taxes of $5 million resulting from an increase in pre-tax income in the current period, variations resulting from the application of the method to calculate the provision for income tax for interim periods and changes in interest related to unrecognized tax benefits. The overall increase in income tax expense was offset by a decrease in income tax expense of $13 million related to the application of intraperiod tax allocation.

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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, RGGI compliance and other environmental costs, and cash settlements from our marketing, hedging and optimization activities including natural gas transactions hedging future power sales that are included in mark-to-market activity, but excludes the unrealized portion of our mark-to-market activity and other revenues. We believe that Commodity Margin is a useful tool for assessing the performance of our core operations and is a key operational measure reviewed by our chief operating decision maker. Commodity Margin is not a measure calculated in accordance with U.S. GAAP and should be viewed as a supplement to and not a substitute for our results of operations presented in accordance with U.S. GAAP. Commodity Margin does not intend to represent income from operations, the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. See Note 12 of the Notes to Consolidated Condensed Financial Statements for a reconciliation of Commodity Margin to income (loss) from operations by segment.

Commodity Margin by Segment for the Three Months Ended September 30, 2012 and 2011

The following tables show our Commodity Margin and related operating performance metrics by segment for the three months ended September 30, 2012 and 2011. 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:	2012			2011			Change			% Change
Commodity Margin (in millions)	$	330		$	329		$	1		—
Commodity Margin per MWh generated	$	33.62		$	50.31		$	(16.69	)	(33	)
MWh generated (in thousands)	9,817			6,540			3,277			50
Average availability	98.5		%	91.2		%	7.3		%	8
Average total MW in operation	6,751			6,898			(147		)	(2	)
Average capacity factor, excluding peakers	70.7		%	47.4		%	23.3		%	49
Steam Adjusted Heat Rate	7,313			7,479			166			2

West — Commodity Margin in our West segment for the three months ended September 30, 2012 was comparable to the same period in 2011, resulting from higher Spark Spreads and a 50% increase in generation driven primarily by lower hydroelectric generation and a nuclear power plant outage in California during 2012. These positive factors were largely offset by lower Commodity Margin contribution from hedges associated with our Geysers Assets during the third quarter of 2012 compared to the third quarter of 2011 which are based on absolute power price. Our average total MW in operation decreased 147 MW, or 2%, due primarily to the temporary shutdown of our Los Esteros Critical Energy Facility at the end of 2011 associated with the upgrade from a simple-cycle power plant to a combined-cycle power plant partially offset by an increase in capacity resulting from our turbine upgrade program. Average availability increased 8% resulting from a decrease in scheduled and unscheduled outages in the third quarter of 2012 compared to the same period in 2011.

44

Texas:	2012			2011			Change			% Change
Commodity Margin (in millions)	$	218		$	162		$	56		35
Commodity Margin per MWh generated	$	21.75		$	14.95		$	6.80		45
MWh generated (in thousands)	10,025			10,833			(808		)	(7	)
Average availability	97.2		%	98.2		%	(1.0		)%	(1	)
Average total MW in operation	7,016			7,003			13			—
Average capacity factor, excluding peakers	64.7		%	70.1		%	(5.4		)%	(8	)
Steam Adjusted Heat Rate	7,211			7,296			85			1

Texas — Commodity Margin in our Texas segment increased by $56 million, or 35%, for the three months ended September 30, 2012 compared to the three months ended September 30, 2011, due to higher contribution from our hedging activities that secured favorable pricing despite lower market prices driven by milder weather in the third quarter of 2012 compared to the same period in 2011. Generation decreased 7% due to strong market pricing driven by extreme heat and drought conditions during the third quarter of 2011. Our average total MW in operation increased 13 MW due to an increase in capacity resulting from our turbine upgrade program.

North:	2012			2011			Change			% Change
Commodity Margin (in millions)	$	266		$	259		$	7		3
Commodity Margin per MWh generated	$	40.13		$	50.69		$	(10.56	)	(21	)
MWh generated (in thousands)	6,628			5,109			1,519			30
Average availability	96.9		%	97.5		%	(0.6		)%	(1	)
Average total MW in operation	7,379			7,370			9			—
Average capacity factor, excluding peakers	56.1		%	43.4		%	12.7		%	29
Steam Adjusted Heat Rate	7,943			8,003			60			1

North — Commodity Margin in our North segment increased by $7 million, or 3%, for the three months ended September 30, 2012 compared to the three months ended September 30, 2011, primarily due to higher regulatory capacity revenues during the third quarter of 2012 compared to the same period in 2011. Generation increased 30% during the three months ended September 30, 2012, as natural gas prices were low enough that during certain periods some of our Mid-Atlantic natural gas-fired, combined-cycle power plants became less expensive on a marginal basis than coal-fired generation resulting in these power plants running baseload. However, the increase in generation did not materially impact our Commodity Margin as a portion of our power plants in the North are contracted and the remaining power plants experienced lower margins on the increased generation. Average total MW in operation increased 9 MW due primarily to an increase in capacity resulting from our turbine upgrade program.

Southeast:	2012			2011			Change			% Change
Commodity Margin (in millions)	$	83		$	75		$	8		11
Commodity Margin per MWh generated	$	14.26		$	12.67		$	1.59		13
MWh generated (in thousands)	5,821			5,918			(97		)	(2	)
Average availability	98.3		%	96.6		%	1.7		%	2
Average total MW in operation	6,083			6,083			—			—
Average capacity factor, excluding peakers	48.4		%	48.9		%	(0.5		)%	(1	)
Steam Adjusted Heat Rate	7,325			7,344			19			—

Southeast — Commodity Margin in our Southeast segment increased by $8 million, or 11%, for the three months ended September 30, 2012 compared to the same period in 2011, primarily due to higher Commodity Margin contribution from hedges associated with lower natural gas prices. Generation decreased 2% primarily due to lower market pricing in SPP resulting from milder weather during the third quarter of 2012 compared the the same period in 2011 and the negative impact from the expiration of a contract during the third quarter of 2012. Otherwise, generation largely increased among our remaining power plants in the Southeast primarily due to lower natural gas prices.

45

Commodity Margin by Segment for the Nine Months Ended September 30, 2012 and 2011

The following tables show our Commodity Margin and related operating performance metrics by segment for the nine months ended September 30, 2012 and 2011. 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:	2012			2011			Change			% Change
Commodity Margin (in millions)	$	748		$	798		$	(50	)	(6	)
Commodity Margin per MWh generated	$	30.90		$	49.29		$	(18.39	)	(37	)
MWh generated (in thousands)	24,211			16,189			8,022			50
Average availability	91.2		%	86.4		%	4.8		%	6
Average total MW in operation	6,739			6,891			(152		)	(2	)
Average capacity factor, excluding peakers	58.7		%	39.6		%	19.1		%	48
Steam Adjusted Heat Rate	7,267			7,488			221			3

West — Commodity Margin in our West segment decreased by $50 million, or 6%, for the nine months ended September 30, 2012 compared to the same period in 2011, due to lower Commodity Margin contribution from hedges associated with our Geysers Assets which are based on absolute power price, lower revenue due to the expiration of contracts and lower Commodity Margin from our Sutter power plant which did not run in the first half of 2012. Generation increased 50% driven primarily by lower hydroelectric generation and a nuclear power plant outage in California during 2012. Our average total MW in operation decreased 152 MW, or 2%, due primarily to the temporary shutdown of our Los Esteros Critical Energy Facility at the end of 2011 associated with the upgrade from a simple-cycle power plant to a combined-cycle power plant partially offset by an increase in capacity resulting from our turbine upgrade program. Average availability increased 6% resulting from a decrease in scheduled and unscheduled outages in the nine months ended September 30, 2012 compared to the same period in 2011.

Texas:	2012			2011			Change			% Change
Commodity Margin (in millions)	$	472		$	357		$	115		32
Commodity Margin per MWh generated	$	16.70		$	14.86		$	1.84		12
MWh generated (in thousands)	28,257			24,019			4,238			18
Average availability	90.4		%	88.8		%	1.6		%	2
Average total MW in operation	7,012			6,983			29			—
Average capacity factor, excluding peakers	61.3		%	52.5		%	8.8		%	17
Steam Adjusted Heat Rate	7,149			7,256			107			1

Texas — Commodity Margin in our Texas segment increased by $115 million, or 32%, for the nine months ended September 30, 2012 compared to the same period in 2011, due to higher contribution from our hedging activities that secured favorable pricing despite lower market prices driven by milder weather in the nine months ended September 30, 2012 compared to the same period in 2011, and increased market opportunities resulting in an 18% increase in generation driven primarily by lower natural gas prices. During the nine months ended September 30, 2012, generation increased as natural gas prices were low enough that during certain periods some of our natural gas-fired, combined-cycle power plants in Texas became less expensive on a marginal basis than coal-fired generation resulting in these plants running baseload. Also contributing to the period over period increase was the negative impact to Commodity Margin in the first quarter of 2011 due to unplanned outages at some of our power plants caused by an extreme cold weather event which occurred on February 2, 2011. Average availability increased 2% resulting from a decrease in scheduled and unscheduled outages primarily in the first quarter of 2012 compared to the same period in 2011. Our average total MW in operation increased 29 MW due to an increase in capacity resulting from our turbine upgrade program.

46

North:	2012			2011			Change			% Change
Commodity Margin (in millions)	$	591		$	578		$	13		2
Commodity Margin per MWh generated	$	35.15		$	51.50		$	(16.35	)	(32	)
MWh generated (in thousands)	16,815			11,224			5,591			50
Average availability	90.5		%	92.3		%	(1.8		)%	(2	)
Average total MW in operation	7,373			7,234			139			2
Average capacity factor, excluding peakers	49.7		%	34.4		%	15.3		%	44
Steam Adjusted Heat Rate	7,918			7,939			21			—

North — Commodity Margin in our North segment increased by $13 million, or 2%, for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011, primarily due to higher Commodity Margin contribution from hedges and our York Energy Center which achieved COD in March 2011 partially offset by lower regulatory capacity revenues during the nine months ended September 30, 2012 compared to the same period in 2011. Generation increased 50% during the nine months ended September 30, 2012, as natural gas prices were low enough that during certain periods some of our Mid-Atlantic natural gas-fired, combined-cycle power plants became less expensive on a marginal basis than coal-fired generation resulting in these power plants running baseload. The increase in generation was also the primary driver of the 44% increase in average capacity factor, excluding peakers for the nine months ended September 30, 2012 compared to the same period in 2011. Average total MW in operation increased 139 MW, or 2%, due primarily to our 565 MW York Energy Center which achieved COD in March 2011 and an increase in capacity resulting from our turbine upgrade program.

Southeast:	2012			2011			Change			% Change
Commodity Margin (in millions)	$	212		$	188		$	24		13
Commodity Margin per MWh generated	$	11.95		$	12.98		$	(1.03	)	(8	)
MWh generated (in thousands)	17,744			14,489			3,255			22
Average availability	94.4		%	92.0		%	2.4		%	3
Average total MW in operation	6,083			6,083			—			—
Average capacity factor, excluding peakers	49.6		%	41.0		%	8.6		%	21
Steam Adjusted Heat Rate	7,302			7,323			21			—

Southeast — Commodity Margin in our Southeast segment increased by $24 million, or 13%, for the nine months ended September 30, 2012 compared to the same period in 2011, primarily due to higher Commodity Margin contribution from hedges and increased market opportunities resulting in 22% higher generation largely driven by lower natural gas prices.

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Adjusted EBITDA

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

	Three Months Ended September 30, 2012
	West		Texas			North		Southeast			Consolidation and Elimination			Total
Net income attributable to Calpine														$	437
Income tax expense														81
Other (income) expense, net														6
Interest expense, net of interest income														181
Income from operations	$	131	$	370		$	149	$	53		$	2		$	705
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs(1)	52		35			33		21			(1		)	140
Major maintenance expense	13		6			9		3			—			31
Operating lease expense	3		—			6		—			—			9
Unrealized (gain) loss on commodity derivative mark-to-market activity	36		(244		)	17		(28		)	—			(219		)
Adjustments to reflect Adjusted EBITDA from unconsolidated investments(2)(3)	—		—			7		—			—			7
Stock-based compensation expense	2		2			1		1			—			6
Loss on dispositions of assets	1		3			2		—			(1		)	5
Acquired contract amortization	—		—			4		—			—			4
Other	6		1			8		3			—			18
Total Adjusted EBITDA	$	244	$	173		$	236	$	53		$	—		$	706

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	Three Months Ended September 30, 2011
	West			Texas		North		Southeast		Consolidation and Elimination			Total
Net income attributable to Calpine													$	190
Income tax expense													20
Debt extinguishment costs and other (income) expense, net													—
Loss on interest rate derivatives													3
Interest expense, net of interest income													190
Income from operations	$	182		$	48	$	159	$	13	$	1		$	403
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs(1)	52			34		36		22		(1		)	143
Major maintenance expense	13			9		6		5		—			33
Operating lease expense	3			—		6		—		—			9
Unrealized (gain) loss on commodity derivative mark-to-market activity	(21		)	25		2		3		—			9
Adjustments to reflect Adjusted EBITDA from unconsolidated investments(2)(3)	—			—		9		—		—			9
Stock-based compensation expense	2			1		2		1		—			6
Loss on dispositions of assets	5			2		1		—		—			8
Acquired contract amortization	—			—		4		—		—			4
Other	7			1		6		—		—			14
Total Adjusted EBITDA	$	243		$	120	$	231	$	44	$	—		$	638

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	Nine Months Ended September 30, 2012
	West			Texas			North		Southeast		Consolidation and Elimination			Total
Net income attributable to Calpine														$	99
Income tax expense														23
Debt extinguishment costs and other (income) expense, net														26
Loss on interest rate derivatives														14
Interest expense, net of interest income														545
Income from operations	$	183		$	205		$	298	$	18	$	3		$	707
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs(1)	151			104			99		67		(2		)	419
Major maintenance expense	58			53			31		16		—			158
Operating lease expense	7			—			19		—		—			26
Unrealized (gain) loss on commodity derivative mark-to-market activity	88			(51		)	6		6		—			49
Adjustments to reflect Adjusted EBITDA from unconsolidated investments(2)(3)	—			—			23		—		—			23
Stock-based compensation expense	6			6			3		4		—			19
Loss on dispositions of assets	2			4			3		1		(1		)	9
Acquired contract amortization	—			—			11		—		—			11
Other	(1		)	2			7		5		—			13
Total Adjusted EBITDA	$	494		$	323		$	500	$	117	$	—		$	1,434

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	Nine Months Ended September 30, 2011
	West			Texas			North		Southeast			Consolidation and Elimination			Total
Net loss attributable to Calpine															$	(177	)
Net income attributable to the noncontrolling interest															1
Income tax benefit															(45		)
Debt extinguishment costs and other (income) expense, net															108
Loss on interest rate derivatives															149
Interest expense, net of interest income															568
Income (loss) from operations	$	338		$	(24	)	$	298	$	(11	)	$	3		$	604
Add:
Adjustments to reconcile income (loss) from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs(1)	140			99			102		68			(3		)	406
Major maintenance expense	51			68			19		31			—			169
Operating lease expense	7			—			19		—			—			26
Unrealized (gain) loss on commodity derivative mark-to-market activity	(32		)	70			1		9			—			48
Adjustments to reflect Adjusted EBITDA from unconsolidated investments(2)(3)	—			—			30		—			—			30
Stock-based compensation expense	7			5			3		3			—			18
Loss on dispositions of assets	7			6			2		2			—			17
Acquired contract amortization	—			—			5		—			—			5
Other	8			1			14		1			—			24
Total Adjusted EBITDA	$	526		$	225		$	493	$	103		$	—		$	1,347

____________

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

(2) Included on our Consolidated Condensed Statements of Operations in (income) from unconsolidated investments in power plants.

(3) Adjustments to reflect Adjusted EBITDA from unconsolidated investments include unrealized (gain) loss on mark-to-market activity of nil for each of the three and nine months ended September 30, 2012 and $1 million for each of the three and nine months ended September 30, 2011.

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LIQUIDITY AND CAPITAL RESOURCES

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

At September 30, 2012, we had $1,097 million in cash and cash equivalents and $226 million of restricted cash. Amounts available for future borrowings were $720 million under our Corporate Revolving Facility. The following table provides a summary of our liquidity position at September 30, 2012 and December 31, 2011 (in millions):

	September 30, 2012		December 31, 2011
Cash and cash equivalents, corporate(1)	$	886	$	946
Cash and cash equivalents, non-corporate	211		306
Total cash and cash equivalents	1,097		1,252
Restricted cash	226		194
Corporate Revolving Facility availability	720		560
Letter of credit availability(2)	25		7
Total current liquidity availability	$	2,068	$	2,013

____________

(1) Includes $9 million and $34 million of margin deposits held by us posted by our counterparties at September 30, 2012 and December 31, 2011, respectively.

(2) Includes availability under our CDHI letter of credit facility. On January 10, 2012, we increased the CDHI letter of credit facility to $300 million and extended the maturity date to January 2, 2016.

Our principal source for future liquidity is cash flows generated from our operations. 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. 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.

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 accounts with investment banks that are not FDIC insured. We place our cash, cash equivalents and restricted cash in what we believe to be creditworthy financial institutions and 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.

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

Liquidity Sensitivity

Significant changes in commodity prices and Market Heat Rates can have an impact on our liquidity as we use margin deposits, cash prepayments and letters of credit as credit support (collateral) with and from our counterparties for commodity procurement and risk management activities. Utilizing our portfolio of transactions subject to collateral exposure, we estimate that as of October 12, 2012, an increase of $1/MMBtu in natural gas prices would result in an increase of collateral required by approximately $209 million. If natural gas prices decreased by $1/MMBtu, we estimate that our collateral requirements would decrease by approximately $150 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

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October 12, 2012, an increase of 500 Btu/KWh in the Market Heat Rate would result in an increase in collateral required by approximately $30 million. If Market Heat Rates were to fall at a similar rate, we estimate that our collateral required would decrease by $30 million. These amounts are not necessarily indicative of the actual amounts that could be required, which may be higher or lower than the amounts estimated above, and also exclude any correlation between the changes in natural gas prices and Market Heat Rates that may occur concurrently. These sensitivities will change as new contracts or hedging activities are executed.

In order to effectively manage our future Commodity Margin, we have economically hedged a portion of our generation and natural gas portfolio mostly through power and natural gas forward physical and financial transactions for 2012; however, we remain susceptible to significant price movements for 2013 and beyond. In addition to the price of natural gas, the future impact on 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;

• the speed, strength and duration of an economic recovery;

• 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 that persists for a significant period of time or energy commodity prices increase significantly.

Our letters of credit, capital management, construction, upgrades and growth initiatives are further discussed below.

Letter of Credit Facilities 

The Corporate Revolving Facility represents our primary revolving facility. The table below represents amounts issued under our letter of credit facilities at September 30, 2012 and December 31, 2011 (in millions):

	September 30, 2012		December 31, 2011
Corporate Revolving Facility	$	280	$	440
CDHI	275		193
Various project financing facilities	130		130
Total	$	685	$	763

We have unfunded credit exposure to several financial institutions domiciled in European countries that are currently experiencing stressed economic and financial conditions related to our Russell City Project Debt, Los Esteros Project Debt and miscellaneous project finance letter of credit facilities. These financial institutions continue to perform in accordance with the terms of the applicable agreements. Should one or all of these financial institutions be unable to perform under their obligations, we do not expect it to have a material adverse effect on our financial condition, results of operations or cash flows.

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Capital Management and Significant Financing Transactions

In connection with our goals of enhancing long-term shareholder value and leveraging our three scale regions, we have completed, initiated or made progress toward completing the following key capital and financing transactions during 2012, as further described below.

Calpine Bosque Energy Center

On October 3, 2012, we, through our indirect, wholly owned subsidiary Calpine Bosque Energy Center, LLC, agreed to purchase a power plant with a nameplate capacity of 800 MW owned by Bosque Power Co., LLC, for approximately $432 million. The natural gas-fired, combined-cycle power plant will increase capacity in our Texas segment and is located in Central Texas near the unincorporated community of Laguna Park in Bosque County. The site includes a 250 MW generation block with one natural-gas turbine, one heat-recovery steam generator and one steam turbine that achieved COD in June 2001 and a 550 MW generation block with two natural-gas turbines that went online in June 2000 as well as two heat recovery steam generators and one steam turbine that achieved COD in June 2011. We expect the transaction to close in November 2012, subject to regulatory approvals, and will fund the acquisition with cash on hand.

2019 First Lien Term Loan

On October 9, 2012, we entered into and borrowed $835 million under our 2019 First Lien Term Loan, which bears interest, at our option, at either (i) the base rate, equal to the higher of the Federal Funds effective rate plus 0.5% per annum or the Prime Rate (as such terms are defined in the 2019 First Lien Term Loan credit agreement), plus an applicable margin of 2.25%, or (ii) LIBOR plus 3.25% per annum subject to a LIBOR floor of 1.25%. We will use the net proceeds received to redeem 10% of the aggregate principal amount of each series of our existing First Lien Notes at a redemption price of 103% of the principal amount redeemed and to repay project debt totaling $218 million, plus accrued and unpaid interest in each case. The 2019 First Lien Term Loan allows us to reduce our overall cost of debt by replacing a portion of our First Lien Notes with fixed interest rates ranging from 7.25% to 8.0% with corporate level term loans carrying a lower variable interest rate currently at 4.5% and to repay variable rate project debt. The 2019 First Lien Term Loan carries substantially the same terms as the First Lien Term Loans and matures on October 9, 2019. The 2019 First Lien Term Loan also contains very similar covenants, qualifications, exceptions and limitations as the First Lien Term Loans and First Lien Notes.

Share Repurchase Program

On August 23, 2011, we announced that our Board of Directors had authorized the repurchase of up to $300 million in shares of our common stock. In April 2012, our Board of Directors authorized us to double the size of our share repurchase program, increasing our permitted cumulative repurchases to $600 million in shares of our common stock. The announced share repurchase program did not specify an expiration date. The repurchases may be commenced or suspended from time to time without prior notice. Through the filing of this Report, a total of 25,632,334 shares of our outstanding common stock have been repurchased under this program for approximately $427 million at an average price of $16.66 per share. The shares repurchased as of the date of this Report were purchased in open market transactions.

Riverside Energy Center Purchase Option

Riverside Energy Center has a PPA that provides WP&L an option to purchase the power plant and plant-related assets which is exercisable in 2012. On May 18, 2012, WP&L exercised their option to purchase Riverside Energy Center, LLC for approximately $392 million. The sale is expected to close in December 2012. As a result, we expect to receive approximately $392 million during the fourth quarter of 2012 in connection with this transaction. The assets being disposed of did not meet the criteria for classification as held for sale under U.S. GAAP, and we do not expect any material gain (loss) on sale.

Broad River Energy Center

On November 1, 2012, we, through our indirect, wholly owned subsidiary Calpine Power Company, entered into an agreement with Broad River Power to sell 100% of our ownership interests in each of the Broad River Entities for approximately $427 million, including a five year consulting agreement and subject to certain working capital adjustments at closing. Under the agreement, Calpine Power Company will use commercially reasonable efforts to cause Broad River Energy Center to continue to operate and maintain the power plant in the ordinary course of business through the closing of the transaction, which is expected to occur in December 2012, subject to regulatory approvals. We expect to use the sale proceeds to focus more resources on our core markets and for general corporate purposes.

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CDHI

On January 10, 2012, we increased the CDHI letter of credit facility to $300 million and extended the maturity date to January 2, 2016.

Construction, Upgrades and Growth Initiatives

We remain focused on our goal to continue to grow our presence in core markets with an emphasis on expansions or upgrades 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 will actively seek divestiture opportunities on our non-core assets if those opportunities meet our financial expectations. In addition, we believe that upgrades and expansions to our current assets or using existing equipment offer proven and financially disciplined opportunities to improve our operations, capacity and efficiencies. Our significant projects under construction, growth initiatives and upgrades are discussed below.

West:

Russell City Energy Center — Construction at our Russell City Energy Center continues to move forward. Upon completion, this project will bring on line approximately 429 MW of net interest baseload capacity (464 MW with peaking capacity) representing our 75% share. We are in possession of all required approvals and permits, and we closed on construction financing on June 24, 2011. Upon completion, the Russell City Energy Center is contracted to deliver its full output to PG&E under a ten-year PPA. Construction is ongoing and COD is expected during the summer of 2013.

Los Esteros Critical Energy Facility — During 2009, we and PG&E negotiated a new PPA to replace the existing California Department of Water Resources contract and facilitate the upgrade of our Los Esteros Critical Energy Facility from a 188 MW simple-cycle generation power plant to a 309 MW combined-cycle generation power plant, which will also increase the efficiency and environmental performance of the power plant by lowering the Heat Rate. We obtained construction financing on August 23, 2011. The existing 188 MW simple-cycle facility was shutdown at the end of 2011 to allow for major maintenance on the combustion turbines and installation of the new heat recovery steam generators and a steam turbine generator in connection with the new PPA. Construction is ongoing and COD is expected during the summer of 2013.

Texas:

Channel and Deer Park Expansions — We are actively permitting and developing the addition of 520 MW of combined-cycle capacity at existing sites in ERCOT, based on tightening reserve margins and potential impact of EPA regulations on generation in Texas. At both our Deer Park and Channel Energy Centers, we have the ability to install an additional combustion turbine generator and connect to the existing steam turbine generator to expand the capacity of these facilities and to improve overall plant efficiency. In September and November 2011, we filed air permit applications with the Texas Commission on Environmental Quality (“TCEQ”) and the EPA to expand the Deer Park and Channel Energy Centers by approximately 260 MW each. We received air permit approvals from the TCEQ for our Deer Park and Channel expansion projects in September and October 2012, respectively, and we executed engineering, procurement and construction agreements during the third quarter of 2012. We expect COD in summer 2014 for these expansions and are currently evaluating funding sources including, but not limited to, nonrecourse financing, corporate financing or internally generated funds.

North:

Garrison Energy Center — We are actively permitting 618 MW of new combined-cycle capacity at a development site secured by a long-term lease with the City of Dover. For the first phase (309 MW), PJM has completed a feasibility study and a system impact study and is currently conducting a facility study. For the second phase (309 MW), a feasibility study has been completed and a system impact study is ongoing. Environmental permitting, site development planning and development engineering are underway and the first phase's capacity cleared PJM's 2015/2016 base residual auction. We expect to receive the air permit in the fourth quarter of 2012 and expect COD for the first phase by the summer of 2015. We are currently evaluating funding sources including, but not limited to, nonrecourse financing, corporate financing or internally generated funds.

All Segments:

Turbine Upgrades — We continue to move forward with our turbine upgrade program. Through September 30, 2012, we have completed the upgrade of eleven Siemens and eight GE turbines totaling over 200 MW and have agreed to upgrade approximately three additional turbines (and may upgrade additional turbines in the future).

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Customer-Oriented Origination Business

We continue to focus on providing products and services that are beneficial to our customers. A summary of certain significant contracts entered into in 2012 is as follows:

• We entered into a new twenty-year PPA with Western Farmers Electric Cooperative to provide 160 MW of power generated by our Oneta Energy Center, commencing in June 2014. The capacity under contract will increase in increments, up to a maximum of 280 MW in years 2019 through 2035.

• We entered into a new five-year PPA with Southwestern Public Service Company, a subsidiary of Xcel Energy, to provide an additional 200 MW of power generated by our Oneta Energy Center commencing on June 1, 2014.

• We entered into a new five-year resource adequacy contract with PG&E for approximately 280 MW of combined heat and power capacity from our Los Medanos Energy Center commencing in summer 2013.

• We entered into a new seven-year resource adequacy contract with Southern California Edison Company (“SCE”) for approximately 280 MW of combined heat and power capacity from our Los Medanos Energy Center and a new five-year resource adequacy contract with SCE for approximately 120 MW of combined heat and power capacity from our Gilroy Cogeneration Plant, both commencing in January 2014.

• We amended an existing PPA with Dow Chemical Company for an incremental energy sale of up to approximately 158,000 MWh per year of energy from our Los Medanos Energy Center which runs through February 2025.

• We entered into a new fifteen-year PPA with American Electric Power Service Corporation, as agent for Public Service Company of Oklahoma, to provide 260 MW of energy, capacity and ancillary services from our Oneta Energy Center commencing in June 2016.

NOLs

We have significant NOLs that will provide future tax deductions if we generate sufficient taxable income during the applicable carryover periods. At December 31, 2011, our consolidated federal NOLs totaled approximately $7.9 billion. See Note 8 of the Notes to Consolidated Condensed Financial Statements for further discussion of our NOLs.

Cash Flow Activities

The following table summarizes our cash flow activities for the nine months ended September 30, 2012 and 2011 (in millions):

	2012			2011
Beginning cash and cash equivalents	$	1,252		$	1,327
Net cash provided by (used in):
Operating activities	608			536
Investing activities	(701		)	(660		)
Financing activities	(62		)	82
Net decrease in cash and cash equivalents	(155		)	(42		)
Ending cash and cash equivalents	$	1,097		$	1,285

Net Cash Provided By Operating Activities

Cash provided by operating activities for the nine months ended September 30, 2012, was $608 million compared to $536 million provided by operating activities for the nine months ended September 30, 2011. The increase in cash provided by operating activities was primarily due to:

• Income from operations — Income from operations, adjusted for non-cash items increased by $112 million for the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011. Non-cash items consist primarily of depreciation and amortization, income from unconsolidated investments and unrealized gains and losses in mark-to-market activity; partially offset by

• Interest paid — Cash paid for interest increased by $56 million to $565 million for the nine months ended September 30, 2012, as compared to $509 million for the nine months ended September 30, 2011. The increase was primarily due to timing of interest payments on our First Lien Term Loans and First Lien Notes offset by lower payments on our NDH Project Debt and other project debt.

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Net Cash Used In Investing Activities

Cash flows used in investing activities for the nine months ended September 30, 2012, were $701 million compared to $660 million for the nine months ended September 30, 2011. The difference was primarily due to:

• Settlement of non-hedging interest rate swaps — During the nine months ended September 30, 2012, we terminated our legacy interest rate swaps formerly hedging our First Lien Credit Facility resulting in payments of approximately $156 million, compared to payments of approximately $147 million during the nine months ended September 30, 2011.

• Restricted cash — Restricted cash increased approximately $32 million for nine months ended September 30, 2012 compared to a decrease of $9 million for the same period in 2011. The increase in restricted cash was primarily due to a 2011 reduction in restricted cash balances related to changes in project related debt which did not recur in the nine months ended September 30, 2012, partially offset by an increase in restricted cash related to normal operating activity.

Net Cash Provided By (Used In) Financing Activities

Cash flows used in financing activities were $62 million for the nine months ended September 30, 2012 compared to cash flows provided by financing activities of $82 million for the nine months ended September 30, 2011. The increase in cash flows used in financing activities was primarily due to:

• First Lien Term Loans — During the nine months ended September 30, 2012, we made repayments on the First Lien Term Loans of approximately $12 million. During the nine months ended September 30, 2011, we received proceeds of approximately $1.7 billion from the issuance of the First Lien Term Loans. We used the proceeds to repay the NDH Project Debt of approximately $1.3 billion resulting in a net increase of $374 million.

• Stock repurchases — During the nine months ended September 30, 2012, we made payments under the share repurchase program of approximately $308 million.

• First Lien Notes — During the nine months ended September 30, 2011, we received proceeds of approximately $1.2 billion from the issuance of the 2023 FirstLien Notes and used those proceeds to terminate the First Lien Credit Facility in accordance with its repayment terms resulting in a net increase of approximately $9 million.

• Decreased contributions from noncontrolling interest holder — During the nine months ended September 30, 2012, we received contributions from a noncontrolling interest holder of nil compared to approximately $34 million during the nine months ended September 30, 2011.

The increase was partially offset by:

• Proceeds from project debt — During the nine months ended September 30, 2012, we received proceeds of approximately $312 million from project debt compared to $223 million for the nine months ended September 30, 2011. The proceeds received were related to our Russell City Project Debt and Los Esteros Project Debt.

• Lower repayments of project debt — During the nine months ended September 30, 2012, we made repayments on project debt of approximately $53million compared to repayments of approximately $476 million for the nine months ended September 30, 2011.

• Lower financing costs — During the nine months ended September 30, 2012, we paid financing costs of approximately $6 million compared to approximately $78 million for the nine months ended September 30, 2011.

Off Balance Sheet Arrangements

There have been no material changes to any off balance sheet arrangements from those disclosed in “Management's Discussion and Analysis of Financial Condition and Results of Operations” of our 2011 Form 10-K.

Special Purpose Subsidiaries

Pursuant to applicable transaction agreements, we have established certain of our entities separate from Calpine Corporation and our other subsidiaries. In accordance with applicable accounting standards, we consolidate these entities. As of the date of filing this Report, these entities included: GEC Holdings, LLC, Gilroy Energy Center, LLC, Creed, Goose Haven, Calpine Gilroy Cogen, L.P., Calpine Gilroy 1, Inc., Calpine King City Cogen, LLC, Calpine Securities Company, L.P. (a parent company of Calpine King City Cogen, LLC), Calpine King City, LLC (an indirect parent company of Calpine Securities Company, L.P.), Russell City Energy Company, LLC and Otay Mesa Energy Center, LLC.

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On March 2, 2012, we closed on the purchase of two of the three third party interests in GEC Holdings, LLC pursuant to the purchase agreements that were executed in December 2011.

RISK MANAGEMENT AND COMMODITY ACCOUNTING

Our hedging strategy and our commercial efforts attempt to maximize our risk adjusted Commodity Margin by leveraging our knowledge, experience and fundamental views on gas and power. We actively seek to manage the commodity risks of our portfolio, utilizing multiple strategies of buying and selling power, natural gas and Heat Rate contracts to manage our Spark Spread and products that manage geographic price differences (basis differential). We have approximately 371 MW of capacity from power plants where we purchase fuel oil to meet our generation requirements if required; however, we have not currently entered into any hedging or optimization transactions for our fuel oil requirements as we do not expect fuel oil requirements to be material to us, but may elect to do so in the future.

In order to simplify our reporting, we elected to discontinue the application of hedge accounting treatment during the first quarter of 2012 for all commodity derivatives, including the remaining commodity derivatives previously accounted for as cash flow hedges. Accordingly, prospective changes in fair value from the date of this election are reflected in earnings and could create more volatility in our earnings. The fair value of our commodity derivative instruments residing in AOCI during the previous application of hedge accounting will be reclassified to earnings in future periods as the related economic transactions affect earnings or if the forecasted transaction becomes probable of not occurring. While our selling and purchasing of power and natural gas is mostly physical in nature, we also engage in marketing, hedging and optimization activities, particularly in natural gas, that are financial in nature. We use derivative instruments, 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) for the purchase and sale of power, natural gas and emission allowances to manage commodity price risk and to maximize the risk-adjusted returns from our power and natural gas assets. We conduct these 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 measurement 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 within operating revenues in the case of power transactions, and within fuel and purchased energy expense in the case of natural gas transactions. Our future hedged status, and marketing and optimization activities are subject to change as determined by our commercial operations group, Chief Risk Officer, Risk Management Committee of senior management and Board of Directors.

We have economically hedged a portion of our expected generation and natural gas portfolio mostly through power and natural gas forward physical and financial transactions for 2012; however, we remain susceptible to significant price movements for 2013 and beyond. By entering into these transactions, we are able to economically hedge a portion of our Spark Spread at pre-determined generation and price levels. We use a combination of PPAs and other hedging instruments to manage our variability in future cash flows.

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. The reclassification of unrealized losses from AOCI into earnings and the changes in fair value and settlements subsequent to the reclassification date of the interest rate swaps formerly hedging our First Lien Credit Facility is presented separately from interest expense as loss on interest rate derivatives on our Consolidated Condensed Statements of Operations. On January 14, 2011, we repaid the remaining balance under the First Lien Credit Facility term loans with the proceeds received from the issuance of the 2023 First Lien Notes and the unrealized losses related to these interest rate swaps of approximately $91 million remaining in AOCI were reclassified out of AOCI and into earnings as additional loss on interest rate derivatives during the first quarter of 2011. On March 26, 2012, we terminated the legacy interest rate swaps formerly hedging our First Lien Credit Facility and paid the fair value of the swaps totaling approximately $156 million. Approximately $14 million of the settlement amount was recorded as a component of loss on interest rate derivatives on our Consolidated Condensed Statements of Operations for the nine months ended September 30, 2012 and approximately $142 million reflected the realization of losses recorded in prior periods.

At September 30, 2012, the maximum length of time over which we were hedging using interest rate derivative instruments designated as cash flow hedges was 11 years. As a result of our election to discontinue hedge accounting treatment for our

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commodity derivatives accounted for as cash flow hedges, the fair value of our commodity derivative instruments residing in AOCI will be reclassified to earnings over the next three months as the related hedged transactions affect earnings. We estimate that pre-tax net losses of $21 million (comprised of amounts related to interest rate swaps and the commodity hedges previously discussed) would be reclassified from AOCI into earnings during the next 12 months as the hedged transactions settle; however, the actual amounts that will be reclassified will 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.

The primary factors affecting our market risk and the fair value of our derivatives at any point in time are the volume of open derivative positions (MMBtu, MWh and $ notional amounts); changing commodity market prices, primarily for power and natural gas; our credit standing and that of our counterparties for energy commodity derivatives; and prevailing interest rates for our interest rate swaps. Since prices for power and natural gas and interest rates are volatile, there may be material changes in the fair value of our derivatives over time, driven both by price volatility and the changes in volume of open derivative transactions. Our derivative assets have decreased to approximately $0.6 billion at September 30, 2012, when compared to approximately $1.2 billion at December 31, 2011, and our derivative liabilities have decreased to approximately $0.7 billion at September 30, 2012, compared to approximately $1.4 billion at December 31, 2011. At September 30, 2012, the fair value of our level 3 derivative assets and liabilities represent only a small portion of our total assets and liabilities measured at fair value (approximately 1%). See Note 5 of the Notes to Consolidated Condensed Financial Statements for further information related to our level 3 derivative assets and liabilities.

The change in fair value of our outstanding commodity and interest rate derivative instruments from January 1, 2012, through September 30, 2012, is summarized in the table below (in millions):

	Interest Rate Swaps			Commodity Instruments			Total
Fair value of contracts outstanding at January 1, 2012	$	(310	)	$	51		$	(259	)
Items recognized or otherwise settled during the period(1)(2)	165			(27		)	138
Fair value attributable to new contracts	—			62			62
Changes in fair value attributable to price movements	(56		)	8			(48		)
Changes in fair value attributable to nonperformance risk	(2		)	(1		)	(3		)
Fair value of contracts outstanding at September 30, 2012(3)	$	(203	)	$	93		$	(110	)

__________

(1) Interest rate settlements consist of recognized losses of $146 million related to interest rate swaps that were terminated during the nine months ended September 30, 2012, $9 million related to recognition of losses from settlements of designated cash flow hedges and $10 million in losses from settlements of undesignated interest rate swaps (represents a portion of interest expense and loss on interest rate derivatives as reported on our Consolidated Condensed Statements of Operations).

(2) Gains on settlement of commodity contracts not designated as hedging instruments of $83 million (represents a portion of operating revenues and fuel and purchased energy expense as reported on our Consolidated Condensed Statements of Operations) and $56 million related to recognition of losses from other changes in derivative assets and liabilities not reflected in OCI or earnings, partially offset by de-designated cash flow hedges, previously reflected in AOCI.

(3) Net commodity and interest rate derivative assets and liabilities reported in Notes 5 and 6 of the Notes to Consolidated Condensed Financial Statements.

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

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2012		2011			2012			2011
Realized gain (loss)
Interest rate swaps	$	—	$	(44	)	$	(157	)	$	(150	)
Commodity derivative instruments	113		65			325			117
Total realized gain (loss)	$	113	$	21		$	168		$	(33	)
Unrealized gain (loss)(1)
Interest rate swaps	$	3	$	43		$	152		$	5
Commodity derivative instruments	219		(8		)	(49		)	(47		)
Total unrealized gain (loss)	$	222	$	35		$	103		$	(42	)
Total mark-to-market activity, net	$	335	$	56		$	271		$	(75	)

____________

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2012		2011			2012			2011
Realized and unrealized gain (loss)
Power contracts included in operating revenues	$	329	$	18		$	149		$	9
Natural gas contracts included in fuel and purchased energy expense	3		39			127			61
Interest rate swaps included in interest expense	3		2			9			4
Loss on interest rate derivatives	—		(3		)	(14		)	(149		)
Total mark-to-market activity, net	$	335	$	56		$	271		$	(75	)

Our change in AOCI from an accumulated loss of $178 million at December 31, 2011, to an accumulated loss of $237 million at September 30, 2012, was primarily driven by $53 million in losses on interest rate swaps due to a decrease in forward LIBOR rates and $38 million in gains reclassified to earnings related to the settlement of de-designated commodity derivative cash flow hedges partially offset by $8 million in losses on settlement of interest rate cash flow hedges reclassified to earnings, $12 million in gains on commodity derivative cash flow hedges from the beginning of 2012 until de-designation on February 1, 2012, a foreign currency translation gain of $5 million related to our Canadian subsidiaries and $7 million in income tax benefits recorded during the nine months ended September 30, 2012.

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

The net fair value of outstanding derivative commodity instruments at September 30, 2012, based on price source and the period during which the instruments will mature, are summarized in the table below (in millions):

Fair Value Source	2012		2013-2014		2015-2016		After 2016		Total
Prices actively quoted	$	25	$	16	$	5	$	—	$	46
Prices provided by other external sources	21		11		—		—		32
Prices based on models and other valuation methods	7		8		—		—		15
Total fair value	$	53	$	35	$	5	$	—	$	93

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We measure the energy commodity price risks in our portfolio on a daily basis using a VAR model to estimate the maximum 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, power plants, PPAs and other physical and financial transactions. The portfolio VAR calculation incorporates positions for the remaining portion of the current calendar year, exclusive of the current month of measurement, plus the following two calendar years. We measure VAR using a variance/covariance approach based on a confidence level of 95%, a one-day holding period and actual observed historical correlation. While we believe that our VAR assumptions and approximations are reasonable, different assumptions and/or approximations could produce materially different estimates.

The table below presents the high, low and average of our daily VAR for the three and nine months ended September 30, 2012 and 2011 (in millions):

	2012		2011
Three months ended September 30:
High	$	67	$	34
Low	$	37	$	21
Average	$	49	$	28
Nine months ended September 30:
High	$	77	$	39
Low	$	34	$	20
Average	$	49	$	31
As of September 30	$	39	$	31

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

Liquidity Risk — Liquidity risk arises from the general funding requirements needed to manage our activities and assets and liabilities. Increasing natural gas prices or Market Heat Rates can cause increased collateral requirements. Our liquidity management framework is intended to maximize liquidity access and minimize funding costs during times of rising prices. See further discussion regarding our uses of collateral as they relate to our commodity procurement and risk management activities in Note 7 of the Notes to Consolidated Condensed Financial Statements.

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

• credit approvals;

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

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

• margin, collateral or prepayment arrangements; and

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

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We have concentrations of credit risk with a few of our commercial customers relating to our sales of power, steam and hedging and optimization activities. We believe that our credit policies and portfolio of transactions adequately monitor our credit risk, and currently our counterparties are performing and financially settling timely according to their respective agreements. We monitor and manage our total comprehensive credit risk associated with all of our contracts and PPAs irrespective of whether they are accounted for as an executory contract, a normal purchase normal sale or whether they are marked-to-market and included in our derivative assets and liabilities on our Consolidated Condensed Balance Sheets. Our counterparty credit quality associated with the net fair value of outstanding derivative commodity instruments is included in our derivative assets and liabilities at September 30, 2012, and the period during which the instruments will mature are summarized in the table below (in millions):

Credit Quality (Based on Standard & Poor’s Ratings as of September 30, 2012)	2012			2013-2014		2015-2016		After 2016		Total
Investment grade	$	59		$	35	$	5	$	—	$	99
Non-investment grade	(1		)	—		—		—		(1		)
No external ratings	(5		)	—		—		—		(5		)
Total fair value	$	53		$	35	$	5	$	—	$	93

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 $(9) million at September 30, 2012.

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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 2011 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) or Rule 15d-15(e) of the Exchange Act. Based upon, and as of the date of, this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective such that the information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the third quarter of 2012, 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.

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PART II — OTHER INFORMATION

Item 1. Legal Proceedings

See Note 11 of the Notes to Consolidated Condensed Financial Statements for a description of our legal proceedings.

Item 1A. Risk Factors

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 2011 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)
July	—	$	—	—	$	191
August	1,087,797	$	16.86	1,086,214	$	173
September	2,157	$	17.51	—	$	173
Total	1,089,954	$	16.86	1,086,214	$	173

___________

(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 third quarter of 2012, we withheld a total of 3,740 shares in the indicated months that are included in total number of shares purchased.

(2) On August 23, 2011, we announced that our Board of Directors had authorized the repurchase of up to $300 million in shares of our common stock. In April 2012, our Board of Directors authorized us to double the size of our share repurchase program, increasing our permitted cumulative repurchases to $600 million in shares of our common stock. The announced share repurchase program did not specify an expiration date. The repurchases may be commenced or suspended from time to time without prior notice. Through the filing of this Report, a total of 25,632,334 shares of our outstanding common stock have been repurchased under this program for approximately $427 million at an average price of $16.66 per share. The shares repurchased under our share repurchase program were purchased in open market transactions and are held as treasury stock.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not Applicable.

Item 5. Other Information

None.

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Item 6. Exhibits

EXHIBIT INDEX

Exhibit Number	Description
4.1	Third Supplemental Indenture dated as of August 20, 2012, among each of Calpine Energy Services GP, LLC and Calpine Energy Services LP, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of October 21, 2009, providing for the issuance of 7.25% Senior Secured Notes due 2017.
4.2	Third Supplemental Indenture dated as of August 20, 2012, among each of Calpine Energy Services GP, LLC and Calpine Energy Services LP, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of May 25, 2010, providing for the issuance of 8.0% Senior Secured Notes due 2019.
4.3	Third Supplemental Indenture dated as of August 20, 2012, among each of Calpine Energy Services GP, LLC and Calpine Energy Services LP, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of July 23, 2010, providing for the issuance of 7.875% Senior Secured Notes due 2020.
4.4	Third Supplemental Indenture dated as of August 20, 2012, among each of Calpine Energy Services GP, LLC and Calpine Energy Services LP, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of October 22, 2010, providing for the issuance of 7.50% Senior Secured Notes due 2021.
4.5	Third Supplemental Indenture dated as of August 20, 2012, among each of Calpine Energy Services GP, LLC and Calpine Energy Services LP, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of January 14, 2011, providing for the issuance of 7.875% Senior Secured Notes due 2023.
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.

65

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: November 5, 2012

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EXHIBIT INDEX

Exhibit Number	Description
4.1	Third Supplemental Indenture dated as of August 20, 2012, among each of Calpine Energy Services GP, LLC and Calpine Energy Services LP, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of October 21, 2009, providing for the issuance of 7.25% Senior Secured Notes due 2017.
4.2	Third Supplemental Indenture dated as of August 20, 2012, among each of Calpine Energy Services GP, LLC and Calpine Energy Services LP, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of May 25, 2010, providing for the issuance of 8.0% Senior Secured Notes due 2019.
4.3	Third Supplemental Indenture dated as of August 20, 2012, among each of Calpine Energy Services GP, LLC and Calpine Energy Services LP, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of July 23, 2010, providing for the issuance of 7.875% Senior Secured Notes due 2020.
4.4	Third Supplemental Indenture dated as of August 20, 2012, among each of Calpine Energy Services GP, LLC and Calpine Energy Services LP, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of October 22, 2010, providing for the issuance of 7.50% Senior Secured Notes due 2021.
4.5	Third Supplemental Indenture dated as of August 20, 2012, among each of Calpine Energy Services GP, LLC and Calpine Energy Services LP, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of January 14, 2011, providing for the issuance of 7.875% Senior Secured Notes due 2023.
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.

67