Edgar Filing: CALPINE CORP

CPN_10Q_03.31.2012

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

____________________

Form 10-Q

(Mark One)



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

For the quarterly period ended March 31, 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: 482,831,387 shares of common stock, par value $0.001, were outstanding as of April 24, 2012.

CALPINE CORPORATION AND SUBSIDIARIES

REPORT ON FORM 10-Q

For the Quarter Ended March 31, 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 Months Ended March 31, 2012 and 2011	1
Consolidated Condensed Statements of Comprehensive Loss for the Three Months Ended March 31, 2012 and 2011	2
Consolidated Condensed Balance Sheets at March 31, 2012 and December 31, 2011	3
Consolidated Condensed Statements of Cash Flows for the Three Months Ended March 31, 2012 and 2011	4
Notes to Consolidated Condensed Financial Statements	6
Item 2. Management Discussion and Analysis of Financial Condition and Results of Operations	29
Forward-Looking Information	29
Introduction and Overview	29
Results of Operations	35
Commodity Margin and Adjusted EBITDA	38
Liquidity and Capital Resources	42
Risk Management and Commodity Accounting	48
New Accounting Standards and Disclosure Requirements	52
Item 3. Quantitative and Qualitative Disclosures About Market Risk	52
Item 4. Controls and Procedures	52

PART II – OTHER INFORMATION

Item 1. Legal Proceedings	53
Item 1A. Risk Factors	53
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	53
Item 3. Defaults Upon Senior Securities	53
Item 4. Mine Safety Disclosures	53
Item 5. Other Information	53
Item 6. Exhibits	54
Signatures	55

DEFINITIONS

As used in 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

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

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 employees and non-employee members of Calpine’s Board of Directors



ABBREVIATION		DEFINITION
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

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

Commodity Margin		Non-GAAP financial measure that includes power and steam revenues, sales of purchased power and physical natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, 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 emission 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

iii



ABBREVIATION		DEFINITION
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		Earnings before 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		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

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



ABBREVIATION		DEFINITION
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

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

NOL(s)		Net operating loss(es)

NOX		Nitrogen oxides

NYMEX		New York Mercantile Exchange

OCI		Other Comprehensive Income

OMEC		Otay Mesa Energy Center, LLC, an indirect, wholly owned subsidiary that owns the Otay Mesa Energy Center, a 608 MW natural gas-fired, combined-cycle power plant located in San Diego county, California

OTC		Over-the-Counter



ABBREVIATION		DEFINITION
PG&E		Pacific Gas & Electric Company

PJM		Pennsylvania-New Jersey-Maryland Interconnection

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 through the filing of this Report

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

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



ABBREVIATION		DEFINITION
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 the Whitby 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada

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;


•	Regulation in the markets in which we participate and our ability to effectively respond to changes in laws and regulations or the interpretation thereof including changing market rules and evolving federal, state and regional laws and regulations including those related to the environment and derivative transactions;


•	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, 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.

PART I — FINANCIAL INFORMATION


Item 1.	Financial Statements

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)



	Three Months Ended March 31,
	2012			2011
	(in millions, except share and per share amounts)
Operating revenues	$	1,236		$	1,499
Operating expenses:
Fuel and purchased energy expense	632			1,069
Plant operating expense	221			238
Depreciation and amortization expense	140			131
Sales, general and other administrative expense	33			32
Other operating expenses	24			20
Total operating expenses	1,050			1,490
(Income) from unconsolidated investments in power plants	(9		)	(9		)
Income from operations	195			18
Interest expense	185			191
Loss on interest rate derivatives	14			109
Interest (income)	(3		)	(3		)
Debt extinguishment costs	12			93
Other (income) expense, net	2			7
Loss before income taxes	(15		)	(379		)
Income tax benefit	(6		)	(83		)
Net loss	(9		)	(296		)
Net income attributable to the noncontrolling interest	—			(1		)
Net loss attributable to Calpine	$	(9	)	$	(297	)

Basic and diluted loss per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands)	478,106			486,191
Net loss per common share attributable to Calpine — basic and diluted	$	(0.02	)	$	(0.61	)

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

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE LOSS

(Unaudited)



	Three Months Ended March 31,
	2012			2011
	(in millions)
Net loss	$	(9	)	$	(296	)
Cash flow hedging activities:
Gain on cash flow hedges before reclassification adjustment for cash flow hedges realized in net loss	10			31
Reclassification adjustment for (gain) loss on cash flow hedges realized in net loss	(10		)	75
Foreign currency translation gain	3			1
Income tax (expense) benefit	2			(34		)
Other comprehensive income	5			73
Comprehensive loss	(4		)	(223		)
Comprehensive (income) attributable to the noncontrolling interest	—			(1		)
Comprehensive loss attributable to Calpine	$	(4	)	$	(224	)

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

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited)



	March 31,			December 31,
	2012			2011
	(in millions, except share and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents ($145 and $285 attributable to VIEs)	$	1,070		$	1,252
Accounts receivable, net of allowance of $13 and $13	386			598
Margin deposits and other prepaid expense	213			193
Restricted cash, current ($84 and $57 attributable to VIEs)	119			139
Derivative assets, current	1,403			1,051
Inventory and other current assets	293			329
Total current assets	3,484			3,562
Property, plant and equipment, net ($4,385 and $4,313 attributable to VIEs)	13,101			13,019
Restricted cash, net of current portion ($51 and $53 attributable to VIEs)	52			55
Investments	92			80
Long-term derivative assets	186			113
Other assets	541			542
Total assets	$	17,456		$	17,371
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	334		$	435
Accrued interest payable ($46 and $19 attributable to VIEs)	156			200
Debt, current portion ($39 and $41 attributable to VIEs)	103			104
Derivative liabilities, current	1,301			1,144
Other current liabilities	315			279
Total current liabilities	2,209			2,162
Debt, net of current portion ($2,626 and $2,522 attributable to VIEs)	10,392			10,321
Long-term derivative liabilities	257			279
Other long-term liabilities	237			245
Total liabilities	13,095			13,007

Commitments and contingencies (see Note 10)
Stockholders’ equity:
Preferred stock, $0.001 par value per share; authorized 100,000,000 shares, none issued and outstanding	—			—
Common stock, $0.001 par value per share; authorized 1,400,000,000 shares, 491,935,530 and 490,468,815 shares issued, respectively, and 482,797,421 and 481,743,738 shares outstanding, respectively	1			1
Treasury stock, at cost, 9,138,109 and 8,725,077 shares, respectively	(131		)	(125		)
Additional paid-in capital	12,310			12,305
Accumulated deficit	(7,708		)	(7,699		)
Accumulated other comprehensive loss	(173		)	(178		)
Total Calpine stockholders’ equity	4,299			4,304
Noncontrolling interest	62			60
Total stockholders’ equity	4,361			4,364
Total liabilities and stockholders’ equity	$	17,456		$	17,371

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

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)



	Three Months Ended March 31,
	2012			2011
	(in millions)
Cash flows from operating activities:
Net loss	$	(9	)	$	(296	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization expense⁽¹⁾	151			140
Debt extinguishment costs	—			80
Deferred income taxes	(1		)	(110		)
Loss on disposition of assets	2			5
Unrealized mark-to-market activities, net	(224		)	127
(Income) from unconsolidated investments in power plants	(9		)	(9		)
Stock-based compensation expense	6			5
Other	—			3
Change in operating assets and liabilities:
Accounts receivable	211			116
Derivative instruments, net	(66		)	(13		)
Other assets	20			65
Accounts payable and accrued expenses	(153		)	(11		)
Settlement of non-hedging interest rate swaps	151			43
Other liabilities	(8		)	4
Net cash provided by operating activities	71			149
Cash flows from investing activities:
Purchases of property, plant and equipment	(181		)	(144		)
Settlement of non-hedging interest rate swaps	(151		)	(43		)
Decrease in restricted cash	23			52
Purchases of deferred transmission credits	(8		)	(3		)
Other	3			—
Net cash used in investing activities	(314		)	(138		)
Cash flows from financing activities:
Borrowings under First Lien Term Loans	—			1,300
Repayments on NDH Project Debt	—			(1,283		)
Issuance of 2023 First Lien Notes	—			1,200
Repayments on First Lien Credit Facility	—			(1,184		)
Borrowings from project financing, notes payable and other	114			—
Repayments of project financing, notes payable and other	(38		)	(64		)
Capital contributions from noncontrolling interest holder	—			8
Financing costs	(5		)	(34		)
Stock repurchases	(6		)	—
Other	(4		)	(1		)
Net cash provided by (used in) financing activities	61			(58		)
Net decrease in cash and cash equivalents	(182		)	(47		)
Cash and cash equivalents, beginning of period	1,252			1,327
Cash and cash equivalents, end of period	$	1,070		$	1,280

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

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS — (CONTINUED)

(Unaudited)



	Three Months Ended March 31,
	2012		2011
	(in millions)
Cash paid during the period for:
Interest, net of amounts capitalized	$	226	$	156
Income taxes	$	6	$	6

Supplemental disclosure of non-cash investing activities:
Change in capital expenditures included in accounts payable	$	47	$	(2	)

____________


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

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

CALPINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

March 31, 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, 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 March 31, 2012 and December 31, 2011, we had cash and cash equivalents of $171 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.

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



	March 31, 2012						December 31, 2011
	Current		Non-Current		Total		Current		Non-Current		Total
Debt service⁽¹⁾	$	14	$	41	$	55	$	11	$	42	$	53
Rent reserve	3		—		3		—		—		—
Construction/major maintenance	38		7		45		33		10		43
Security/project/insurance	51		1		52		79		—		79
Other	13		3		16		16		3		19
Total	$	119	$	52	$	171	$	139	$	55	$	194

___________


(1)	At both March 31, 2012 and December 31, 2011, debt service included approximately $25 million of repurchase agreements with a financial institution containing maturity dates greater than one year.

Inventory — At March 31, 2012 and December 31, 2011, we had inventory of $256 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 March 31, 2012 and December 31, 2011, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):



	March 31, 2012		December 31, 2011
Buildings, machinery and equipment	$	15,118	$	15,074
Geothermal properties	1,176		1,163
Other	157		156
	16,451		16,393
Less: Accumulated depreciation	4,293		4,158
	12,158		12,235
Land	90		91
Construction in progress	853		693
Property, plant and equipment, net	$	13,101	$	13,019

Capitalized Interest — The total amount of interest capitalized was $8 million and $7 million for the three months ended March 31, 2012 and 2011, respectively.

Leases — We have contracts, such as certain tolling agreements, which we account for as operating leases under U.S. GAAP. Generally, we levelize 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 March 31, 2012, are as follows (in millions):



2012	$	395
2013	527
2014	452
2015	461
2016	375
Thereafter	2,269
Total	$	4,479

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 during the three months ended March 31, 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, we do not expect that the adoption of this standard will have a material impact on our results of operations, cash flows or financial condition.


2.	Variable Interest Entities and Unconsolidated Investments

We consolidate all of our VIEs where we have determined that we are the primary beneficiary. We have the following types of VIEs consolidated in our financial statements:

Subsidiaries with Project Debt — All of our subsidiaries with project debt not guaranteed by Calpine have PPAs that provide financial support and are thus considered VIEs. We retain ownership and absorb the full risk of loss and potential for reward once the project debt is paid in full. Actions by the lender to assume control of collateral can occur only under limited circumstances such as upon the occurrence of an event of default, which we have determined to be unlikely. See Note 3 for further information regarding our project debt and Note 1 for information regarding our restricted cash balances.

Subsidiaries with PPAs — Certain of our majority owned subsidiaries have PPAs that limit the risk and reward of our ownership and thus constitute a VIE.

VIEs with a Purchase Option — Riverside Energy Center and OMEC have agreements that provide third parties a fixed price option to purchase power plant assets exercisable in the years 2012 and 2019, respectively, with an aggregate capacity of 1,211 MW. Through the filing of this report, the option to purchase our Riverside Energy Center has not been exercised. These purchase options limit the risk and reward of our ownership and, thus, constitute a VIE.

Consolidation of VIEs

We consolidate our VIEs where we determine that we have both the power to direct the activities of a VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or receive benefits from the VIE. We have determined that we hold the obligation to absorb losses and receive benefits in all of our VIEs where we hold the majority equity interest. Therefore, our determination of whether to consolidate is based upon which variable interest holder has the power to direct the most significant activities of the VIE (the primary beneficiary). Our analysis includes consideration of the following primary activities which we believe to have a significant impact on a power plant's financial performance: operations and maintenance, plant dispatch, and fuel strategy as well as our ability to control or influence contracting and overall plant strategy. Our approach to determining which entity holds the powers and rights is based on powers held as of the balance sheet date. Contractual terms that may change the powers held in future periods, such as a purchase or sale option, are not considered in our analysis. Based on our analysis, we believe that we hold the power and rights to direct the most significant activities of all our majority owned VIEs.

Under our consolidation policy and under U.S. GAAP we also:


•	perform an ongoing reassessment each reporting period of whether we are the primary beneficiary of our VIEs; and

•

evaluate if an entity is a VIE and whether we are the primary beneficiary whenever any changes in facts and circumstances occur such that the holders of the equity investment at risk, as a group, lose the power from voting rights or similar rights of those investments to direct the activities of a VIE that most significantly impact the VIE's economic performance or when there are other changes in the powers held by individual variable interest holders.

There were no changes to our determination of whether we are the primary beneficiary of our VIEs for the three months ended March 31, 2012.

Noncontrolling Interest — We own a 75% interest in Russell City Energy Company, LLC, one of our VIEs, which is also 25% owned by a third party. We are the primary beneficiary and fully consolidate this entity in our Consolidated Condensed Financial Statements. We account for the third party ownership interest as a noncontrolling interest.

VIE Disclosures

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 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 whether 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.

The VIEs meeting the above disclosure criteria are majority owned subsidiaries of Calpine Corporation and include natural gas-fired power plants with an aggregate capacity of 11,392 MW, including 773 MW under construction, and 11,391 MW, including 584 MW under construction, at March 31, 2012 and December 31, 2011, respectively. In connection with the upgrade of our Los Esteros Critical Energy Facility, one of our VIEs, from a 188 MW simple-cycle power plant to a 309 MW combined-cycle generation power plant, our existing 188 MW simple-cycle power plant was shut down 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 a new PPA. 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. Calpine Corporation provided support to these VIEs in the form of cash and other contributions other than amounts contractually required of nil and $72 million during the three months ended March 31, 2012 and 2011, respectively.

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 March 31, 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 March 31, 2012	March 31, 2012		December 31, 2011
Greenfield LP	50%	81		72
Whitby	50%	11		8
Total investments		$	92	$	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 March 31, 2012 and December 31, 2011, equity method investee debt was approximately $466 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 $233 million and $231 million at March 31, 2012 and December 31, 2011, respectively.

Our equity interest in the net income from Greenfield LP and Whitby for the three months ended March 31, 2012 and 2011 are recorded in (income) from unconsolidated investments in power plants. The following table sets forth details of our (income) from unconsolidated investments in power plants for the periods indicated (in millions):



	Three Months Ended March 31,
	2012			2011
Greenfield LP	(6		)	(5		)
Whitby	(3		)	(4		)
Total	$	(9	)	$	(9	)

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 in the 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 nil during both the three months ended March 31, 2012 and 2011.

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 during both the three months ended March 31, 2012 and 2011.

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 7 and 14 after the start of commercial operation. GE holds a put option whereby they can require us to purchase the power plant, if certain plant performance criteria are met during year 15 after the start of commercial operation. We determined that we are not the primary beneficiary of the Inland Empire power plant, and we do not consolidate it due to, but not limited to, the fact that GE directs the most significant activities of the power plant including operations and maintenance.

Significant Subsidiary — Greenfield LP met the criteria of a significant unconsolidated subsidiary for the three months ended March 31, 2012, based upon the relationship of our net income from our investment to our consolidated net loss. The Condensed Statements of Operations for Greenfield LP for the three months ended March 31, 2012 and 2011, are set forth below (in millions):

Greenfield LP

Condensed Statements of Operations

(Unaudited)



	Three Months Ended March 31,
	2012			2011
Operating revenues	$	57		$	67
Operating expenses	40			50
Income from operations	17			17
Interest expense, net of interest income	7			7
Other (income) expense, net	(2		)	—
Net income	$	12		$	10


3.	Debt

Our debt at March 31, 2012 and December 31, 2011, was as follows (in millions):



	March 31, 2012		December 31, 2011
First Lien Notes	$	5,892	$	5,892
Project financing, notes payable and other	1,767		1,691
First Lien Term Loans	1,642		1,646
CCFC Notes	973		972
Capital lease obligations	221		224
Total debt	10,495		10,425
Less: Current maturities	103		104
Debt, net of current portion	$	10,392	$	10,321

First Lien Notes

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



	March 31, 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 and First Lien Term Loans, 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.

First Lien Term Loans

Our First Lien Term Loans provide for a senior secured term loan facility and 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 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 will be payable at the end of each quarter with the remaining balance payable on the maturity date (April 1, 2018). We may elect from time to time to convert all or a portion of the First Lien Term Loans from initial LIBOR rate loans to base rate loans or vice versa. In addition, we may at any time, and from time to time, prepay the First Lien Term Loans, in whole or in part, without premium or penalty, upon irrevocable notice to the administrative agent. We may also reprice the interest rate on the First Lien Term Loans, subject to

approval from the Lenders and subject to a 1% premium if a repricing transaction occurs prior to the first anniversary of the closing date. We may elect to extend the maturity of any term loans under the First Lien Term Loans, in whole or in part subject to approval from those lenders holding such term loans. The First Lien Term Loans are subject to certain qualifications and exceptions, similar to our First Lien Notes.

If a change of control triggering event occurs, the Company shall notify the administrative agent in writing and shall make an offer to prepay the entire principal amount of the First Lien Term Loans outstanding within thirty days after the date of such change of control triggering event.

In connection with the First Lien Term Loans, the Company and its subsidiaries (subject to certain exceptions) have made certain representations and warranties and are required to comply with various affirmative and negative covenants. The First Lien Term Loans are subject to customary events of default included in financing transactions, including, among others, failure to make payments when due, certain defaults under other material indebtedness, breach of certain covenants, breach of certain representations and warranties, involuntary or voluntary bankruptcy, and material judgments. If an event of default arises from certain events of bankruptcy or insolvency, all amounts outstanding under the First Lien Term Loans will become due and payable immediately without further action or notice. If other events of default arise (as defined in the Credit Agreement) and are continuing, the lenders holding more than 50% of the outstanding First Lien Term Loans (as defined in the Credit Agreement) may declare all the First Lien Term Loans outstanding to be due and payable immediately.

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 March 31, 2012, approximately $334 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 March 31, 2012, approximately $107 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 March 31, 2012 and December 31, 2011 (in millions):



	March 31, 2012		December 31, 2011
Corporate Revolving Facility	$	351	$	440
CDHI⁽¹⁾	226		193
Various project financing facilities	130		130
Total	$	707	$	763

__________


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

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%. 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 reborrowed, 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 amended the CDHI letter of credit facility to increase the 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 March 31, 2012 and December 31, 2011 (in millions):



	March 31, 2012				December 31, 2011
	Fair Value		Carrying Value		Fair Value		Carrying Value
First Lien Notes	$	6,395	$	5,892	$	6,219	$	5,892
Project financing, notes payable and other⁽¹⁾	1,565		1,606		1,467		1,504
First Lien Term Loans	1,640		1,642		1,615		1,646
CCFC Notes	1,100		973		1,070		972
Total	$	10,700	$	10,113	$	10,371	$	10,014

____________


(1)	Excludes leases that are accounted for as failed sale-leaseback transactions 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 debt instruments using market information, including quoted market prices or dealer quotes for the identical liability when traded as an asset (categorized as level 2) and 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. The following table presents the fair value of our debt instruments by level of the fair value hierarchy at March 31, 2012 (in millions):



	March 31, 2012
	Level 1		Level 2		Level 3		Total
First Lien Notes	$	—	$	6,395	$	—	$	6,395
Project financing, notes payable and other	—		—		1,565		1,565
First Lien Term Loans	—		1,640		—		1,640
CCFC Notes	—		1,100		—		1,100
Total	$	—	$	9,135	$	1,565	$	10,700


4.	Assets and Liabilities with Recurring Fair Value Measurements

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

Margin Deposits and Margin Deposits 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); market price levels, primarily for power and natural gas; our credit standing and that of our counterparties; 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 risks and 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.

On January 1, 2012, we adopted Accounting Standards Update 2011-04, “Fair Value Measurement.” At March 31, 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 for disclosure purposes 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. As the fair value of the net derivative position classified as level 3 is predominantly driven by market commodity rates, given the nature of our net derivative position, we do not believe that a significant change in commodity market rates would have a material impact on our level 3 fair value.

The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2012 and December 31, 2011, by level within the fair value hierarchy. 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.



	Assets and Liabilities with Recurring Fair Value Measures as of March 31, 2012
	Level 1		Level 2		Level 3		Total
	(in millions)
Assets:
Cash equivalents⁽¹⁾	$	1,212	$	—	$	—	$	1,212
Margin deposits	165		—		—		165
Commodity instruments:
Commodity futures contracts	1,439		—		—		1,439
Commodity forward contracts⁽²⁾	—		107		35		142
Interest rate swaps	—		8		—		8
Total assets	$	2,816	$	115	$	35	$	2,966
Liabilities:
Margin deposits held by us posted by our counterparties	$	111	$	—	$	—	$	111
Commodity instruments:
Commodity futures contracts	1,141		—		—		1,141
Commodity forward contracts⁽²⁾	—		230		18		248
Interest rate swaps	—		169		—		169
Total liabilities	$	1,252	$	399	$	18	$	1,669



	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 futures 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 futures 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 March 31, 2012 and December 31, 2011, we had cash equivalents of $1,067 million and $1,249 million included in cash and cash equivalents and $145 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 March 31,
	2012			2011
Balance, beginning of period	$	17		$	30
Realized and unrealized gains (losses):
Included in net loss:
Included in operating revenues⁽¹⁾	10			(6		)
Included in fuel and purchased energy expense⁽²⁾	(4		)	—
Included in OCI	4			1
Purchases, issuances and settlements:
Purchases	1			—
Issuances	(1		)	—
Settlements	(6		)	(13		)
Transfers in and/or out of level 3⁽³⁾:
Transfers into level 3⁽⁴⁾	—			—
Transfers out of level 3⁽⁵⁾	(4		)	—
Balance, end of period	$	17		$	12
Change in unrealized gains (losses) relating to instruments still held at end of period	$	6		$	(6	)

___________


(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 months ended March 31, 2012 and 2011.


(4)	There were no transfers out of level 2 into level 3 for the three months ended March 31, 2012 and 2011.


(5)	We had $4 million of transfers out of level 3 into level 2 for the three months ended March 31, 2012. There were no transfers out of level 3 for the three months ended March 31, 2011.


5.	Derivative Instruments

Types of Derivative Instruments and Volumetric Information

Commodity Instruments — We are exposed to changes in prices for the purchase and sale of power, natural gas 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 March 31, 2012, the maximum length of time over which we were hedging using interest rate derivative instruments designated as cash flow hedges was 12 years.

As of March 31, 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
Derivative Instruments	March 31, 2012			December 31, 2011
Power (MWh)	(23		)	(21		)
Natural gas (MMBtu)	(192		)	(200		)
Interest rate swaps⁽¹⁾	$	1,550		$	5,639

____________


(1)	Approximately $4.1 billion at December 31, 2011 was related to 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 March 31, 2012, was $155 million for which we have posted collateral of $99 million by posting margin deposits or granted additional first priority liens on the assets currently subject to first priority liens under our First Lien Notes, Corporate Revolving Facility and First Lien Term Loans. However, if our credit rating were downgraded by one notch from its current level, we estimate that additional collateral of $1 million would be required and that no counterparty could request immediate, full settlement.

Accounting for Derivative Instruments

We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Condensed Statements of Operations until the period of delivery. 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 will be 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.

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 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 income 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 three months ended March 31, 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 March 31, 2012 and December 31, 2011 (in millions):



	March 31, 2012
	Interest Rate Swaps			Commodity Instruments		Total Derivative Instruments
Balance Sheet Presentation
Current derivative assets	$	—		$	1,403	$	1,403
Long-term derivative assets	8			178		186
Total derivative assets	$	8		$	1,581	$	1,589

Current derivative liabilities	$	30		$	1,271	$	1,301
Long-term derivative liabilities	139			118		257
Total derivative liabilities	$	169		$	1,389	$	1,558
Net derivative assets (liabilities)	$	(161	)	$	192	$	31



	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	)



	March 31, 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	$	8	$	145	$	10	$	149
Commodity instruments	43		7		51		18
Total derivatives designated as cash flow hedging instruments	$	51	$	152	$	61	$	167

Derivatives not designated as hedging instruments:
Interest rate swaps	$	—	$	24	$	—	$	171
Commodity instruments	1,538		1,382		1,103		1,085
Total derivatives not designated as hedging instruments	$	1,538	$	1,406	$	1,103	$	1,256
Total derivatives	$	1,589	$	1,558	$	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):



	Three Months Ended March 31,
	2012			2011
Realized gain (loss)
Interest rate swaps	$	(157	)	$	(46	)
Commodity derivative instruments	118			10
Total realized gain (loss)	$	(39	)	$	(36	)

Unrealized gain (loss)⁽¹⁾
Interest rate swaps	$	146		$	(62	)
Commodity derivative instruments	78			(65		)
Total unrealized gain (loss)	$	224		$	(127	)
Total mark-to-market activity, net	$	185		$	(163	)

___________


(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 income, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.



	Three Months Ended March 31,
	2012			2011
Realized and unrealized gain (loss)
Power contracts included in operating revenues	$	92		$	(57	)
Natural gas contracts included in fuel and purchased energy expense	104			2
Interest rate swaps included in interest expense	3			1
Loss on interest rate derivatives	(14		)	(109		)
Total mark-to-market activity, net	$	185		$	(163	)

Derivatives Included in OCI and AOCI

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



	Three Months Ended March 31,
	Gains (Loss) Recognized in OCI (Effective Portion)					Gain (Loss) Reclassified from AOCI into Income (Effective Portion)⁽²⁾								Gain (Loss) Reclassified from AOCI into Income (Ineffective Portion)
	2012			2011		2012				2011				2012		2011
Interest rate swaps	$	1		$	103	$	(7	)	⁽³⁾	$	(101	)	⁽³⁾	$	—	$	—
Commodity derivative instruments	(1		)	3		17			⁽¹⁾	26			⁽¹⁾	2		—
Total	$	—		$	106	$	10			$	(75	)		$	2	$	—

____________


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


(2)	Cumulative cash flow hedge losses, net of tax, remaining in AOCI were $169 million and $172 million at March 31, 2012 and December 31, 2011, respectively.

(3)

Reclassification of losses from OCI to earnings consisted of $7 million and $10 million from the reclassification of interest rate contracts due to settlement for the three months ended March 31, 2012 and 2011, respectively, 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 three months ended March 31, 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 nine months as the related hedged transactions affect earnings. We estimate that pre-tax net gains of $4 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.


6.	Use of Collateral

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

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



	March 31, 2012		December 31, 2011
Margin deposits⁽¹⁾	$	165	$	140
Natural gas and power prepayments	37		42
Total margin deposits and natural gas and power prepayments with our counterparties⁽²⁾	$	202	$	182

Letters of credit issued	$	550	$	581
First priority liens under power and natural gas agreements	1		1
First priority liens under interest rate swap agreements	166		318
Total letters of credit and first priority liens with our counterparties	$	717	$	900

Margin deposits held by us posted by our counterpartie^s(1)(3)	$	111	$	34
Letters of credit posted with us by our counterparties	1		—
Total margin deposits and letters of credit posted with us by our counterparties	$	112	$	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 March 31, 2012 and December 31, 2011, $183 million and $162 million, respectively, were included in margin deposits and other prepaid expense and $19 million and $20 million were included in other assets at March 31, 2012 and December 31, 2011, respectively, on our Consolidated Condensed Balance Sheets.


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

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


7.	Income Taxes

Income Tax Benefit

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



	Three Months Ended March 31,
	2012			2011
Income tax benefit	$	(6	)	$	(83	)	⁽¹⁾
Imputed tax rate	40		%	22		%

_________


(1)	Represents approximately $76 million related to the election to consolidate our CCFC and Calpine groups for federal income tax reporting purposes and $34 million related to intraperiod tax allocation tax benefits offset by approximately $27 million of state and foreign tax expense.

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 (losses) with an offsetting amount recognized in OCI. The following table details the effects of our intraperiod tax allocations for the three months ended March 31, 2012 and 2011 (in millions).



	2012			2011
Intraperiod tax allocation expense (benefit) included in continuing operations	$	2		$	(34	)
Intraperiod tax allocation expense (benefit) included in OCI	$	(2	)	$	34

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 state 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. In 2012, we are continuing with our analysis and will adjust our state NOLs where appropriate.

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 of 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.

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 to our tax transfer pricing positions.

We continue to evaluate the proposed adjustments; however, based on our preliminary analysis, we believe that our transfer pricing tax positions policies are appropriate and 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 March 31, 2012, we had unrecognized tax benefits of $74 million. If recognized, $28 million of our unrecognized tax benefits could impact the annual effective tax rate and $46 million related to deferred tax assets which 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 $20 million for income tax matters at March 31, 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 March 31, 2012 remained comparable to the amount of unrecognized tax benefits at December 31, 2011. We believe it is reasonably possible that a decrease within the range of approximately nil and $2 million in unrecognized tax benefits could occur within the next 12 months primarily related to foreign tax issues.


8.	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 three months ended March 31, 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 three months ended March 31, 2012 and 2011, diluted loss per share for both periods is computed on the same basis as basic loss per share, as the inclusion of any other potential shares outstanding would be anti-dilutive. We excluded the following items from diluted loss per common share for the three months ended March 31, 2012 and 2011, because they were anti-dilutive (shares in thousands):



	2012	2011
Share-based awards	15,650	14,696


9.	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 March 31, 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 use our closing stock price on the date of grant, or the last trading day preceding the grant date for restricted stock granted on non-trading days, as the fair value for measuring compensation expense. Stock-based compensation expense is recognized over the period in which the related employee services are rendered. The service period is generally presumed to begin on the grant date and end when the equity award is fully vested. We use the graded vesting attribution method to recognize fair value of the equity award over the service period. For example, the graded vesting attribution method views one three-year 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 and $5 million for the three months ended March 31, 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 three months ended March 31, 2012 and 2011. At March 31, 2012, there was unrecognized compensation cost of $12 million related to options, $29 million related to restricted stock and nil related to restricted stock units, which is expected to be recognized over a weighted average period of 1.2 years for options, 1.6 years for restricted stock and 0.1 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 three months ended March 31, 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	879,527	$	15.31
Exercised	7,300	$	16.90
Forfeited	34,604	$	12.10
Expired	44,200	$	17.69
Outstanding — March 31, 2012	18,459,325	$	17.23	4.8	$	35
Exercisable — March 31, 2012	8,262,451	$	19.48	4.3	$	3
Vested and expected to vest – March 31, 2012	17,987,325	$	17.31	4.7	$	33

The total intrinsic value and the cash proceeds received from our employee stock options exercised were not significant for the three months ended March 31, 2012 and 2011.

The fair value of options granted during the three months ended March 31, 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⁾	1.6		%	3.2		%
Expected volatility⁽³⁾	30		%	31		%
Dividend yield⁽⁴⁾	—			—
Weighted average grant-date fair value (per option)	$	5.18		$	5.48

___________


(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.


(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 three months ended March 31, 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	1,504,473	$	15.31
Forfeited	45,058	$	12.82
Vested	72,484	$	13.75
Nonvested — March 31, 2012	4,897,289	$	13.06

The total fair value of our restricted stock that vested during the three months ended March 31, 2012 and 2011, was approximately $1 million and $6 million, respectively.


10.	Commitments and Contingencies

Litigation

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


11.	Segment Information

We assess our business on a regional basis due to the impact on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors impacting supply and demand. At March 31, 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.

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



	Three Months Ended March 31, 2012
	West		Texas		North			Southeast		Consolidation and Elimination			Total
Revenues from external customers	$	416	$	356	$	298		$	166	$	—		$	1,236
Intersegment revenues	4		20		3			22		(49		)	—
Total operating revenues	$	420	$	376	$	301		$	188	$	(49	)	$	1,236
Commodity Margin	$	208	$	109	$	144		$	56	$	—		$	517
Add: Mark-to-market commodity activity, net and othe^r(1)(2)	36		34		12			10		(8		)	84
Less:
Plant operating expense	81		68		45			33		(6		)	221
Depreciation and amortization expense	50		35		33			23		(1		)	140
Sales, general and other administrative expense	8		11		6			8		—			33
Other operating expenses⁽³⁾	11		2		9			1		(2		)	21
(Income) from unconsolidated investments in power plants	—		—		(9		)	—		—			(9		)
Income from operations	94		27		72			1		1			195
Interest expense, net of interest income													182
Loss on interest rate derivatives													14
Debt extinguishment costs and other (income) expense, net													14
Loss before income taxes													$	(15	)



	Three Months Ended March 31, 2011
	West		Texas			North			Southeast			Consolidation and Elimination			Total
Revenues from external customers	$	599	$	450		$	271		$	179		$	—		$	1,499
Intersegment revenues	3		5			8			45			(61		)	—
Total operating revenues	$	602	$	455		$	279		$	224		$	(61	)	$	1,499
Commodity Margin	$	233	$	67		$	135		$	54		$	—		$	489
Add: Mark-to-market commodity activity, net and other⁽¹⁾	5		(60		)	4			(4		)	(6		)	(61		)
Less:
Plant operating expense	87		80			45			33			(7		)	238
Depreciation and amortization expense	46		30			33			23			(1		)	131
Sales, general and other administrative expense	11		10			6			5			—			32
Other operating expenses⁽³⁾	8		—			7			1			2			18
(Income) from unconsolidated investments in power plants	—		—			(9		)	—			—			(9		)
Income (loss) from operations	86		(113		)	57			(12		)	—			18
Interest expense, net of interest income															188
Loss on interest rate derivatives															109
Debt extinguishment costs and other (income) expense, net															100
Loss before income taxes															$	(379	)

__________


(1)	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 for the three months ended March 31, 2012 and 2011.


(2)	Includes $(8) million of lease levelization and $4 million of amortization expense for the three months ended March 31, 2012 related to contracts that became effective in June and August 2011.


(3)	Excludes $3 million and $2 million of RGGI compliance and other environmental costs for the three months ended March 31, 2012 and 2011, respectively, which are components of Commodity Margin.


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 shareholder value through our capital allocation and share repurchases and to set the foundation for continued growth and success with the following achievements during the first quarter of 2012:


•	We produced over 29 million MWh of electricity in the first quarter of 2012 (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 our lowest first quarter forced outage factor on record of 1.1%.


•	Our entire fleet achieved our highest first quarter starting reliability on record of 98%.


•	During the first quarter of 2012, we did not have a lost-time incident, our first time 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.


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

•


•	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 related to our Mid-Atlantic and Texas markets.

Our portfolio, including partnership interests, consists of 93 power plants, including 2 under construction, located throughout 20 states in the U.S. and Canada, with an aggregate generation capacity of 27,967 MW and 773 MW under construction. In connection with 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, our existing 188 MW simple-cycle power plant was shut down 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 a new PPA. Our fleet generation capacity includes 77 natural gas-fired power plants, 15 geothermal plants and 1 photovoltaic solar plant consisting of approximately 725 MW of baseload capacity from our Geysers Assets and 4,561 MW of baseload capacity from our cogeneration power plants, 16,393 MW of intermediate load capacity from our combined-cycle combustion turbines and 6,288 MW of peaking capacity from our simple-cycle combustion turbines and duct-fired capability, which includes approximately 4 MW of capacity from photovoltaic solar power generation technology located in New Jersey. Our segments have an aggregate generation capacity of 6,731 MW with an additional 773 MW under construction in the West, 7,239 MW in Texas, 7,914 MW in the North and 6,083 MW in the Southeast. Our Geysers Assets, included in our West segment, have generation capacity of approximately 725 MW from 15 operating geothermal power plants.

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”). These rules limit, for the first time, emissions of mercury, acid gases and other metals from coal and oil-fired power plants. 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 about 600 power plants.We are not directly affected by the rule 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 proposed emission standards are sufficiently stringent to force coal units without emission controls to be retired or to install acid gas, mercury, and particulate matter controls by April 16, 2015, which could benefit our competitive position. On February 16, 2012, three parties filed petitions for review with the U.S. Court of Appeals for the D.C. Circuit (“D.C. Circuit”) challenging MATS. These petitions were consolidated under one docket number, along with two other petitions. On March 19, 2012, Calpine filed a motion for leave to intervene in the consolidated case on behalf of the EPA. Prior to the April 16, 2012 petition filing deadline, at least 25 additional lawsuits, including petitions filed by 24 states, have been filed challenging MATS.

Cross-State Air Pollution Rule

On July 6, 2011, the EPA finalized rules to control interstate transportation of fine particulate matter (PM-2.5) and ozone. The Cross-State Air Pollution Rule (“CSAPR”) requires substantial emissions reductions of NOx and SO2 from electric generating units in 27 states primarily in the eastern U.S. The rule sets up three distinct cap-and-trade programs: annual NOx and SO2 trading programs to control fine particles, and a NOx trading program from May through September (the ozone season) to control ozone. Emission reductions were scheduled to take effect starting January 1, 2012 for SO2 and annual NOx reductions and May 1, 2012 for ozone season NOx reductions. Significant additional SO2 emission reductions in Group 1 states will be required in 2014. Compared to 2005, the EPA estimates that by 2014 this rule and other federal rules will lower power plant annual emissions in the CSAPR region by 6.4 million tons per year of SO2 (a 73% reduction) and 1.4 million tons per year of NOx (a 54% reduction). The rule 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 will be allocated sufficient allowances; thus, CSAPR is not expected to have a material impact on our operations. We expect the overall impact of this rule to be positive to Calpine as the significant emission reductions require coal-fired electric generating units to either purchase allowances, switch to more expensive fuels, install air pollution controls, or reduce or discontinue operations.

On October 14, 2011, the EPA proposed revisions to CSAPR to address discrepancies in unit-specific modeling assumptions that affect state budgets in Texas, Florida, Louisiana, Michigan, Mississippi, Nebraska, New Jersey, New York and Wisconsin. In addition, the EPA proposed delaying the assurance provisions, which were established to ensure that states’ emissions do not exceed their emissions budgets plus a variability allowance. The proposed two-year delay in the assurance provisions would allow unlimited interstate trading of CSAPR allowances, thereby providing more compliance options for affected sources. In addition, the EPA finalized a supplemental rule that includes five additional states - Iowa, Michigan, Missouri, Oklahoma and Wisconsin - in CSAPR’s seasonal NOx emission trading program.

A number of power generation companies, states and other groups have filed petitions for review in the D.C. Circuit challenging CSAPR. Several of these petitioners have also filed motions for either full or partial stays of the Rule. Calpine and other power generation companies have been granted intervenor status on behalf of respondent EPA. On December 30, 2011, the D.C. Circuit stayed CSAPR pending the court’s review of the merits of the challenges to CSAPR. The court also restored CSAPR’s predecessor, CAIR, for the 2012 compliance year. Oral arguments took place on April 13, 2012. Calpine continues to participate as a respondent intervenor in the court proceedings.

California: GHG (AB 32)

California's AB 32 creates a statewide cap on GHG emissions and requires the state to return to 1990 emission levels by 2020. On October 20, 2011, CARB adopted final cap-and-trade and mandatory reporting regulations which were approved by the Office of Administrative Law on December 15, 2011. The regulations took effect on January 1, 2012 and CARB has begun to implement the program. The first compliance year for which covered sources, including Calpine, will have to turn in allowances has been moved from 2012 to 2013; however, CARB is implementing other requirements of the cap-and-trade regulation including registering covered entities and testing the necessary auction infrastructure. CARB will conduct one practice auction in August 2012 to test the auction system and conduct the first real auction in November 2012. 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. 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, on October 20, 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 March 30, 2012, CARB published a discussion draft of proposed amendments to link and harmonize California’s and Quebec’s cap-and-trade programs, including making several changes to the provisions governing the auction and trading of allowances. Besides California, Quebec is the only other member of the Western Climate Initiative to have completed development of a GHG cap-and-trade program and be in a position to begin implementing a linked program in 2013. CARB plans to finalize the linking amendments to the cap-and-trade regulation in late June 2012 and may complete additional changes to the regulation in 2012, prior to the first auction in November 2012. Overall, we support AB 32 and believe we are favorably 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 emission controls on some of our units. 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. PJM must approve the deactivation of these units or compensate us for the cost of modifying the units to keep them operational. We are awaiting PJM’s response to our notice. The retirement of these power plants will not have a material impact on our financial condition or results of operations. We continue to evaluate the cost to comply with these air regulations on our remaining three peaker power plants subject to the air regulations and are uncertain of the impact to our financial condition or results of operations.

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. On March 28, 2011, the EPA proposed rules (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 (where fish and other aquatic life get trapped against the intake screens) and entrainment (where small aquatic life passes through the intake screens and goes through the condenser at high temperatures). 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.

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 now 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 utilities that are not CPUC-jurisdictional. 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.

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. Most existing California QFs are under QF contracts. The settlement 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 are exploring similar opportunities for some of our other California QFs. In addition, we are participating in the IOUs’ ongoing CHP solicitations. The impact of the settlement has been positive to Calpine.

PJM Capacity Market

Recently, 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. Market participants and others were concerned that awarding long-term contracts could impact the clearing prices of future PJM capacity auctions. 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. 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, FERC issued an order on April 12, 2011 approving PJM's MOPR tariff changes. FERC’s MOPR order is currently on appeal before the Court of Appeals for the Third Circuit. 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. The court proceeding is continuing.

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 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 is scheduled to have a COD of June 1, 2015. Based on these events, we are currently considering our options.

ERCOT Scarcity Pricing

In April 2012, the PUCT recommended two proposed rulemakings in connection with its proceedings on Resource and Reserve Adequacy and Shortage Pricing. The first rulemaking will consider increasing the current system-wide offer cap of $3,000/MWh to $4,500/MWh for the period August 1, 2012 through May 31, 2013. A proposed alternate rule would increase the cap in annual increments beginning in June 2013, escalating up to $9,000/MWh by June 2015. The second rulemaking will also consider whether the offer cap should be raised to $12,000 - $15,000/MWh range. Consistent with current ERCOT practice, the top price for the ERCOT Power Balance Penalty Curve (“PBPC”) will be revised to match each increase of the offer cap. The slope of the PBPC also will be revised by ERCOT, increasing the starting price from $200/MWh to $500/MWh. ERCOT will be responsible for revising ancillary services used for capacity (non-spinning reserve service, responsive reserves, regulation up service and reliability unit commitment) and reliability must run units for capacity to reflect each new offer cap.

At the direction of the PUCT, stakeholders and ERCOT staff have implemented additional changes which include shifting 500 MW of non-spinning reserve service to the responsive reserve service, establishing the price paid for energy from reliability unit commitment units at the system-wide offer cap, and setting the price paid for energy from responsive reserves and regulation up service at the system-wide offer cap. With these changes, we expect more scarcity pricing conditions to arise which should have a positive impact on our Commodity Margin.

Sutter Energy Center

Our Sutter power plant, which is a 578 MW combined-cycle natural gas-fired power plant, has no contracts for its output in 2012. In late 2011, we determined that the power plant will be uneconomic and may have to be shut down absent incremental compensation. Consequently, on November 22, 2011, we submitted a request to the CAISO to compensate our Sutter power plant under a provision of CAISO's current tariff that is intended to avoid retirement of needed generating units. 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. Upon review of our request, the CAISO determined we had met all of the requirements for such compensation. However, the CAISO also determined that the need for our Sutter power plant cannot be demonstrated in the following year (as required by the current tariff), but some time later. On January 26, 2012, the CAISO submitted a request to FERC seeking a narrow waiver of its tariff to allow such designation and compensation for our Sutter power plant. In parallel, we submitted a notice to the CPUC indicating that the operational status of our Sutter power plant may change. 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. The outcome of these negotiations is uncertain at this time.

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 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. SPP requests a FERC order by July 31, 2012. We believe the proposed market structure is generally beneficial to our Oneta power plant 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 will 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; however, after extended negotiations to modify the agreement to address the financial impacts, Greenfield LP has initiated arbitration as provided for under the power supply contract to preserve its recovery rights. We continue to pursue arbitration of this matter and cannot predict at this time the outcome of arbitration, or the potential impact, if any, to our 50% partnership interest in Greenfield LP. The Ontario government recently announced its intent to introduce legislation to merge the OPA and IESO. If passed, we do not anticipate the merger to result in any further adverse impact to Greenfield LP’s power supply contract.

Federal Litigation on EPA Regulation of GHG Emissions

On April 2, 2007, the U.S. Supreme Court ruled that the EPA has the authority to regulate GHG emissions under the CAA. As a result of this ruling, the EPA is moving forward to regulate GHG emissions pursuant to its existing authority under the CAA. On December 7, 2009, the EPA made an “endangerment finding” with respect to GHGs, determining that current and projected concentrations of six key GHGs endanger the public health and welfare of current and future generations. As part of the EPA’s initiative to regulate GHGs, on May 13, 2010, the EPA finalized regulations referred to as the “Tailoring Rule” to require new sources emitting over 100,000 tons per year (a “major” source) of GHG emissions or modifications to existing major sources that would increase their GHG emissions by greater than 75,000 tons per year to undergo a major new source review (“NSR”). Beginning in January 2011, sources or modifications already required to obtain a prevention of significant deterioration (“PSD”) permit due to their emissions of conventional regulated pollutants were required to satisfy best available control technology (“BACT”) requirements for GHG as well. Beginning in July 2011, new sources and modifications exceeding the 100,000 and 75,000 tons per year thresholds, respectively, were required to obtain a PSD permit and satisfy BACT requirements for GHGs, regardless of their emissions of any conventional pollutants. The EPA has issued guidance to permitting authorities on the

implementation of GHG BACT that focuses on energy efficiency, but requires consideration of carbon capture and storage (“CCS”) as available technology for high-emitting industries, although the EPA acknowledges that CCS may be eliminated as technically infeasible or excessively costly at this time. We believe that the impact of the final 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.

On August 2, 2010, a coalition of approximately 20 members representing manufacturing, oil and gas facilities, refineries, and small businesses, filed a petition for review of the Tailoring Rule. The petition was consolidated with a prior petition from the coalition challenging the EPA’s “Timing Rule,” which clarified the timeframe for PSD regulation of GHGs to take effect, and numerous related petitions filed by states, environmental organizations, and other industry groups. There are currently over 70 parties in the consolidated litigation, Coalition for Responsible Regulations, Inc. v. U.S. Environmental Protection Agency. Oral argument for all of the petitions challenging the EPA’s suite of GHG regulations and policies was heard on February 28-29, 2012 in the D.C. Circuit.

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

CFTC Regulation of Derivatives Transactions

Many aspects of the Dodd-Frank Act, which was signed into law on July 21, 2010, are subject to rulemaking that will take effect over future periods, thus making it difficult to assess its impact on us at this time.

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. While the effective date for the CFTC to implement all final regulations related to Title VII is July 16, 2012, the CFTC has already stated that it will not meet this deadline. 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 derivatives 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. Which OTC derivatives transactions will be subject to mandatory central clearing has not yet been determined. Further, the central clearing requirement is subject to an end-user exception; however, we are still waiting for final rulemaking from the CFTC to determine whether we will qualify as a commercial end-user and may benefit from such an exception under the regulations. If we do not qualify as a commercial end-user, it is highly likely that we will be required to register as a dealer of commodities with the CFTC, and we will be required to perform additional activities within our transaction processes to comply with the regulations; however, our compliance activities will not have a material adverse effect on our financial condition or results of operations. Other features of the Dodd-Frank Act which will have an impact on our derivatives activities include trade reporting, position limits 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.

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, 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, if any, related to the implementation of, or compliance with, the potential future requirements under the Dodd-Frank Act.

RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 2012 AND 2011

Below are our results of operations for the three months ended March 31, 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	$	1,216		$	1,520		$	(304	)	(20	)
Mark-to-market activity⁽¹⁾	22			(25		)	47			#
Other⁽²⁾	(2		)	4			(6		)	#
Operating revenues	1,236			1,499			(263		)	(18	)
Operating expenses:
Fuel and purchased energy expense:
Commodity expense	688			1,029			341			33
Mark-to-market activity⁽¹⁾	(56		)	40			96			#
Fuel and purchased energy expense	632			1,069			437			41
Plant operating expense	221			238			17			7
Depreciation and amortization expense	140			131			(9		)	(7	)
Sales, general and other administrative expense	33			32			(1		)	(3	)
Other operating expenses⁽³⁾	24			20			(4		)	(20	)
Total operating expenses	1,050			1,490			440			30
(Income) from unconsolidated investments in power plants	(9		)	(9		)	—			—
Income from operations	195			18			177			#
Interest expense	185			191			6			3
Loss on interest rate derivatives	14			109			95			87
Interest (income)	(3		)	(3		)	—			—
Debt extinguishment costs	12			93			81			87
Other (income) expense, net	2			7			5			71
Loss before income taxes	(15		)	(379		)	364			96
Income tax benefit	(6		)	(83		)	(77		)	(93	)
Net loss	(9		)	(296		)	287			97
Net income attributable to the noncontrolling interest	—			(1		)	1			#
Net loss attributable to Calpine	$	(9	)	$	(297	)	$	288		97



	2012		2011		Change		% Change
Operating Performance Metrics:
MWh generated (in thousands)⁽⁴⁾	28,055		18,127		9,928		55
Average availability	90.3	%	88.9	%	1.4	%	2
Average total MW in operation⁽⁴⁾	27,187		26,904		283		1
Average capacity factor, excluding peakers	54.9	%	36.9	%	18.0	%	49
Steam Adjusted Heat Rate	7,272		7,369		97		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 the three months ended March 31, 2012, related to an acquired contract that became effective in June 2011.


(3)	Includes $3 million and $2 million of RGGI compliance and other environmental costs for the three months ended March 31, 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 $37 million for the three months ended March 31, 2012, compared to the three months ended March 31, 2011, primarily due to:


•	an increase in generation driven by lower natural gas prices in the first quarter of 2012 compared to the first quarter of 2011;


•	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 first quarter of 2011, which did not reoccur in the first quarter of 2012; partially offset by


•	lower revenue in the first quarter of 2012 due to lower regulatory capacity prices and the expiration of contracts subsequent to the first quarter of 2011; and


•	lower super-peak prices in Texas and the North due to milder weather conditions during the first quarter of 2012 compared to the first quarter of 2011.

Generation increased 55% driven by lower natural gas prices, which was also the primary driver of a 49% increase in our average capacity factor, excluding peakers, and our York Energy Center which achieved COD in March 2011. Our average total MW in operation increased by 283 MW, or 1%, primarily due to our 565 MW York Energy Center partially offset by the temporary shut down of our Los Esteros Critical Energy Facility to allow for major maintenance on the combustion turbines and installation of new heat recovery steam generators and a steam turbine generator associated with the upgrade from a simple-cycle power plant to a combined-cycle power plant in connection with a new PPA.

Unrealized mark-to-market earnings from hedging our future generation and fuel needs had a favorable variance of $143 million primarily driven by the impact of an overall decrease in forward power and natural gas prices on both power and natural gas hedges during the three months ended March 31, 2012, when compared to the decrease in power and natural gas prices for the same period during 2011.

Other revenue decreased for the three months ended March 31, 2012, compared to the three months ended March 31, 2011, due primarily to $4 million of amortization expense on intangible contract values related to an acquired contract that became effective in June 2011.

Plant operating expense decreased by $17 million for the three months ended March 31, 2012, compared to the three months ended March 31, 2011, due to a $14 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. Aside from this decrease, plant operating expense was unchanged despite a 55% increase in generation in the first quarter of 2012 compared to the first quarter of 2011. Our variable operating costs increased though were offset by lower repair and maintenance costs. The increase in generation also resulted in a 1% decrease in our Steam Adjusted Heat Rate for the three months ended March 31, 2012, compared to the same period in 2011 as our power plants tend to operate more efficiently under baseload operations.

Depreciation and amortization expense increased for the three months ended March 31, 2012, compared to the three months ended March 31, 2011, primarily resulting from a decrease of $10 million in the first quarter of 2011 related to a revision in the expected settlement dates of the asset retirement obligations related to our gas-fired power plants.

Interest expense decreased for the three months ended March 31, 2012, compared to the three months ended March 31, 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 7.4% for the three months ended March 31, 2012, from 7.9% for the three months ended March 31, 2011.

Loss on interest rate derivatives had a favorable change of $95 million for the three months ended March 31, 2012, compared to the three months ended March 31, 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 issuance of the 2023 First Lien Notes. See

Note 5 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 three months ended March 31, 2012, consisted of $12 million associated with the purchase of two of the 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 three months ended March 31, 2011, consisted of $74 million associated with the repayment of the NDH Project Debt in March 2011 and $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.

During the three months ended March 31, 2012, we recorded an income tax benefit of $6 million compared to an income tax benefit of $83 million for the three months ended March 31, 2011. The 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 in 2011 for federal income tax reporting purposes.

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 11 of the Notes to Consolidated Condensed Financial Statements for a reconciliation of Commodity Margin to income (loss) from operations by segment.

Commodity Margin by Segment for the Three Months Ended March 31, 2012 and 2011

The following tables show our Commodity Margin and related operating performance metrics by segment for the three months ended March 31, 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 represents generation from power plants that we both consolidate and operate.



West:	2012			2011			Change			% Change
Commodity Margin (in millions)	$	208		$	233		$	(25	)	(11	)
Commodity Margin per MWh generated	$	25.36		$	37.61		$	(12.25	)	(33	)

MWh generated (in thousands)	8,203			6,195			2,008			32
Average availability	93.5		%	91.9		%	1.6		%	2
Average total MW in operation	6,731			6,886			(155		)	(2	)
Average capacity factor, excluding peakers	60.3		%	46.3		%	14.0		%	30
Steam Adjusted Heat Rate	7,140			7,386			246			3

West — Commodity Margin in our West segment decreased by $25 million, or 11%, for the three months ended March 31, 2012 compared to the same period in 2011, primarily resulting from lower revenue due to the expiration of regulatory capacity contracts and a PPA, as well as our Sutter power plant which did not run in the first quarter of 2012. In addition, despite higher Spark Spreads and generation, we realized a lower Commodity Margin contribution from hedges associated with our Geysers Assets which are based on absolute power price. The 32% increase in generation resulted from higher Spark Spreads driven by lower hydroelectric generation in California in the first quarter of 2012 compared to the first quarter of 2011. Our average total MW in operation decreased 155 MW, or 2%, due primarily to the temporary shut down of our Los Esteros Critical Energy Facility at the end of 2011 to allow for major maintenance on the combustion turbines and installation of new heat recovery steam generators and a steam turbine generator associated with the upgrade from a simple-cycle power plant to a combined-cycle power plant in connection with a new PPA. Although our Sutter power plant did not run in the first quarter of 2012, this plant has not been removed from service and remains available to generate power in California.



Texas:	2012			2011			Change			% Change
Commodity Margin (in millions)	$	109		$	67		$	42		63
Commodity Margin per MWh generated	$	11.92		$	12.60		$	(0.68	)	(5	)

MWh generated (in thousands)	9,143			5,319			3,824			72
Average availability	85.7		%	79.6		%	6.1		%	8
Average total MW in operation	7,003			6,961			42			1
Average capacity factor, excluding peakers	59.8		%	35.4		%	24.4		%	69
Steam Adjusted Heat Rate	7,081			7,253			172			2

Texas — Commodity Margin in our Texas segment increased by $42 million, or 63%, for the three months ended March 31, 2012 compared to the same period in 2011, due to a 72% increase in generation driven by lower natural gas prices and an increase in Commodity Margin earned during overnight periods related to the must-run obligations of certain of our cogeneration power plants, partially offset by lower on-peak and super-peak prices resulting from milder weather conditions during the first quarter of 2012 compared to the first quarter of 2011. During the first quarter of 2012, generation increased as natural gas prices were low enough that some of our Texas combined-cycle natural gas-fired power plants became less expensive on a marginal basis than coal-fired generation resulting in these plants running baseload during certain periods. 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 8% resulting from a decrease in scheduled and unscheduled outages in the first quarter of 2012 compared to the same period in 2011.



North:	2012			2011			Change			% Change
Commodity Margin (in millions)	$	144		$	135		$	9		7
Commodity Margin per MWh generated	$	28.88		$	57.99		$	(29.11	)	(50	)

MWh generated (in thousands)	4,987			2,328			2,659			#
Average availability	89.1		%	91.1		%	(2.0		)%	(2	)
Average total MW in operation	7,370			6,974			396			6
Average capacity factor, excluding peakers	47.1		%	24.1		%	23.0		%	95
Steam Adjusted Heat Rate	7,818			7,746			(72		)	(1	)

North — Commodity Margin in our North segment increased by $9 million, or 7%, for the three months ended March 31, 2012 compared to the three months ended March 31, 2011. Despite lower regulatory capacity revenues and lower super-peak prices resulting from milder weather conditions in the first quarter of 2012, Commodity Margin increased primarily due to our York Energy Center which achieved COD in March 2011, an increase in Commodity Margin from fixed-price power contracts which benefited from Spark Spread expansion and higher generation driven by lower natural gas prices. During the first quarter of 2012, generation increased as natural gas prices were low enough that some of our Mid-Atlantic combined-cycle natural gas-fired power plants became less expensive on a marginal basis than coal-fired generation resulting in these power plants running baseload during certain periods. The increase in generation was also the primary driver of the 95% increase in average capacity factor, excluding peakers for the three months ended March 31, 2012 compared to the same period in 2011. Average total MW in operation increased 396 MW, or 6%, due primarily to our 565 MW York Energy Center which achieved COD in March 2011. Our Steam Adjusted Heat Rate increased due to higher dispatch of generating units with higher Heat Rates during the three months ended March 31, 2012 compared to the same period in 2011.



Southeast:	2012			2011			Change			% Change
Commodity Margin (in millions)	$	56		$	54		$	2		4
Commodity Margin per MWh generated	$	9.79		$	12.60		$	(2.81	)	(22	)

MWh generated (in thousands)	5,722			4,285			1,437			34
Average availability	94.1		%	94.4		%	(0.3		)%	—
Average total MW in operation	6,083			6,083			—			—
Average capacity factor, excluding peakers	48.7		%	38.1		%	10.6		%	28
Steam Adjusted Heat Rate	7,271			7,298			27			—

Southeast — Commodity Margin in our Southeast segment increased by $2 million, or 4%, for the three months ended March 31, 2012 compared to the same period in 2011, primarily due to higher generation which increased 34% with a resulting 28% increase in our average capacity factor, excluding peakers, largely driven by higher generation at power plants contracted and dispatched by third parties during the first quarter of 2012 compared to the first quarter of 2011. The increase in Commodity Margin was largely offset by lower revenues resulting from the expiration of a PPA subsequent to the first quarter of 2011.

Adjusted EBITDA

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



	Three Months Ended March 31, 2012
	West			Texas			North			Southeast			Consolidation and Elimination			Total
Net loss attributable to Calpine																$	(9	)
Income tax benefit																(6		)
Debt extinguishment costs and other (income) expense, net																14
Loss on interest rate derivatives																14
Interest expense, net																182
Income from operations	$	94		$	27		$	72		$	1		$	1		$	195
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs⁽¹⁾	50			35			33			24			(1		)	141
Major maintenance expense	10			23			7			6			—			46
Operating lease expense	2			—			7			—			—			9
Unrealized (gain) on commodity derivative mark-to-market activity	(30		)	(29		)	(10		)	(9		)	—			(78		)
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			1			—			—			—			2
Acquired contract amortization	—			—			4			—			—			4
Other	(4		)	—			(4		)	1			—			(7		)
Total Adjusted EBITDA	$	125		$	59		$	117		$	24		$	—		$	325



	Three Months Ended March 31, 2011
	West			Texas			North			Southeast			Consolidation and Elimination		Total
Net loss attributable to Calpine															$	(297	)
Net income attributable to the noncontrolling interest															1
Income tax benefit															(83		)
Debt extinguishment costs and other (income) expense, net															100
Loss on interest rate derivatives															109
Interest expense, net															188
Income (loss) from operations	$	86		$	(113	)	$	57		$	(12	)	$	—	$	18
Add:
Adjustments to reconcile income (loss) from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs⁽¹⁾	45			30			33			24			—		132
Major maintenance expense	7			38			6			9			—		60
Operating lease expense	2			—			6			—			—		8
Unrealized (gain) loss on commodity derivative mark-to-market activity	(2		)	65			(3		)	5			—		65
Adjustments to reflect Adjusted EBITDA from unconsolidated investments⁽²⁾⁽³⁾	—			—			8			—			—		8
Stock-based compensation expense	3			1			1			—			—		5
Loss on dispositions of assets	1			3			—			1			—		5
Other	—			—			2			—			—		2
Total Adjusted EBITDA	$	142		$	24		$	110		$	27		$	—	$	303

_____________


(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 both the three months ended March 31, 2012 and 2011.

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 March 31, 2012, we had $1,070 million in cash and cash equivalents and $171 million of restricted cash. Amounts available for future borrowings were $649 million under our Corporate Revolving Facility. The following table provides a summary of our liquidity position at March 31, 2012 and December 31, 2011 (in millions):



	March 31, 2012		December 31, 2011
Cash and cash equivalents, corporate⁽¹⁾	$	899	$	946
Cash and cash equivalents, non-corporate	171		306
Total cash and cash equivalents	1,070		1,252
Restricted cash	171		194
Corporate Revolving Facility availability	649		560
Letter of credit availability⁽²⁾	74		7
Total current liquidity availability	$	1,964	$	2,013

____________


(1)	Includes $111 million and $34 million of margin deposits held by us posted by our counterparties at March 31, 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 April 13, 2012, an increase of $1/MMBtu in natural gas prices would result in an increase of collateral required by approximately $538 million. If natural gas prices decreased by $1/MMBtu, we estimate that our collateral requirements would decrease by approximately $487 million. Changes in Market Heat Rates also affect our liquidity. For example, as demand increases, less efficient generation is dispatched, which increases the Market Heat Rate and results in increased collateral requirements. Historical relationships of natural gas and Market Heat Rate movements for our portfolio of assets have been volatile over time and are influenced by the absolute price of natural gas and the regional characteristics of each power market. We estimate that at

April 13, 2012, an increase of 500 Btu/KWh in the Market Heat Rate would result in an increase in collateral required by approximately $46 million. If Market Heat Rates were to fall at a similar rate, we estimate that our collateral required would decrease by $44 million. These amounts are not necessarily indicative of the actual amounts that could be required, which may be higher or lower than the amounts estimated above, and also exclude any correlation between the changes in natural gas prices and Market Heat Rates that may occur concurrently. These sensitivities will change as new contracts or hedging activities are executed.

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


•	continued compliance with the covenants under our existing financing obligations, including our First Lien Notes, Corporate Revolving Facility, First Lien Term Loans, CCFC Notes and other debt obligations;


•	stabilizing and 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 March 31, 2012 and December 31, 2011 (in millions):



	March 31, 2012		December 31, 2011
Corporate Revolving Facility	$	351	$	440
CDHI⁽¹⁾	226		193
Various project financing facilities	130		130
Total	$	707	$	763

___________


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

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, miscellaneous project finance letter of credit facilities and interest rate and commodity derivative contracts. 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 or results of operations. The table below sets forth our unfunded exposure for these financial institutions by country of domicile at March 31, 2012 and December 31, 2011 (in millions).



Country of Domicile	March 31, 2012		December 31, 2011
France	$	106	$	96
Spain	64		75
Germany	56		66
Italy	42		50
Total unfunded exposure	$	268	$	287

Capital Management and Significant Financing Transactions

In connection with our goals of enhancing 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 the three months ended March 31, 2012, as further described below.

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 8,524,576 shares of our outstanding common stock have been repurchased under this program for approximately $124 million at an average price of $14.60 per share. The shares repurchased as of the date of this Report were purchased in open market transactions.

Riverside Energy Center Purchase Option

As disclosed in Note 2 to the Consolidated Condensed Financial Statements, Riverside Energy Center has a PPA that provides a third party a fixed price option to purchase the power plant which is exercisable in 2012. The third party has received approval from the Public Service Commission of Wisconsin to purchase the Riverside Energy Center and has publicly stated their intent to exercise their purchase option. As a result, we expect to receive approximately $392 million during the fourth quarter of 2012 in connection with the sale of Riverside Energy Center.

CDHI

On January 10, 2012, we amended our letter of credit facility related to CDHI to increase the facility from $200 million to $300 million and extend the maturity from December 11, 2012 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 — The Russell City Energy Center is under construction and continues to move forward with expected COD in 2013. 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. The project's prevention of significant deterioration permit is currently the subject of an ongoing appeal at the U.S. Court of Appeals for the Ninth Circuit brought by Chabot-Las Positas Community College District against the EPA. Upon completion, the Russell City Energy Center is contracted to deliver its full output to PG&E under a ten-year PPA.

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 shut down 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 in the third quarter of 2013.

Texas:

Channel and Deer Park Expansions — We are actively permitting 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 and the EPA to expand the Deer Park and Channel Energy Centers by approximately 260 MW each. We continue to move forward with development and permitting activities and expect COD in summer 2014 for these expansions.

North:

Garrison Energy Center — We are actively permitting 618 MW of new combined-cycle capacity at a development site secured by a lease option with the City of Dover. PJM has completed a feasibility study and a system impact study and is currently conducting a facility study for the first phase (309 MW). The feasibility study has been completed and a system impact study is ongoing for the second phase (309 MW). Environmental permitting, site development planning and development engineering are underway and the first phase's capacity will be bid into PJM's 2015/2016 base residual auction.

All Segments:

Turbine Upgrades — We continue to move forward with our turbine upgrade program. Through March 31, 2012, we have completed the upgrade of ten Siemens and five GE turbines and have agreed to upgrade approximately six additional Siemens and GE turbines (and may upgrade additional turbines in the future). Our turbine upgrade program is expected to increase our generation capacity in total by approximately 275 MW. This upgrade program began in the fourth quarter of 2009 and is scheduled through 2014. The upgraded turbines have been operating with more efficient Heat Rates consistent with expectations.

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 or approved in 2012 is as follows:


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

NOLs

We have significant NOLs that will provide future tax deductions when we generate sufficient taxable income during the applicable carryover periods. At December 31, 2011, our consolidated federal NOLs totaled approximately $7.9 billion. See Note 7 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 three months ended March 31, 2012 and 2011 (in millions):



	2012			2011
Beginning cash and cash equivalents	$	1,252		$	1,327
Net cash provided by (used in):
Operating activities	71			149
Investing activities	(314		)	(138		)
Financing activities	61			(58		)
Net decrease in cash and cash equivalents	(182		)	(47		)
Ending cash and cash equivalents	$	1,070		$	1,280

Net Cash Provided By Operating Activities

Cash provided by operating activities for the three months ended March 31, 2012, was $71 million compared to $149 million for the three months ended March 31, 2011. The decrease in cash provided by operating activities was primarily due to:


•	Interest paid — Cash paid for interest increased by $70 million to $226 million for the three months ended March 31, 2012, as compared to $156 million for the three months ended March 31, 2011. The increase was primarily due to timing of interest payments on the new bonds and term loans as compared to the previously outstanding First Lien Credit Facility and project debt.


•	Working capital employed — Working capital employed increased by approximately $54 million for the three months ended March 31, 2012 compared to the three months ended March 31, 2011 after adjusting for debt related balances and non-hedging interest rate swaps which did not impact cash provided by operating activities.

Our decrease in cash provided by operating activities was partially offset by the following:


•	Income from operations — Income from operations, adjusted for non-cash items increased by $43 million for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011. Non-cash items consist primarily of depreciation and amortization, income from unconsolidated investments and unrealized gains and losses in mark-to-market activity.

Net Cash Used In Investing Activities

Cash flows used in investing activities for the three months ended March 31, 2012 were $314 million compared to $138 million for the three months ended March 31, 2011. The difference was primarily due to:


•	Capital expenditures — Capital expenditures increased by approximately $37 million primarily resulting from construction activity at the Russell City Energy Center and Los Esteros Critical Energy Facility combined with our turbine upgrade program.

•

Settlement of non-hedging interest rate swaps — During the three months ended March 31, 2012, we terminated our legacy interest rate swaps formerly hedging our First Lien Credit Facility resulting in payments of approximately $151 million, an increase of approximately $108 million compared to payments on interest rate swap derivative instruments associated with swaps that formerly hedged the variable rate debt which was converted to fixed rate debt of approximately $43 million during the three months ended March 31, 2011.

•

Restricted cash — The net decrease in restricted cash was $23 million for three months ended March 31, 2012 compared to $52 million for the same period in 2011. The decrease in restricted cash in 2012 as compared to 2011 was primarily due to normal first quarter reductions partially offset by a $12 million increase in requirements at OMEC due to insurance proceeds related to outages in the spring of 2011.


•	Transmission credits — During the three months ended March 31, 2012, we paid $8 million for transmission credits related to construction of our Russell City Energy Center. In the three months ended March 31, 2011, we paid $3 million for transmission credits related to construction of our Russell City Energy Center.

Net Cash Provided By (Used In) Financing Activities

Cash flows provided by financing activities were $61 million for the three months ended March 31, 2012 compared to cash flows used in financing activities of $58 million for the three months ended March 31, 2011. The increase in cash flows provided by financing activities was primarily due to:


•	Proceeds from project debt — During the three months ended March 31, 2012, we received proceeds of approximately $114 million from project debt compared to nil for the three months ended March 31, 2011. The proceeds received were related to our Russell City Project Debt and Los Esteros Project Debt.


•	Lower repayments of project debt — During the three months ended March 31, 2012, we made repayments on project debt of approximately $38 million compared to repayments of approximately $64 million during the three months ended March 31, 2011.


•	Lower finance costs — During the three months ended March 31, 2012, we incurred finance costs of approximately $5 million compared to approximately $34 million for the three months ended March 31, 2011.

The increase was partially offset by:

•

First Lien Notes — During the three months ended March 31, 2012, we made repayments on the First Lien Credit Facility of nil. During the three months ended March 31, 2011, we received proceeds of approximately $1.2 billion from the issuance of the 2023 First Lien 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 $16 million.


•	First Lien Term Loans — During the three months ended March 31, 2011, we received proceeds of approximately $1.3 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 $17 million. We had no similar activity during the three months ended March 31, 2012.


•	Decreased contributions from noncontrolling interest holder — During the three months ended March 31, 2012, we received contributions from a noncontrolling interest holder of nil compared to approximately $8 million during the three months ended March 31, 2011.


•	Stock repurchases — During the three months ended March 31, 2012, we made payments under the share repurchase program of approximately $6 million compared to nil during the three months ended March 31, 2011.

Off Balance Sheet Arrangements

There have been no material changes to any off balance sheet arrangements from those disclosed in “Management 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 OMEC.

On March 2, 2012, we closed on the purchase of two of the 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 will be 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; however, we remain susceptible to significant price movements for 2012 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 three months ended March 31, 2012 and approximately $142 million reflected the realization of losses recorded in prior periods.

At March 31, 2012, the maximum length of time over which we were hedging using interest rate derivative instruments designated as cash flow hedges was 12 years. 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 nine months as the related hedged transactions affect earnings. We estimate that pre-tax net gains of $4 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, principally for power and natural gas; our credit standing and that of our counterparties for energy commodity derivatives; and prevailing interest rates for our interest rate swaps. Since prices for power and natural gas and interest rates are volatile, there may be material changes in the fair value of our derivatives over time, driven both by price volatility and the changes in volume of open derivative transactions. Our derivative assets have increased to approximately $1.6 billion at March 31, 2012, compared to $1.2 billion at December 31, 2011, and our derivative liabilities have increased to approximately $1.6 billion at March 31, 2012, compared to $1.4 billion at December 31, 2011. At March 31, 2012, the fair value of our level 3 derivative assets and liabilities represent only a small portion of our total assets and liabilities (less than 1%). See Note 4 of the Notes to Consolidated Condensed Financial Statements for further information related to our level 3 derivative assets and liabilities.

The change in fair value of our outstanding commodity and interest rate derivative instruments from January 1, 2012, through March 31, 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⁾	154			(64		)	90
Fair value attributable to new contracts	—			81			81
Changes in fair value attributable to price movements	(2		)	124			122
Changes in fair value attributable to nonperformance risk	(3		)	—			(3		)
Fair value of contracts outstanding at March 31, 2012⁽³⁾	$	(161	)	$	192		$	31

__________

(1)

Interest rate settlements consist of recognized losses of $146 million related to interest rate swaps that were terminated during the three months ended March 31, 2012, $4 million related to recognition of losses from settlements of designated cash flow hedges and $4 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 $80 million (represents a portion of operating revenues and fuel and purchased energy expense as reported on our Consolidated Condensed Statements of Operations) and $16 million related to recognition of losses from other changes in derivative assets and liabilities not reflected in OCI or earnings, partially offset by cash flow hedges, previously reflected in AOCI.


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

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



	Three Months Ended March 31,
	2012			2011
Realized gain (loss)
Interest rate swaps	$	(157	)	$	(46	)
Commodity derivative instruments	118			10
Total realized gain (loss)	$	(39	)	$	(36	)

Unrealized gain (loss)⁽¹⁾
Interest rate swaps	$	146		$	(62	)
Commodity derivative instruments	78			(65		)
Total unrealized gain (loss)	$	224		$	(127	)
Total mark-to-market activity, net	$	185		$	(163	)

____________


(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 March 31,
	2012			2011
Realized and unrealized gain (loss)
Power contracts included in operating revenues	$	92		$	(57	)
Natural gas contracts included in fuel and purchased energy expense	104			2
Interest rate swaps included in interest expense	3			1
Loss on interest rate derivatives	(14		)	(109		)
Total mark-to-market activity, net	$	185		$	(163	)

Our change in AOCI from an accumulated loss of $178 million at December 31, 2011, to an accumulated loss of $173 million at March 31, 2012, was primarily driven by a foreign currency translation gain of $3 million related to our Canadian subsidiaries and $2 million in income tax benefits recorded in the three months ended March 31, 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 March 31, 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	$	122		$	22	$	—	$	—	$	144
Prices provided by other external sources	(3		)	35		—		—		32
Prices based on models and other valuation methods	5			11		—		—		16
Total fair value	$	124		$	68	$	—	$	—	$	192

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 months ended March 31, 2012 and 2011 (in millions):



	2012		2011
Three months ended March 31:
High	$	55	$	39
Low	$	34	$	31
Average	$	45	$	35
As of March 31	$	49	$	37

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

Liquidity Risk — Liquidity risk arises from the general funding requirements needed to manage our activities and assets and liabilities. Increasing natural gas prices or Market Heat Rates can cause increased collateral requirements. Our liquidity management framework is intended to maximize liquidity access and minimize funding costs during times of rising prices. See further discussion regarding our uses of collateral as they relate to our commodity procurement and risk management activities in Note 6 of the Notes to Consolidated Condensed Financial Statements.

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


•	credit approvals;


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


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


•	margin, collateral, or prepayment arrangements; and


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

We have concentrations of credit risk with a few of our 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 and diversify our credit risk, and currently our counterparties are performing and financially settling timely according to their respective agreements. We monitor and manage our total comprehensive credit risk associated with all of our contracts and PPAs irrespective of whether they are accounted for as an executory contract, a normal purchase normal sale or whether they are marked-to-market and included in our derivative assets and liabilities on our Consolidated Condensed Balance Sheets. Our counterparty credit quality associated with the net fair value of outstanding derivative commodity instruments is included in our derivative assets and liabilities at March 31, 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 March 31, 2012)	2012			2013-2014		2015-2016		After 2016		Total
Investment grade	$	139		$	66	$	—	$	—	$	205
Non-investment grade	(15		)	—		—		—		(15		)
No external ratings	—			2		—		—		2
Total fair value	$	124		$	68	$	—	$	—	$	192

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 $(16) million at March 31, 2012.

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 first 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.

PART II — OTHER INFORMATION


Item 1.	Legal Proceedings

See Note 10 of the Notes to Consolidated Condensed Financial Statements for a description of our legal proceedings.


Item 1A.	Risk Factors

There were no material changes to the description of the risk factors associated with our business previously disclosed in Part I, Item 1A “Risk Factors” of our 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)
January	101,035	$	14.84	99,345	$	180
February	310,516	$	14.57	288,158	$	176
March	1,481	$	17.14	—	$	176
Total	413,032	$	14.65	387,503	$	176

___________


(1)	Upon vesting of restricted stock awarded by us to employees, we withhold shares to cover employees' tax withholding obligations, other than for employees who have chosen to satisfy their tax withholding obligations in cash. During the first quarter of 2012, we withheld a total of 25,529 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 8,524,576 shares of our outstanding common stock have been repurchased under this program for approximately $124 million at an average price of $14.60 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.


Item 6.	Exhibits

EXHIBIT INDEX



Exhibit Number		Description
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. **

_______________


*	Filed herewith.


‡	Furnished herewith.


**	XBRL (eXtensible Business Reporting Language) information is furnished, not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise is not subject to liability under those sections.

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

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

Date: April 26, 2012

EXHIBIT INDEX



Exhibit Number		Description
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. **

_______________


*	Filed herewith.


‡	Furnished herewith.


**	XBRL (eXtensible Business Reporting Language) information is furnished, not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise is not subject to liability under those sections.