UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_______________

Form 10-Q

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

For the quarterly period ended June 30, 2011
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) 830-8775

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. [X] Yes[   ] No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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). [X] Yes[   ] 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 definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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               [X] No

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 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.

[X] Yes               [   ] No

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: 459,500,298 shares of common stock, par value $.001 per share, outstanding on July 26, 2011.

CALPINE CORPORATION AND SUBSIDIARIES

REPORT ON FORM 10-Q

For the Quarter Ended June 30, 2011

INDEX
	Page
Definitions	iii
Forward-Looking Statements	ix
Where You Can Find Other Information	ix
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Condensed Statements of Operations for the Three and Six Months Ended June 30, 2011 and 2010	1
Consolidated Condensed Balance Sheets at June 30, 2011, and December 31, 2010	2
Consolidated Condensed Statements of Cash Flows for the Six Months Ended June 30, 2011 and 2010	3
Notes to Consolidated Condensed Financial Statements	4
Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Introduction and Overview	32
Results of Operations	36
Commodity Margin and Adjusted EBITDA	42
Liquidity and Capital Resources	50
Risk Management and Commodity Accounting	57
New Accounting Standards and Disclosure Requirements	60
Item 3.  Quantitative and Qualitative Disclosures About Market Risk	61
Item 4.  Controls and Procedures	61
PART II — OTHER INFORMATION
Item 1.  Legal Proceedings	62
Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds	62
Item 5.  Other Information	62
Item 6.  Exhibits	63
Signatures	64

ii

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
2010 Form 10-K	Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2010, filed with the SEC on February 17, 2011
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, (j) Conectiv acquisition-related costs, (k) Adjusted EBITDA from our discontinued operations, (l) reorganization items and (m) 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	Represents 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
BLM	Bureau of Land Management of the U.S. Department of the Interior
Blue Spruce	Blue Spruce Energy Center, LLC, formerly an indirect, wholly owned subsidiary that owned Blue Spruce Energy Center, a 310 MW natural gas-fired peaker power plant located in Aurora, Colorado, which was sold on December 6, 2010
Broad River	Broad River Energy Center, an 847 MW natural gas-fired peaker power plant located in Gaffney, South Carolina
Btu	British thermal unit(s), a measure of heat content

iii

ABBREVIATION	DEFINITION
CAA	Federal Clean Air Act, U.S. Code Title 42, Chapter 85
CAISO	California Independent System Operator
CalGen	Calpine Generating Company, LLC, an indirect, wholly owned subsidiary
CalGen Third Lien Debt	Together, the $680 million Third Priority Secured Floating Rate Notes Due 2011, issued by CalGen and CalGen Finance Corp.; and the $150 million 11.50% Third Priority Secured Notes Due 2011, issued by CalGen and CalGen Finance Corp., in each case repaid on March 29, 2007
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
CARB	California Air Resources Board
CCFC	Calpine Construction Finance Company, L.P., an indirect, wholly owned subsidiary
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 Corp.
CEHC	Conectiv Energy Holding Company, LLC, a wholly owned subsidiary of Conectiv
Chapter 11	Chapter 11 of the U.S. Bankruptcy Code
CO2	Carbon dioxide
COD	Commercial operations date
Cogeneration	Using a portion or all of the steam generated in the power generating process to supply a customer with steam for use in the customer’s operations
Commodity Collateral Revolver	Commodity Collateral Revolving Credit Agreement, dated as of July 8, 2008, among Calpine Corporation as borrower, Goldman Sachs Credit Partners L.P., as payment agent, sole lead arranger and sole bookrunner, and the lenders from time to time party thereto, which was repaid on July 8, 2010
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
Conectiv	Conectiv, LLC, a wholly owned subsidiary of PHI

iv

ABBREVIATION	DEFINITION
Conectiv Acquisition	The acquisition of all of the membership interests in CEHC pursuant to the Conectiv Purchase Agreement on July 1, 2010, whereby we acquired all of the power generation assets of Conectiv from PHI, which included 18 operating power plants and York Energy Center that was under construction and achieved COD on March 2, 2011, with approximately 4,490 MW of capacity (including completion of scheduled upgrades)
Conectiv Purchase Agreement	Purchase Agreement by and among PHI, Conectiv, CEHC and NDH dated as of April 20, 2010
CPUC	California Public Utilities Commission
Director Plan	The Amended and Restated Calpine Corporation 2008 Director Incentive Plan
Dodd-Frank Act	The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
EBITDA	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
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
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)
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

v

ABBREVIATION	DEFINITION
Heat Rate(s)	A measure of the amount of fuel required to produce a unit of power
ISRA	Industrial Site Recovery Act
kWh	Kilowatt-hour(s), a measure of power produced
LIBOR	London Inter-Bank Offered Rate
Mankato	Mankato Energy Center, a 375 MW natural gas-fired, combined-cycle power plant located in Mankato, Minnesota
Market Capitalization	As of any date, Calpine Corporation’s then market capitalization calculated using the rolling 30-day weighted average trading price of Calpine Corporation’s common stock, as defined in and calculated in accordance with the Calpine Corporation amended and restated certificate of incorporation
Market Heat Rate(s)	The regional power price divided by the corresponding regional natural gas price
MMBtu	Million Btu
MRTU	CAISO’s Market Redesign and Technology Upgrade
MW	Megawatt(s), a measure of plant capacity
MWh	Megawatt hour(s), a measure of power produced
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 bookrunners 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
NJDEP	New Jersey Department of Environmental Protection
New Term Loan	The $360 million first lien senior secured term loan, dated June 17, 2011 among Calpine Corporation as borrower and the lenders party hereto, and Morgan Stanley Senior Funding, Inc., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent
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 power plant located in San Diego county, California
OTC	Over-the-Counter
PG&E	Pacific Gas & Electric Company
PHI	Pepco Holdings, Inc.

vi

ABBREVIATION	DEFINITION
PJM	Pennsylvania – New Jersey – Maryland Interconnection
Plan of Reorganization	Sixth Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the U.S. 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
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 U.S. Public Utility Holding Company Act of 2005 and grants certain other benefits to the QF
REC	Renewable Energy Credit
RGGI	Regional Greenhouse Gas Initiative
Rocky Mountain	Rocky Mountain Energy Center, LLC, formerly an indirect, wholly owned subsidiary that owned Rocky Mountain Energy Center, a 621 MW combined-cycle, natural gas-fired power plant located in Keenesburg, Colorado, which was sold on December 6, 2010
RPS	Renewable Portfolio Standards
Russell City	Russell City Energy Center, a 619 MW combined-cycle, natural gas-fired power plant under construction and located in Hayward, California, of which, Calpine owns 75%
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
SO2	Sulfur dioxide
South Point	South Point Energy Center, a 530 MW natural gas-fired combined-cycle power plant located in Mohave Valley, Arizona
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
Term Loan	The $1.3 billion first lien senior secured term loan, dated March 9, 2011 among Calpine Corporation as borrower and the lenders party hereto, and Morgan Stanley Senior Funding, Inc., as administrative agent, Goldman Sachs Credit Partners L.P., as collateral agent, Citibank, N.A., Credit Suisse Securities (USA) LLC and Deutsche Bank Securities Inc., as co-documentation agents and Goldman Sachs Bank USA as syndication agent

vii

ABBREVIATION	DEFINITION
U.S. Debtors	Calpine Corporation and each of its subsidiaries and affiliates that filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court, which matters are being jointly administered in the U.S. Bankruptcy Court under the caption In re Calpine Corporation, et al., Case No. 05-60200 (BRL)
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, cogeneration power plant 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, included in the Conectiv Acquisition, which achieved COD on March 2, 2011

viii

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 U.S. Securities Act of 1933, as amended, and Section 21E of the Exchange Act. Forward-looking statements may appear throughout this report, including without limitation, “Management’s Discussion and Analysis.” 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, 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 climate change, GHG emissions and derivative transactions;

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

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

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

• Risks related to our geothermal resources, including the adequacy of our steam reserves, unusual or unexpected steam field well and pipeline maintenance requirements, variables associated with the injection of 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 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, or acts of terrorism 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 our 2010 Form 10-K.

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

Where You Can Find Other Information

Our website is www.calpine.com. Information contained on our website is not part of this Report. Information that we furnish or file with the SEC, including our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to or exhibits included in these reports are available for download, free of charge, on our website soon after such reports are filed with or furnished to the SEC. Our SEC filings, including exhibits filed therewith, are also available at the SEC’s website at www.sec.gov. You may obtain and copy any document we furnish or file with the SEC at the SEC’s public reference room at 100 F Street, NE, Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the SEC’s public reference facilities by calling the SEC at 1-800-SEC-0330. You may request copies of these documents, upon payment of a duplicating fee, by writing to the SEC at its principal office at 100 F Street, NE, Room 1580, Washington, D.C. 20549.

ix

PART I –– FINANCIAL INFORMATION

Item 1. Financial Statements

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(in millions, except share and per share amounts)
Operating revenues	$	1,633		$	1,430		$	3,132		$	2,944
Operating expenses:
Fuel and purchased energy expense		1,000			904			2,069			1,873
Plant operating expense		261			213			499			431
Depreciation and amortization expense		131			135			262			271
Sales, general and other administrative expense		34			50			66			72
Other operating expenses		22			26			42			52
Total operating expenses		1,448			1,328			2,938			2,699
(Income) loss from unconsolidated investments in power plants		2			(6	)		(7	)		(13	)
Income from operations		183			108			201			258
Interest expense		192			224			383			405
(Gain) loss on interest rate derivatives, net		37			(8	)		146			3
Interest (income)		(2	)		(4	)		(5	)		(6	)
Debt extinguishment costs		5			7			98			7
Other (income) expense, net		3			1			10			6
Loss before income taxes and discontinued operations		(52	)		(112	)		(431	)		(157	)
Income tax expense (benefit)		18			6			(65	)		17
Loss before discontinued operations		(70	)		(118	)		(366	)		(174	)
Discontinued operations, net of tax expense		—			4			—			12
Net loss		(70	)		(114	)		(366	)		(162	)
Net income attributable to the noncontrolling interest		—			(1	)		(1	)		—
Net loss attributable to Calpine	$	(70	)	$	(115	)	$	(367	)	$	(162	)
Basic and diluted loss per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands)		486,411			486,057			486,334			485,989
Loss before discontinued operations attributable to Calpine	$	(0.14	)	$	(0.25	)	$	(0.75	)	$	(0.35	)
Discontinued operations, net of tax expense attributable to Calpine		—			0.01			—			0.02
Net loss per common share attributable to Calpine – basic and diluted	$	(0.14	)	$	(0.24	)	$	(0.75	)	$	(0.33	)

The accompanying notes are an integral part of these

Consolidated Condensed Financial Statements

1

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited)

	June 30, 2011			December 31, 2010
	(in millions, except share and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents ($301 and $345 attributable to VIEs)	$	1,147		$	1,327
Accounts receivable, net of allowance of $4 and $2		738			669
Margin deposits and other prepaid expense		170			221
Restricted cash, current ($117 and $177 attributable to VIEs)		175			195
Derivative assets, current		569			725
Inventory and other current assets		285			292
Total current assets		3,084			3,429
Property, plant and equipment, net ($3,865 and $6,602 attributable to VIEs)		13,033			12,978
Restricted cash, net of current portion ($40 and $52 attributable to VIEs)		42			53
Investments		84			80
Long-term derivative assets		110			170
Other assets		545			546
Total assets	$	16,898		$	17,256
LIABILITIES & STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	602		$	514
Accrued interest payable		203			132
Debt, current portion ($63 and $132 attributable to VIEs)		126			152
Derivative liabilities, current		643			718
Other current liabilities		298			273
Total current liabilities		1,872			1,789
Debt, net of current portion ($2,345 and $4,069 attributable to VIEs)		10,190			10,104
Deferred income taxes, net of current		1			77
Long-term derivative liabilities		221			370
Other long-term liabilities		225			247
Total liabilities		12,509			12,587
Commitments and contingencies (see Note 12)
Stockholders’ equity:
Preferred stock, $.001 par value per share; 100,000,000 shares authorized; none issued and outstanding		—			—
Common stock, $.001 par value per share; 1,400,000,000 shares authorized; 446,380,252 and 444,883,356 shares issued, respectively, and 445,801,327 and 444,435,198 shares outstanding, respectively		1			1
Treasury stock, at cost, 578,925 and 448,158 shares, respectively		(7	)		(5	)
Additional paid-in capital		12,293			12,281
Accumulated deficit		(7,876	)		(7,509	)
Accumulated other comprehensive loss		(83	)		(125	)
Total Calpine stockholders’ equity		4,328			4,643
Noncontrolling interest		61			26
Total stockholders’ equity		4,389			4,669
Total liabilities and stockholders’ equity	$	16,898		$	17,256

The accompanying notes are an integral part of these

Consolidated Condensed Financial Statements.

2

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
	2011			2010
	(in millions)
Cash flows from operating activities:
Net Loss	$	(366	)	$	(162	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization expense(1)		279			298
Debt extinguishment costs		85			7
Deferred income taxes		(90	)		(4	)
Loss on disposal of assets		9			9
Unrealized mark-to-market activity, net		77			(62	)
Income from unconsolidated investments in power plants		(7	)		(13	)
Return on unconsolidated investments in power plants		6			2
Stock-based compensation expense		12			12
Other		5			(1	)
Change in operating assets and liabilities:
Accounts receivable		(68	)		68
Derivative instruments, net		(29	)		(81	)
Other assets		58			171
Accounts payable and accrued expenses		166			(91	)
Liabilities related to non-hedging interest rate swaps		103			14
Other liabilities		(1	)		3
Net cash provided by operating activities		239			170
Cash flows from investing activities:
Purchases of property, plant and equipment		(341	)		(97	)
Cash acquired due to consolidation of OMEC		—			8
Purchases of deferred transmission credits		(8	)		—
Decrease in restricted cash		30			224
Settlement of non-hedging interest rate swaps		(103	)		(14	)
Other		1			3
Net cash provided by (used in) investing activities		(421	)		124
Cash flows from financing activities:
Repayments of project financing, notes payable and other		(419	)		(277	)
Borrowings from project financing, notes payable and other		69			—
Repayments on NDH Project Debt		(1,283	)		—
Borrowings under Term Loan and New Term Loan		1,657			—
Issuance of First Lien Notes		1,200			400
Repayments on First Lien Credit Facility		(1,187	)		(430	)
Capital contributions from noncontrolling interest holder		34			—
Financing costs		(67	)		(15	)
Refund of financing costs		—			10
Other		(2	)		—
Net cash provided by (used in) financing activities		2			(312	)
Net decrease in cash and cash equivalents		(180	)		(18	)
Cash and cash equivalents, beginning of period		1,327			989
Cash and cash equivalents, end of period	$	1,147		$	971
Cash paid during the period for:
Interest, net of amounts capitalized	$	292		$	362
Income taxes	$	12		$	9
Supplemental disclosure of non-cash investing and financing activities:
Change in capital expenditures included in accounts payable	$	21		$	(7	)

_________

(1) Includes depreciation and amortization that is also recorded in fuel and purchased energy expense, interest expense and discontinued operations on our Consolidated Condensed Statements of Operations.

The accompanying notes are an integral part of these

Consolidated Condensed Financial Statements.

3

CALPINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

June 30, 2011

(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, regulatory capacity, renewable energy credits and ancillary services to our customers, including industrial companies, retail power providers, utilities, municipalities, independent electric system operators, 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, 2010, included in our 2010 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.

Reclassifications — Certain reclassifications have been made to our Consolidated Condensed Statements of Operations and Cash Flows for the three and six months ended June 30, 2010 to conform to the current period presentation. Our reclassifications are summarized as follows:

• We have reclassified amounts attributable to interest rate swaps formerly hedging our First Lien Credit Facility term loans previously recorded in interest expense to (gain) loss on interest rate derivatives, net of approximately $(8) million and $3 million for the three and six months ended June 30, 2010, respectively. See Note 7 for further information about our interest rate swaps formerly hedging our First Lien Credit Facility.

• We have reclassified depreciation expense on corporate assets previously recorded in sales, general and other administrative expense to depreciation and amortization expense of approximately $3 million and $6 million for the three and six months ended June 30, 2010, respectively.

• We have reclassified cash payments on our interest rate swaps formerly hedging our First Lien Credit Facility term loans previously included in net cash provided by operating activities of approximately $14 million to settlement of non-hedging interest rate swaps included in net cash provided by (used in) investing activities for the six months ended June 30, 2010.

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 June 30, 2011, and December 31, 2010, we had cash and cash equivalents of $301 million and $269 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

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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 Consolidated Condensed Statements of Cash Flows. The table below represents the components of our restricted cash at June 30, 2011, and December 31, 2010 (in millions):

	June 30, 2011						December 31, 2010
	Current		Non-Current		Total		Current		Non-Current		Total
Debt service	$	48	$	28	$	76	$	44	$	25	$	69
Rent reserve		5		—		5		22		5		27
Construction/major maintenance		56		3		59		35		14		49
Security/project/insurance		51		7		58		75		7		82
Other		15		4		19		19		2		21
Total	$	175	$	42	$	217	$	195	$	53	$	248

Inventory — At June 30, 2011 and December 31, 2010, we had inventory of $246 million and $262 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 under the weighted average cost method or market value. Spare parts inventory is valued at the weighted average cost and are expensed to plant operating expense or capitalized to property, plant and equipment as the parts are utilized and consumed.

Property, Plant and Equipment — At June 30, 2011 and December 31, 2010, the components of property, plant and equipment were stated at cost less accumulated depreciation as follows (in millions):

	June 30, 2011		December 31, 2010
Buildings, machinery and equipment	$	14,966	$	14,578
Geothermal properties		1,143		1,102
Other		265		273
		16,374		15,953
Less: Accumulated depreciation		3,931		3,690
		12,443		12,263
Land		94		93
Construction in progress		496		622
Property, plant and equipment, net	$	13,033	$	12,978

Capitalized Interest— The total amount of interest capitalized was $4 million and $1 million for the three months ended June 30, 2011 and 2010, respectively, and $11 million and $2 million for the six months ended June 30, 2011 and 2010, respectively.

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New Accounting Standards and Disclosure Requirements

Fair Value Measurement — In May 2011, the Financial Accounting Standards Board 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 Financial Accounting Standards Board 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 is not expected to impact any of our fair value measurements but will 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 do not expect that the adoption of this standard will have a material impact on our results of operations, cash flows or financial condition.

Comprehensive Income — In June 2011, the Financial Accounting Standards Board issued Accounting Standards Update 2011-05, “Comprehensive Income” to amend requirements relating to the presentation of comprehensive income. The update eliminates the option to present components of other comprehensive income as part of the statement of changes in stockholders’ equity and provides an entity with the option to present comprehensive income in a single continuous financial statement or in two separate but consecutive statements. The new requirements relating to the presentation of comprehensive income are retrospective and effective for interim and annual periods beginning after December 15, 2011 with early adoption permitted. We have not elected to early adopt the requirements related to the update at June 30, 2011. Since the update only requires a change in presentation, 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.

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2.  Acquisitions, Divestitures and Discontinued Operations

Conectiv Acquisition

On July 1, 2010, we, through our indirect, wholly owned subsidiary NDH, completed the Conectiv Acquisition. The assets acquired include 18 operating power plants and the York Energy Center that was under construction and achieved COD on March 2, 2011, totaling approximately 4,490 MW of capacity (including completion of the scheduled upgrades). We did not acquire Conectiv’s trading book, load serving auction obligations or collateral requirements. Additionally, we did not assume any of Conectiv’s off-site environmental liabilities, environmental remediation liabilities in excess of $10 million related to assets located in New Jersey that are subject to ISRA, or pre-close accumulated pension and retirement welfare liabilities; however, we did assume pension liabilities on future services and compensation increases for past services for approximately 129 union employees who joined Calpine as a result of the Conectiv Acquisition. The net proceeds of $1.3 billion received from the NDH Project Debt were used, together with available operating cash, to pay the Conectiv Acquisition purchase price of approximately $1.64 billion and also fund a cash contribution from Calpine Corporation to NDH of $110 million to fund completion of the York Energy Center.

The Conectiv Acquisition provided us with a significant presence in the Mid-Atlantic market, one of the most robust competitive power markets in the U.S., and positioned us with three scale markets instead of two (California and Texas) giving us greater geographic diversity. We accounted for the Conectiv Acquisition under the acquisition method of accounting in accordance with U.S. GAAP.

During the second quarter of 2011, we finalized the valuations we assigned to the net assets acquired in the Conectiv Acquisition which is summarized in the following table (in millions). We did not record any material valuation adjustments during the three and six months ended June 30, 2011, and we did not recognize any goodwill as a result of this acquisition.

Consideration	$	1,640
Final values of identifiable assets acquired and liabilities assumed:
Assets:
Current assets	$	78
Property, plant and equipment, net		1,574
Other long-term assets		85
Total assets acquired		1,737
Liabilities:
Current liabilities		46
Long-term liabilities		51
Total liabilities assumed		97
Net assets acquired	$	1,640

Sale of Blue Spruce and Rocky Mountain

On December 6, 2010, we, through our indirect, wholly owned subsidiaries Riverside Energy Center, LLC and Calpine Development Holdings, Inc., completed the sale of 100% of our ownership interests in Blue Spruce and Rocky Mountain for approximately $739 million, and we recorded a pre-tax gain of approximately $209 million during the fourth quarter of 2010. The results of operations for Blue Spruce and Rocky Mountain are reported as discontinued operations on our Consolidated Condensed Statement of Operations for the three and six months ended June 30, 2010.

The table below presents the components of our discontinued operations for the periods presented (in millions):

	Three Months Ended		Six Months Ended
	June 30, 2010		June 30, 2010
Operating revenues	$	25	$	50
Income from discontinued operations before taxes	$	12	$	20
Less: Income tax expense		8		8
Discontinued operations, net of tax	$	4	$	12

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3.  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 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 5 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 with an aggregate capacity of 1,211 MW exercisable in the years 2013 and 2019. 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.

There were no changes to our determination of whether we are the primary beneficiary of our VIEs during the first half of 2011.

VIE Disclosures

U.S. GAAP also requires separate disclosure on the face of our Consolidated Condensed Balance Sheets of the significant assets of a consolidated VIE that can only be used 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 met the separate disclosure criteria, we determined 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 there are agreements that prohibit the VIE from guaranteeing the debt of Calpine Corporation or its other subsidiaries. In determining which liabilities of our VIEs met the separate disclosure criteria, we reviewed all of our VIEs and determined this separate disclosure requirement was met where our VIEs had project financing that prohibits the VIE from providing guarantees on the debt of others 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 approximately 11,064 MW and 13,553 MW at June 30, 2011 and December 31, 2010, respectively. For these VIEs, we may provide other operational and administrative support through various affiliate contractual arrangements between 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 for both the three months ended June 30, 2011 and 2010, and $52 million and $1 million during the six months ended June 30, 2011 and 2010, respectively.

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Unconsolidated VIEs and Investments

We have a 50% partnership interest in Greenfield LP and in Whitby. Greenfield LP and Whitby are also VIEs; however, we do not have the power to direct the most significant activities of these entities and therefore do not consolidate them. We account for these entities under the equity method of accounting and include our net equity interest in investments on our Consolidated Condensed Balance Sheets in accordance with U.S. GAAP. Our ownership interest in the net income for Greenfield LP and Whitby for the three and six months ended June 30, 2011 and 2010, are recorded in (income) loss from unconsolidated investments in power plants. At June 30, 2011 and December 31, 2010, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):

	Ownership Interest as of June 30, 2011		June 30, 2011(1)		December 31, 2010
Greenfield LP		50%	$	79	$	77
Whitby		50%		5		3
Total investments			$	84	$	80

_________

(1) Our risk of loss related to our unconsolidated VIEs is limited to our investment balance. While we also could be responsible for our pro rata portion of debt, holders of the debt of our unconsolidated investments do not have recourse to Calpine Corporation and its other subsidiaries. The debt of our unconsolidated investments is not reflected on our Consolidated Condensed Balance Sheets. At June 30, 2011, and December 31, 2010, equity method investee debt was approximately $514 million and $494 million, respectively, and based on our pro rata share of each of the investments, our share of such debt would be approximately $257 million and $247 million at June 30, 2011 and December 31, 2010, respectively.

The following table sets forth details of our (income) loss from unconsolidated investments in power plants for the periods indicated (in millions):

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Greenfield LP	$	4		$	(3	)	$	(1	)	$	(7	)
Whitby		(2	)		(3	)		(6	)		(6	)
Total	$	2		$	(6	)	$	(7	)	$	(13	)

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 power plant 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 $2 million for both the three and six months ended June 30, 2011. We did not receive any distributions from Greenfield LP during the three and six months ended June 30, 2010.

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 in Ontario, Canada. We and Atlantic Packaging Ltd. each hold a 50% partnership interest in Whitby. Distributions from Whitby were $4 million for both the three and six months ended June 30, 2011, and $2 million for both the three and six months ended June 30, 2010.

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 were 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.

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

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4.  Comprehensive Loss

Comprehensive loss includes our net loss, unrealized gains and losses from derivative instruments, net of tax that qualify as cash flow hedges, our share of equity method investees’ OCI and the effects of foreign currency translation adjustments. See Note 7 for further discussion of our accounting for derivative instruments designated as cash flow hedges and the related amounts recorded in OCI. We report AOCI on our Consolidated Condensed Balance Sheets. The table below details the components of our comprehensive loss for the periods indicated (in millions):

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Net loss	$	(70	)	$	(114	)	$	(366	)	$	(162	)
Other comprehensive income (loss):
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net loss		(17	)		(71	)		14			30
Reclassification adjustment for cash flow hedges realized in net loss		(31	)		8			44			22
Foreign currency translation loss		(1	)		(2	)		—			—
Income tax (expense) benefit		18			(23	)		(16	)		(9	)
Comprehensive loss		(101	)		(202	)		(324	)		(119	)
Add: Comprehensive income attributable to the noncontrolling interest		—			(1	)		(1	)		—
Comprehensive loss attributable to Calpine	$	(101	)	$	(203	)	$	(325	)	$	(119	)

5.  Debt

Our debt at June 30, 2011 and December 31, 2010, was as follows (in millions):

	June 30, 2011		December 31, 2010
First Lien Notes(1)	$	5,891	$	4,691
Project financing, notes payable and other(2)(3)		1,568		1,922
Term Loan and New Term Loan(2)(4)		1,654		—
NDH Project Debt(4)		—		1,258
First Lien Credit Facility(1)		—		1,184
CCFC Notes		969		965
Capital lease obligations		234		236
Total debt		10,316		10,256
Less: Current maturities		126		152
Debt, net of current portion	$	10,190	$	10,104

_________

(1) On January 14, 2011, we repaid and terminated the First Lien Credit Facility with the issuance of the 2023 First Lien Notes as discussed below.

(2) On June 17, 2011, we repaid approximately $340 million of project debt with the proceeds received from $360 million in borrowings under the New Term Loan as further described below.

(3) On June 24, 2011, we closed on the approximately $845 million Russell City Project Debt to fund the construction of Russell City as further described below.

(4) On March 9, 2011, we borrowed $1.3 billion under the Term Loan and repaid and terminated the NDH Project Debt as discussed below.

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Our First Lien Notes and Termination of the First Lien Credit Facility

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

	June 30, 2011		December 31, 2010
2017 First Lien Notes	$	1,200	$	1,200
2019 First Lien Notes		400		400
2020 First Lien Notes		1,091		1,091
2021 First Lien Notes		2,000		2,000
2023 First Lien Notes(1)		1,200		—
Total First Lien Notes	$	5,891	$	4,691

_________

(1) On January 14, 2011, we issued $1.2 billion in aggregate principal amount of 7.875% senior secured notes due 2023 in a private placement. The 2023 First Lien Notes bear interest at 7.875% payable semi-annually on January 15 and July 15 of each year, beginning on July 15, 2011. The 2023 First Lien Notes will mature on January 15, 2023.

Following our emergence from Chapter 11, our First Lien Credit Facility served as our primary debt facility. Beginning in late 2009, we began to repay or exchange our First Lien Credit Facility term loans through proceeds received from the issuances of the First Lien Notes, together with operating cash. On January 14, 2011, we repaid the remaining approximately $1.2 billion from the proceeds from the issuance of the 2023 First Lien Notes, together with operating cash, thereby terminating the First Lien Credit Facility in accordance with its terms.

Our First Lien Notes are secured equally and ratably with indebtedness incurred under our Corporate Revolving Facility, Term Loan and New Term Loan (described below), subject to certain exceptions and permitted liens, on substantially all of our and certain of the guarantors’ existing and future assets. Additionally, our First Lien Notes rank equally in right of payment with all of our and the guarantors’ other existing and future senior indebtedness, and will be effectively subordinated in right of payment to all existing and future liabilities of our subsidiaries that do not guarantee our First Lien Notes. Repayment of the NDH Project Debt also eliminated the restrictions against our NDH subsidiaries being guarantors to our First Lien Notes and Corporate Revolving Facility. On March 9, 2011, we executed assumption agreements to the amended and restated guarantee and collateral agreement, to add our NDH subsidiaries as guarantors to our Corporate Revolving Facility and Term Loan. On April 26, 2011, we executed supplemental indentures for the First Lien Notes to add the NDH subsidiaries as guarantors. On June 17, 2011, we executed assumption agreements to the amended and restated guarantee and collateral agreement, to add Deer Park Holdings, LLC, Metcalf Holdings, LLC, Deer Park Energy Center LLC and Metcalf Energy Center, LLC as guarantors of our Corporate Revolving Facility, Term Loan and New Term Loan. On July 22, 2011, we executed supplemental indentures for the First Lien Notes to add Deer Park Holdings, LLC, Metcalf Holdings, LLC, Deer Park Energy Center LLC and Metcalf Energy Center, LLC as guarantors.

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.

We recorded approximately $19 million in debt extinguishment costs in the first quarter of 2011 from the write-off of unamortized deferred financing costs related to the repayment and termination of the First Lien Credit Facility, and we recorded approximately $22 million of deferred financing costs during the first quarter of 2011 related to the issuance of the 2023 First Lien Notes.

The Term Loan and New Term Loan and Repayment of the NDH Project Debt and Other Project Debt

On March 9, 2011, we entered into and borrowed $1.3 billion under the Term Loan. We used the net proceeds received, together with operating cash on hand to fully retire the approximately $1.3 billion NDH Project Debt in accordance with its repayment terms. The NDH Project Debt was originally established to partially fund the Conectiv Acquisition.

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The Term Loan provides for a senior secured term loan facility in an aggregate principal amount of $1.3 billion 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 Term Loan credit agreement), plus an applicable margin of 2.25%, or (ii) LIBOR plus 3.25% per annum subject to a LIBOR floor of 1.25%.

An aggregate amount equal to 0.25% of the aggregate principal amount of the Term Loan will be payable at the end of each quarter commencing on June 30, 2011, 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 Term Loan 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 Term Loan, in whole or in part, without premium or penalty, upon irrevocable notice to the administrative agent. We may also reprice the Term Loan, 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 Term Loan, in whole or in part subject to approval from those lenders holding such term loans. The Term Loan is 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 Term Loan outstanding within thirty (30) days after the date of such change of control triggering event.

In connection with the Term Loan, 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 Term Loan is 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 Term Loan 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 Term Loan amounts (as defined in the Credit Agreement) may declare all the Term Loan amounts outstanding to be due and payable immediately.

In connection with the Term Loan, we recorded deferred financing costs of approximately $14 million on our Consolidated Condensed Balance Sheet as of June 30, 2011, and we recorded approximately $74 million in debt extinguishment costs during the first quarter of 2011, which includes approximately $36 million from the write-off of unamortized deferred financing costs, the write-off of approximately $25 million of debt discount and approximately $13 million in prepayment premiums related to the NDH Project Debt.

On June 17, 2011, we repaid approximately $340 million of project debt with the proceeds received from $360 million in borrowings under the New Term Loan. The New Term Loan carries substantially the same terms as the Term Loan and matures on April 1, 2018. The New Term Loan also contains very similar covenants, qualifications, exceptions and limitations as the Term Loan and First Lien Notes.

In connection with the New Term Loan, we recorded deferred financing costs of approximately $5 million on our Consolidated Condensed Balance Sheet as of June 30, 2011, and we recorded approximately $5 million in debt extinguishment costs during the three and six months ended June 30, 2011.

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, a 619 MW combined-cycle power plant under construction in Hayward, CA, which comprises 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 and borrowings bear interest initially at LIBOR plus 2.25%. At June 30, 2011, approximately $69 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 is 75% and the pro rata share related to the noncontrolling interest is 25%.

In connection with the closing of the Russell City Project Debt, we recorded deferred financing costs of approximately $26 million on our Consolidated Condensed Balance Sheet as of June 30, 2011.

12

Corporate Revolving Facility and Other Letter of Credit Facilities

The table below represents amounts issued under our letter of credit facilities at June 30, 2011, and December 31, 2010 (in millions):

	June 30, 2011		December 31, 2010
Corporate Revolving Facility(1)	$	369	$	443
Calpine Development Holdings, Inc.		193		165
NDH Project Debt credit facility(2)		—		34
Various project financing facilities		100		69
Total	$	662	$	711

_________

(1) When we entered into our $1.0 billion Corporate Revolving Facility on December 10, 2010, the letters of credit issued under our First Lien Credit Facility were either replaced with letters of credit issued by our Corporate Revolving Facility or back-stopped by an irrevocable standby letter of credit issued by a third-party. Our letters of credit under our Corporate Revolving Facility at December 31, 2010 include those that were back-stopped of approximately $83 million. The back-stopped letters of credit were returned and extinguished during the first quarter of 2011.

(2) We repaid and terminated the NDH Project Debt on March 9, 2011.

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 (with the exception of any swingline borrowings, which bear interest at the base 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 2 business days or be converted into borrowings as provided in the Corporate Revolving Facility credit agreement. We will 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 $3.0 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.

We also have a letter of credit facility related to our subsidiary Calpine Development Holdings, Inc. which matures on December 11, 2012, under which up to $200 million is available for letters of credit.

13

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. We measured the fair value of our debt instruments at June 30, 2011, and December 31, 2010, using market information including credit default swap rates and historical default information, quoted market prices or dealer quotes for the identical liability when traded as an asset and discounted cash flow analyses based on our current borrowing rates for similar types of borrowing arrangements. The following table details the fair values and carrying values of our debt instruments at June 30, 2011, and December 31, 2010 (in millions):

	June 30, 2011				December 31, 2010
	Fair Value		Carrying Value		Fair Value		Carrying Value
First Lien Notes(1)	$	6,032	$	5,891	$	4,695	$	4,691
Project financing, notes payable and other(2)(3)(4)		1,355		1,378		1,673		1,708
Term Loan and New Term Loan(1)(2)		1,638		1,654		—		—
NDH Project Debt(1)		—		—		1,303		1,258
First Lien Credit Facility(1)		—		—		1,182		1,184
CCFC Notes		1,073		969		1,067		965
Total	$	10,098	$	9,892	$	9,920	$	9,806

_________

(1) On March 9, 2011, we repaid and terminated the NDH Project Debt with proceeds received from the Term Loan, and on January 14, 2011, we repaid and terminated the First Lien Credit Facility with the issuance of the 2023 First Lien Notes as discussed above.

(2) On June 17, 2011, we repaid approximately $340 million of project debt with the proceeds received from $360 million in borrowings under the New Term Loan as described above.

(3) On June 24, 2011, we closed on the approximately $845 million Russell City Project Debt to fund the construction of Russell City as described above.

(4) Excludes leases that are accounted for as failed sale-leaseback transactions under U.S. GAAP and included in our project financing, notes payable and other balance.

6.  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 in 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 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; however, other qualitative assessments can also be used 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.

14

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 markets 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 primarily consist of our 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 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.

The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis at June 30, 2011, and December 31, 2010, 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 at June 30, 2011
	Level 1		Level 2		Level 3		Total
	(in millions)
Assets:
Cash equivalents(1)	$	1,334	$	—	$	—	$	1,334
Margin deposits		133		—		—		133
Commodity instruments:
Commodity futures contracts		460		—		—		460
Commodity forward contracts(2)		—		173		45		218
Interest rate swaps		—		1		—		1
Total assets	$	1,927	$	174	$	45	$	2,146
Liabilities:
Commodity instruments:
Commodity futures contracts	$	414	$	—	$	—	$	414
Commodity forward contracts(2)		—		112		24		136
Interest rate swaps		—		314		—		314
Total liabilities	$	414	$	426	$	24	$	864

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	Assets and Liabilities with Recurring Fair Value Measures at December 31, 2010
	Level 1		Level 2		Level 3		Total
	(in millions)
Assets:
Cash equivalents(1)	$	1,297	$	—	$	—	$	1,297
Margin deposits		162		—		—		162
Commodity instruments:
Commodity futures contracts		550		—		—		550
Commodity forward contracts(2)		—		287		54		341
Interest rate swaps		—		4		—		4
Total assets	$	2,009	$	291	$	54	$	2,354
Liabilities:
Margin deposits held by us posted by our counterparties	$	6	$	—	$	—	$	6
Commodity instruments:
Commodity futures contracts		574		—		—		574
Commodity forward contracts(2)		—		119		24		143
Interest rate swaps		—		371		—		371
Total liabilities	$	580	$	490	$	24	$	1,094

_________

(1) At June 30, 2011, and December 31, 2010, we had cash equivalents of $1,144 million and $1,094 million included in cash and cash equivalents and $190 million and $203 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 June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Balance, beginning of period	$	12		$	57		$	30		$	38
Realized and unrealized gains (losses):
Included in net loss:
Included in operating revenues(1)		10			10			6			29
Included in fuel and purchased energy expense(2)		1			(3	)		—			(3	)
Included in OCI		4			(5	)		5			—
Purchases, issuances, sales and settlements:
Purchases		1			—			1			—
Settlements		(7	)		(16	)		(21	)		(22	)
Transfers into and/or out of level 3:(3)
Transfers out of level 3(4)		—			—			—			1
Balance, end of period	$	21		$	43		$	21		$	43
Change in unrealized gains relating to instruments held at end of period	$	11		$	7		$	7		$	26

_________

(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 significant transfers into/out of level 1 or out of level 2 or into level 3 during the three and six months ended June 30, 2011 and 2010.

(4) There were no significant transfers into level 2 or out of level 3 for the three months ended June 30, 2011 and 2010, and the six months ended June 30, 2011. We had $(1) million in losses transferred out of level 3 into level 2 for the six months ended June 30, 2010. Transfers out of level 3 into level 2 were due to changes in market liquidity in various power markets.

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7.  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) 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.

At June 30, 2011, the maximum length of time that our PPAs extend is approximately 24 years into the future and the maximum length of time over which we were hedging using commodity and interest rate derivative instruments was 2 and 15 years, respectively.

At June 30, 2011 and December 31, 2010, 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):

	Notional Amounts
	June 30, 2011			December 31, 2010
Derivative Instruments
Power (MWh)		(40	)		(50	)
Natural gas (MMBtu)		170			31
Interest rate swaps(1)	$	5,191		$	6,171

_________

(1) Approximately $4.1 billion and $3.3 billion at June 30, 2011 and December 31, 2010, respectively, related to variable rate debt that was converted to fixed rate debt in 2011 and 2010.

Certain of our derivative instruments contain credit-contingent provisions that require us to maintain our current credit rating or higher from each of the major credit rating agencies. If our credit rating were to be downgraded, it could require us to post additional collateral or could potentially allow our counterparty(ies) 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 rating level downgrade would be material. The aggregate fair value of our derivative liabilities with credit-contingent provisions at June 30, 2011, was $48 million for which we have posted collateral of $3 million by posting margin deposits or granting additional first priority liens on the assets currently subject to first priority liens under our Corporate Revolving Facility. If our credit rating were downgraded, we estimate that additional collateral of approximately $21 million would be required and that no counterparty could request immediate, full settlement.

Accounting for Derivative Instruments

We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Condensed Statements of Operations until the period of delivery. Revenues and fuel costs derived from instruments that qualify for hedge accounting or represent an economic hedge are recorded in the same period and 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 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 or interest rate swap breakage costs associated with interest rate swaps formerly hedging project debt) 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.

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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 commodity hedging instruments are included in unrealized mark-to-market gains and losses, and 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. Upon repayment of our NDH Project Debt and other project debt, we terminated and settled the interest rate swaps related to these debt instruments and recorded $17 million to (gain) loss on interest rate derivatives, net for both the three months and six months ended June 30, 2011. See Note 5 for further information about the repayment of the NDH Project Debt as well as the repayment of other project debt with proceeds from our New Term Loan.

Derivatives Not Designated as Hedging Instruments — Along with our portfolio of transactions which are accounted for as hedges under U.S. GAAP, we enter into power, natural gas and interest rate transactions that primarily act as economic hedges to our asset 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 and Other Project Debt — During 2010, we repaid approximately $3.5 billion of our First Lien Credit Facility term loans, which had approximately $3.3 billion notional amount of interest rate swaps hedging the scheduled variable interest payments, and in January 2011, we repaid the remaining approximately $1.2 billion of 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 the remaining First Lien Credit Facility term loans, the remaining unrealized losses of approximately $91 million in AOCI related to the interest swaps formerly hedging the First Lien Credit Facility, were reclassified out of AOCI and into income as an additional (gain) loss on interest rate derivatives, net, during the first quarter of 2011. In addition, we reclassified approximately $17 million in unrealized losses in AOCI to (gain) loss on interest rate derivatives, net during the second quarter of 2011 resulting from the repayment of project debt in June 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 (gain) loss on interest rate derivatives, net on our Consolidated Condensed Statements of Operations. We also have determined that, based upon current market conditions and consistent with our risk management policy, liquidation of these interest rate swaps is not economically beneficial and additional future losses are limited. Accordingly, we have elected to retain and hold these interest rate swap positions at this time.

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Derivatives Included on Our Consolidated Condensed Balance Sheets

The following tables present the fair values of our net derivative instruments recorded on our Consolidated Condensed Balance Sheets by hedge type and location at June 30, 2011, and December 31, 2010 (in millions):

	June 30, 2011
	Interest Rate Swaps			Commodity Instruments		Total Derivative Instruments
Balance Sheet Presentation
Current derivative assets	$	—		$	569	$	569
Long-term derivative assets		1			109		110
Total derivative assets	$	1		$	678	$	679
Current derivative liabilities	$	195		$	448	$	643
Long-term derivative liabilities		119			102		221
Total derivative liabilities	$	314		$	550	$	864
Net derivative assets (liabilities)	$	(313	)	$	128	$	(185	)

	December 31, 2010
	Interest Rate Swaps			Commodity Instruments		Total Derivative Instruments
Balance Sheet Presentation
Current derivative assets	$	—		$	725	$	725
Long-term derivative assets		4			166		170
Total derivative assets	$	4		$	891	$	895
Current derivative liabilities	$	197		$	521	$	718
Long-term derivative liabilities		174			196		370
Total derivative liabilities	$	371		$	717	$	1,088
Net derivative assets (liabilities)	$	(367	)	$	174	$	(193	)

	June 30, 2011				December 31, 2010
	Fair Value of Derivative Assets		Fair Value of Derivative Liabilities		Fair Value of Derivative Assets		Fair Value of Derivative Liabilities
Derivatives designated as cash flow hedging instruments:
Interest rate swaps	$	—	$	49	$	2	$	143
Commodity instruments		104		41		161		52
Total derivatives designated as cash flow hedging instruments	$	104	$	90	$	163	$	195
Derivatives not designated as hedging instruments:
Interest rate swaps	$	1	$	265	$	2	$	228
Commodity instruments		574		509		730		665
Total derivatives not designated as hedging instruments	$	575	$	774	$	732	$	893
Total derivatives	$	679	$	864	$	895	$	1,088

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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 net income.

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 not designated as hedging instruments and where these components were recorded on our Consolidated Condensed Statements of Operations for the periods indicated (in millions):

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Realized gain (loss)
Interest rate swaps	$	(60	)	$	(6	)	$	(106	)	$	(12	)
Commodity derivative instruments		42			59			52			52
Total realized gain (loss)	$	(18	)	$	53		$	(54	)	$	40
Unrealized gain (loss)(1)
Interest rate swaps	$	24		$	(16	)	$	(38	)	$	(19	)
Commodity derivative instruments		26			(31	)		(39	)		81
Total unrealized gain (loss)	$	50		$	(47	)	$	(77	)	$	62
Total mark-to-market activity	$	32		$	6		$	(131	)	$	102

_________

(1) Changes in unrealized gain (loss) include 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 June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Realized and unrealized gain (loss)
Power contracts included in operating revenues	$	48		$	41		$	(9	)	$	12
Natural gas contracts included in fuel and purchased energy expense		20			(13	)		22			121
Interest rate swaps included in interest expense		1			(30	)		2			(28	)
Gain (loss) on interest rate derivatives, net		(37	)		8			(146	)		(3	)
Total mark-to-market activity	$	32		$	6		$	(131	)	$	102

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Derivatives Included in Our OCI and AOCI

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

	Three Months Ended June 30,
	Gain (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)
	2011			2010			2011			2010			2011			2010
Interest rate swaps	$	(9	)	$	(16	)	$	(22	)(3)	$	(62	)	$	(1	)	$	—
Commodity derivative instruments		(39	)		(47	)		53	(1)		54			1			3
Total	$	(48	)	$	(63	)	$	31		$	(8	)	$	—		$	3

	Six Months Ended June 30,
	Gain (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)
	2011			2010			2011			2010			2011			2010
Interest rate swaps	$	94		$	(27	)	$	(123	)(4)	$	(122	)	$	(1	)	$	—
Commodity derivative instruments		(36	)		79			79	(1)		100			1			1
Total	$	58		$	52		$	(44	)	$	(22	)	$	—		$	1

_________

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

(2) Cumulative cash flow hedge losses remaining in AOCI were $81 million and $122 million at June 30, 2011 and December 31, 2010, respectively.

(3) Reclassification of losses from OCI to earnings for the three months ended June 30, 2011 consisted of $7 million in losses from the reclassification of interest rate contracts due to settlement and $15 million in losses from terminated interest rate contracts due to the repayment of project debt in June 2011.

(4) Reclassification of losses from OCI to earnings for the six months ended June 30, 2011 consisted of $17 million in losses from the reclassification of interest rate contracts due to settlement, $15 million in losses from terminated interest rate contracts due to the repayment of project debt in June 2011, and $91 million in losses from existing interest rate contracts reclassified from OCI into earnings due to the repayment of project debt in June 2011.

Assuming constant June 30, 2011, power and natural gas prices and interest rates, we estimate that pre-tax net gains of $45 million would be reclassified from AOCI into our net income 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 natural gas and power prices as well as interest rates. Therefore, we are unable to predict what the actual reclassification from AOCI to our net income (positive or negative) will be for the next 12 months.

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8.  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 our Corporate Revolving Facility as collateral under certain of our power and natural gas agreements that qualify as “eligible commodity hedge agreements” under our Corporate Revolving Facility 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 Corporate Revolving Facility, First Lien Notes, Term Loan and New Term Loan.

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 at June 30, 2011, and December 31, 2010 (in millions):

	June 30, 2011		December 31, 2010
Margin deposits(1)	$	133	$	162
Natural gas and power prepayments		49		43
Total margin deposits and natural gas and power prepayments with our counterparties(2)	$	182	$	205
Letters of credit issued(3)	$	492	$	588
First priority liens under power and natural gas agreements(4)		—		—
First priority liens under interest rate swap agreements		299		356
Total letters of credit and first priority liens with our counterparties	$	791	$	944
Margin deposits held by us posted by our counterparties(1)(5)	$	—	$	6
Letters of credit posted with us by our counterparties		36		66
Total margin deposits and letters of credit posted with us by our counterparties	$	36	$	72

_________

(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 June 30, 2011 and December 31, 2010, $158 million and $183 million were included in margin deposits and other prepaid expense, respectively, and $24 million and $22 million were included in other assets at June 30, 2011 and December 31, 2010, respectively, on our Consolidated Condensed Balance Sheets.

(3) When we entered into our Corporate Revolving Facility on December 10, 2010, the letters of credit issued under our First Lien Credit Facility were either replaced by letters of credit issued by the Corporate Revolving Facility or back-stopped by an irrevocable standby letter of credit issued by a third party. Our letters of credit issued under our Corporate Revolving Facility used for our commodity procurement and risk management activities at December 31, 2010 include those that were back-stopped of approximately $63 million. The back-stopped letters of credit were returned and extinguished during the first quarter of 2011.

(4) At June 30, 2011, and December 31, 2010, the fair value of our commodity derivative instruments collateralized by first priority liens included assets of $99 million and $193 million, respectively; therefore, there was no collateral exposure at June 30, 2011, or December 31, 2010.

(5) 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.

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9.  Income Taxes

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Income tax expense (benefit)	$	18		$	6		$	(65	)(1)	$	17	(2)
Imputed tax rate		(35	)%		(5	)%		15	%		(11	)%
Intraperiod tax allocation expense (benefit)	$	18		$	(31	)	$	(16	)	$	(17	)

_________

(1) Includes a tax benefit of approximately $76 million related to the consolidation of the CCFC and Calpine groups for federal income tax reporting purposes for the six months ended June 30, 2011 (as described below).

(2) Includes approximately $13 million in intraperiod tax expense related to a prior period with an offsetting benefit in OCI.

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) and income from discontinued operations with an offsetting amount recognized in OCI and discontinued operations. The following table details the effects of our intraperiod tax allocations for the three and six months ended June 30, 2011 and 2010 (in millions).

	Three Months Ended June 30,
	Included in continuing operations					Included in discontinued operations				Included in OCI
	2011		2010			2011		2010		2011			2010
Intraperiod tax allocation expense (benefit)	$	18	$	(31	)	$	—	$	8	$	(18	)	$	23

	Six Months Ended June 30,
	Included in continuing operations						Included in discontinued operations				Included in OCI
	2011			2010			2011		2010		2011		2010
Intraperiod tax allocations expense (benefit)	$	(16	)	$	(17	)	$	—	$	8	$	16	$	9

Accounting for Income Taxes

Consolidation of CCFC and Calpine Tax Reporting Groups — For federal income tax reporting purposes, our historical tax reporting group was comprised primarily of two separate groups, CCFC and its subsidiaries, which we referred to as the CCFC group, and Calpine Corporation and its subsidiaries other than CCFC, which we referred to as the Calpine group. During the first quarter of 2011, we elected to consolidate our CCFC and Calpine groups for federal income tax reporting purposes and Calpine will file a consolidated federal income tax return for the year ended December 31, 2011 that will include the CCFC group. As a result of the consolidation, the CCFC group deferred tax liabilities will be eligible to offset existing Calpine group NOLs that were reserved by a valuation allowance. Accordingly, we recorded a one-time federal deferred income tax benefit of approximately $76 million during the first quarter of 2011 to reduce our valuation allowance. For the three and six months ended June 30, 2010, the CCFC group was deconsolidated from the Calpine group for federal income tax reporting purposes.

For the three and six months ended June 30, 2011 and 2010, we used the effective rate method to determine both the CCFC and Calpine groups’ tax provision, as applicable; however, our income tax rates did not bear a customary relationship to statutory income tax rates primarily as a result of the consolidation of the CCFC and Calpine groups for 2011, the impact of state income taxes, changes in unrecognized tax benefits, the Calpine group valuation allowance and intraperiod tax allocations.

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 in prior periods, we are unable to assume future profits; however, since our emergence from Chapter 11, we are able to consider available tax planning strategies.

Unrecognized Tax Benefits and Liabilities — At June 30, 2011, we had unrecognized tax benefits of $88 million. If recognized, $41 million of our unrecognized tax benefits could impact the annual effective tax rate and $47 million related to deferred tax assets could be offset against the recorded valuation allowance resulting in no impact to our effective tax rate. We also had accrued

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interest and penalties of $21 million for income tax matters at June 30, 2011. The amount of unrecognized tax benefits at June 30, 2011 remained comparable to the amount of unrecognized tax benefits at December 31, 2010. We believe it is reasonably possible that a decrease within the range of approximately $13 million and $16 million in unrecognized tax benefits could occur within the next 12 months primarily related to federal tax liabilities, interest and penalties.

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 Internal Revenue Code. 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. At December 31, 2010, approximately $2.5 billion of our $7.4 billion total NOLs remain subject to annual section 382 limitations with the remaining $4.9 billion no longer subject to the Section 382 limitation. 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 Internal Revenue Code. We are analyzing 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 will also determine our state NOLs expected to expire unutilized as a result of the cessation of business operations and changes in apportionment as of the Effective Date. Although our analysis is not complete, we believe that the statutory limitations on the use of some of our pre-emergence state NOLs will cause them to expire unutilized. We believe our analysis could result in a reduction of available state NOLs, which had a full valuation allowance at June 30, 2011 and December 31, 2010. Upon completion of the analysis, we will reduce our deferred tax asset for state NOLs that we are unable to utilize and make an equal reduction in our valuation allowance. The result is not expected to have an effect on our income tax expense in 2011.

We have certain intercompany accounts payable / receivable balances that we will be eliminating as part of the final steps of our emergence from bankruptcy. We are analyzing the federal and state income tax effects of eliminating these balances and, although our analysis is not complete, we believe that the elimination of some of these pre-petition intercompany balances will have the ultimate effect of recharacterizing a portion of our federal and state ordinary NOLs into either capital losses, which has a shorter carryforward period, or increasing the tax basis in our affiliates, a portion of which will not be recognized until the related entity is sold. Certain of these recharacterizations may result in a reduction of our gross deferred tax asset along with an equal reduction in our valuation allowance. The elimination of these intercompany account balances is not expected to have an effect on our income tax expense in 2011.

The State of California enacted legislation in 2010 suspending the ability of taxpayers to use NOLs for tax years 2010 and 2011; however, they have extended the 20 year carryforward period to account for the suspension period.

To manage the risk of significant limitations on our ability to utilize our tax NOL carryforwards, our amended and restated certificate of incorporation permits our Board of Directors to meet to determine whether to impose certain transfer restrictions on our common stock in the following circumstances: 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 Internal Revenue Code. 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, they shall 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.

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10.  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 pursuant to our Plan of Reorganization. Accordingly, although the reserved shares are not yet issued and outstanding, 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 and six months ended June 30, 2011 and 2010, diluted loss per share for these 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 potentially dilutive securities from our calculation of weighted average shares outstanding from diluted earnings per common share for the periods indicated:

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
	(shares in thousands)
Share-based awards		15,309		15,000		15,131		14,655

11.  Stock-Based Compensation

The Calpine Equity Incentive Plans provide for the issuance of equity awards to all 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 of approximately five and ten years and are subject to forfeiture provisions under certain circumstances, including termination of employment prior to vesting. At June 30, 2011, there are 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 to estimate the fair value of our employee stock options on the grant date, which takes into account the exercise price and expected life 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 $7 million and $6 million for the three months ended June 30, 2011 and 2010, respectively, and $12 million for both the six months ended June 30, 2011 and 2010. 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 and six months ended June 30, 2011 and 2010. At June 30, 2011, there was unrecognized compensation cost of $17 million related to options, $22 million related to restricted stock and $1 million related to restricted stock units, which is expected to be recognized over a weighted average period of 1.6 years for options, 1.8 years for restricted stock and 0.9 years for restricted stock units. We issue new shares from our reserves set aside for the Calpine Equity Incentive Plans and employment inducement options when stock options are exercised and for other share-based awards.

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A summary of all of our non-qualified stock option activity for the Calpine Equity Incentive Plans for the six months ended June 30, 2011, is as follows:

	Number of Shares		Weighted Average Exercise Price		Weighted Average Remaining Term (in years)		Aggregate Intrinsic Value (in millions)
Outstanding - December 31, 2010		17,164,890	$	17.44		5.6	$	8
Granted		909,306	$	14.32
Exercised		6,654	$	10.95
Forfeited		51,050	$	11.23
Expired		156,885	$	17.55
Outstanding - June 30, 2011		17,859,607	$	17.30		5.3	$	25
Exercisable - June 30, 2011		6,665,499	$	19.15		5.3	$	1
Vested and expected to vest - June 30, 2011		17,443,021	$	17.41		5.2	$	24

The total intrinsic value and the cash proceeds received from our employee stock options exercised were not significant for the six months ended June 30, 2011 and 2010.

The fair value of options granted during the six months ended June 30, 2011 and 2010, was determined on the grant date using the Black-Scholes pricing model. Certain assumptions were used in order to estimate fair value for options as noted in the following table.

	2011			2010
Expected term (in years)(1)		6.5			6.5
Risk-free interest rate(2)		2.7 — 3.2	%		2.9 — 3.3	%
Expected volatility(3)		31.2 — 31.7	%		35.0 — 37.6	%
Dividend yield(4)		—			—
Weighted average grant-date fair value (per option)	$	5.48		$	4.66

_________

(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 six months ended June 30, 2011, is as follows:

	Number of Restricted Stock Awards		Weighted Average Grant-Date Fair Value
Nonvested - December 31, 2010		2,683,117	$	11.16
Granted		1,630,465	$	14.38
Forfeited		145,923	$	11.88
Vested		460,232	$	14.62
Nonvested - June 30, 2011		3,707,427	$	12.10

The total fair value of our restricted stock and restricted stock units that vested during the six months ended June 30, 2011 and 2010, was $7 million and $4 million, respectively.

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12.  Commitments and Contingencies

Litigation

We are party to various litigation matters, including regulatory and administrative proceedings arising out of the normal course of business. 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 to our financial position, 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 to our financial position, results of operations or cash flows. Further, following the Effective Date, pending actions to enforce or otherwise effect repayment of liabilities preceding December 20, 2005, the petition date, as well as pending litigation against the U.S. Debtors related to such liabilities, generally have been permanently enjoined. Any unresolved claims will continue to be subject to the claims reconciliation process under the supervision of the U.S. Bankruptcy Court. However, certain pending litigation related to pre-petition liabilities may proceed in courts, other than the U.S. Bankruptcy Court, to the extent the parties to such litigation have obtained relief from the permanent injunction.

Pit River Tribe, et al. v. Bureau of Land Management, et al. — On June 17, 2002, the Pit River Tribe filed suit against the BLM and other federal agencies in the U.S. District Court for the Eastern District of California seeking to enjoin further exploration, construction and development of the Calpine Four-Mile Hill Project in the Glass Mountain and Medicine Lake geothermal areas. The complaint challenged the validity of the decisions of the BLM and the U.S. Forest Service to permit the development of the proposed project under two geothermal mineral leases previously issued by the BLM. The lawsuit also sought to invalidate the leases. Only declaratory and equitable relief was sought.

On November 5, 2006, the U.S. Court of Appeals for the Ninth Circuit issued a decision granting the plaintiffs relief by holding that the BLM had not complied with the National Environmental Policy Act, and other procedural requirements and, therefore, held that the lease extensions were invalid. As reported last quarter, on November 4, 2010, the United States District for the Eastern District of California entered an order remanding the matter to federal agencies to implement the Court’s order. We consider this matter closed and anticipate it will take the federal agencies at least one year to implement the Court’s order to conduct additional analysis.

In addition, in May 2004, the Pit River Tribe and other interested parties filed two separate suits in the District Court seeking to enjoin exploration, construction, and development of the Telephone Flat leases and proposed project at Glass Mountain. These two cases have remained mostly inactive pending the outcome of the above described Pit River Tribe case. Now that the above Pit River Tribe case has been resolved, we anticipate the Pit River Tribe and other interested parties may seek to reactivate the two additional suits, and we are in communication with the U.S. Department of Justice regarding how to proceed.

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 normal operation of our power plants. We do not, however, 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. A summary of our larger environmental matters are as follows:

Environmental Remediation of Certain Assets Acquired from Conectiv — As part of the Conectiv Acquisition on July 1, 2010, we assumed environmental remediation liabilities related to certain of the assets located in New Jersey that are subject to the ISRA. We have accrued or paid $10 million related to these liabilities at June 30, 2011. Pursuant to the Conectiv Purchase Agreement, PHI is responsible for any amounts that exceed $10 million associated with New Jersey environmental remediation liabilities. Our accrual is included in our allocation of the Conectiv Acquisition purchase price. See Note 2 for disclosures related to our Conectiv Acquisition.

Heat Input Limits at Deepwater Unit 1 — Prior to our acquisition, Conectiv was a party to certain pending penalty proceedings in the administrative courts of the State of New Jersey involving one of the older peaker power plants (Deepwater Unit 1). The NJDEP alleged that Deepwater Unit 1 had exceeded its permissible maximum heat input limit, which restricts the amount of fuel burned. Heat input limits are imposed on power plants to limit emissions of pollutants that are not subject to measurement by continuous emissions monitoring systems. These restrictions required one of our peaker power plants (Deepwater Unit 1) to operate at approximately 8 MW less than its full capacity of 86 MW. As part of the settlement reached with the NJDEP, we submitted an application to modify the Deepwater Unit 1 air permit to reclaim the 8 MW limitation and the application was recently approved. We

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received a permit to allow Deepwater Unit 1 to operate at approximately 86 MW versus the 78 MW restriction during the appeal process. We continue settlement discussions with NJDEP regarding the modification of permits for the other peaker power plants and those appeals remain pending.

Other Contingencies

Distribution of Calpine Common Stock under our Plan of Reorganization — Through the filing of this Report, approximately 464 million shares have been distributed to holders of allowed unsecured claims and approximately 21 million shares remain in reserve for distribution to holders of disputed claims whose claims ultimately become allowed under our Plan of Reorganization. To the extent that any of the reserved shares remain undistributed upon resolution of the remaining disputed claims, such shares will not be returned to us but rather will be distributed pro rata to claimants with allowed claims to increase their recovery. We are not required to issue additional shares above the 485 million shares authorized to settle unsecured claims, even if the shares remaining for distribution are not sufficient to fully pay all allowed unsecured claims. Holders of the CalGen Third Lien Debt made assertions that they continued to have lien rights to the assets of the CalGen entities until the pending claims asserted in the case styled: HSBC Bank USA, NA as Indenture Trustee, et al v. Calpine Corporation, et al. Case No. 1: 07-cv-03088, S.D.N.Y. are resolved either through court action or settlement. On June 2, 2011, we reached a settlement with holders of the CalGen Third Lien Debt which will be funded from the sale of a portion of the shares held in reserve. The balance of the reserve shares are expected to be distributed to the remaining unsecured creditors over the next few months in accordance with our Plan of Reorganization. The exact timing and number of shares to be distributed will be subject to our final calculation. The sale of shares or the distribution of the remaining shares does not represent the issuance of new or additional shares and will have no impact on our results of operations, financial position or cash flows. The bankruptcy court approved the settlement with the CalGen Third Lien Debt claimants on June 16, 2011. The settlement agreements with the CalGen Third Lien Debt claimants and the claims purchasers are expected to be fully implemented by early August.

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13.  Segment Information

We assess our business on a regional basis due to the impact on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors impacting supply and demand. At June 30, 2011, our reportable segments were West (including geothermal), Texas, North (including Canada and the assets purchased in the Conectiv Acquisition) 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). Our North segment information for the three and six months ended June 30, 2011, includes the financial results of the assets we acquired from Conectiv, with no similar revenues and expenses included for the three and six months ended June 30, 2010. See Note 2 for further information about our Conectiv Acquisition.

	Three Months Ended June 30, 2011
	West		Texas		North		Southeast			Consolidation and Elimination			Total
Revenues from external customers	$	466	$	646	$	324	$	197		$	—		$	1,633
Intersegment revenues		1		5		5		40			(51	)		—
Total operating revenues	$	467	$	651	$	329	$	237		$	(51	)	$	1,633
Commodity Margin	$	236	$	128	$	179	$	59		$	—		$	602
Add: Mark-to-market commodity activity, net and other revenue(1)		11		27		—		—			(9	)		29
Less:
Plant operating expense		116		63		47		41			(6	)		261
Depreciation and amortization expense		42		35		33		22			(1	)		131
Sales, general and other administrative expense		8		13		6		6			1			34
Other operating expenses(2)		11		3		9		2			(5	)		20
Loss from unconsolidated investments in power plants		—		—		2		—			—			2
Income (loss) from operations		70		41		82		(12	)		2			183
Interest expense, net of interest income														190
(Gain) loss on interest rate derivatives, net														37
Debt extinguishment costs and other (income) expense, net														8
Loss before income taxes and discontinued operations													$	(52	)

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	Three Months Ended June 30, 2010
	West		Texas			North			Southeast			Consolidation and Elimination			Total
Revenues from external customers	$	525	$	552		$	134		$	219		$	—		$	1,430
Intersegment revenues		1		6			1			21			(29	)		—
Total operating revenues	$	526	$	558		$	135		$	240		$	(29	)	$	1,430
Commodity Margin	$	258	$	128		$	79		$	68		$	—		$	533
Add: Mark-to-market commodity activity, net and other revenue(1)		10		(10	)		3			(9	)		(6	)		(12	)
Less:
Plant operating expense		88		78			23			31			(7	)		213
Depreciation and amortization expense		50		40			19			27			(1	)		135
Sales, general and other administrative expense		11		16			22			2			(1	)		50
Other operating expenses(2)		12		(5	)		7			(1	)		8			21
(Income) from unconsolidated investments in power plants		—		—			(6	)		—			—			(6	)
Income (loss) from operations		107		(11	)		17			—			(5	)		108
Interest expense, net of interest income																220
(Gain) loss on interest rate derivatives, net																(8	)
Debt extinguishment costs and other (income) expense, net																8
Loss before income taxes and discontinued operations															$	(112	)

	Six Months Ended June 30, 2011
	West		Texas			North			Southeast			Consolidation and Elimination			Total
Revenues from external customers	$	1,065	$	1,096		$	595		$	376		$	—		$	3,132
Intersegment revenues		4		10			13			85			(112	)		—
Total operating revenues	$	1,069	$	1,106		$	608		$	461		$	(112	)	$	3,132
Commodity Margin	$	469	$	195		$	314		$	113		$	—		$	1,091
Add: Mark-to-market commodity activity, net and other revenue(1)		16		(33	)		4			(4	)		(15	)		(32	)
Less:
Plant operating expense		203		143			92			74			(13	)		499
Depreciation and amortization expense		88		65			66			45			(2	)		262
Sales, general and other administrative expense		19		23			12			11			1			66
Other operating expenses(2)		19		3			16			3			(3	)		38
(Income) from unconsolidated investments in power plants		—		—			(7	)		—			—			(7	)
Income (loss) from operations		156		(72	)		139			(24	)		2			201
Interest expense, net of interest income																378
(Gain) loss on interest rate derivatives, net																146
Debt extinguishment costs and other (income) expense, net																108
Loss before income taxes and discontinued operations															$	(431	)

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	Six Months Ended June 30, 2010
	West		Texas		North			Southeast		Consolidation and Elimination			Total
Revenues from external customers	$	1,190	$	1,079	$	257		$	418	$	—		$	2,944
Intersegment revenues		5		10		2			44		(61	)		—
Total operating revenues	$	1,195	$	1,089	$	259		$	462	$	(61	)	$	2,944
Commodity Margin	$	471	$	235	$	131		$	126	$	—		$	963
Add: Mark-to-market commodity activity, net and other revenue(1)		18		86		—			13		(14	)		103
Less:
Plant operating expense		178		162		45			59		(13	)		431
Depreciation and amortization expense		103		76		39			56		(3	)		271
Sales, general and other administrative expense		26		16		25			6		(1	)		72
Other operating expenses(2)		29		2		15			2		(1	)		47
(Income) from unconsolidated investments in power plants		—		—		(13	)		—		—			(13	)
Income from operations		153		65		20			16		4			258
Interest expense, net of interest income														399
(Gain) loss on interest rate derivatives, net														3
Debt extinguishment costs and other (income) expense, net														13
Loss before income taxes and discontinued operations													$	(157	)

_________

(1) Mark-to-market commodity activity represents 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.

(2) Excludes $2 million and $5 million of RGGI compliance and other environmental costs for the three months ended June 30, 2011 and 2010, respectively, and $4 million and $5 million for the six months ended June 30, 2011 and 2010, respectively, which are included as a component of Commodity Margin.

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

Forward-Looking Information

This Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our accompanying Consolidated Condensed Financial Statements and related notes. See the cautionary statement regarding forward-looking statements on page ix 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, regulatory capacity, renewable energy credits and ancillary services to our customers, including 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 we purchase electric transmission rights to deliver power to our customers. We also enter into natural gas and power physical and financial contracts to hedge certain business risks and optimize our portfolio of power plants. Our goal is to be recognized as the premier independent power company in the U.S. as measured by our customers, regulators, shareholders and communities in which our power plants 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 hedging agreements within the guidelines of our commodity risk policy.

We continue to make significant progress to maintain financially disciplined growth, to enhance shareholder value and to set the foundation for continued growth and success with the following achievements during the first half of 2011:

• Our York Energy Center, a 565 MW dual fuel, combined-cycle power plant achieved COD on March 2, 2011 and began selling power under a six-year PPA with a third party which commenced on June 1, 2011.

• Construction of our Russell City Energy Center, which closed on construction financing in June 2011, and upgrades at our Los Esteros Critical Energy Facility continue to move forward with expected completion dates in 2013.

• We issued our 2023 First Lien Notes, terminated our First Lien Credit Facility and extended our corporate debt maturities. Together, these changes eliminated the more restrictive of our debt covenants, resulting in increased operational, strategic and financial flexibility in managing our capital resources including the flexibility to reinvest more earnings for organic growth, issue and/or buyback shares of our common stock and incur additional debt, if needed, for acquisitions or development projects. Additionally, we achieved attractive yields and a maturity schedule stretching from 2017 to 2023 with no more than $2.0 billion of corporate debt maturing in any given year.

• We have further continued to reduce our overall cost of debt and simplify our capital structure by refinancing subsidiary level debt with corporate level term loans eliminating the need for subsidiary level reporting and the potential for cash to be temporarily trapped at the subsidiary level.  On March 9, 2011, we closed on the $1.3 billion Term Loan and used the net proceeds received, together with operating cash on hand, to fully retire the approximately $1.3 billion NDH Project Debt in accordance with its repayment terms. On June 17, 2011, we repaid approximately $340 million of project debt with the proceeds received from $360 million in borrowings under the New Term Loan.

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

Our portfolio, including partnership interests, includes 92 operating power plants, located throughout 20 states in the U.S. and Canada, with an aggregate generation capacity of 28,127 MW and 584 MW under construction. Our generation capacity includes approximately 725 MW of baseload capacity from our Geysers Assets and 4,542 MW of baseload capacity from our cogeneration power plants, 16,393 MW of intermediate load capacity from our combined-cycle combustion turbines and 6,467 MW of peaking capacity from our simple-cycle combustion turbines and duct-fired capability, which includes approximately 4 MW of capacity from solar, photovoltaic power generation technology located in New Jersey. Our segments have an aggregate generation capacity of 6,898 MW with an additional 584 MW under construction in the West, 7,239 MW in Texas, 7,907 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, and we have begun expansion efforts to increase our generation capacity at our Geysers Assets.

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Legislative and Regulatory Update

We are subject to complex and stringent energy, environmental and other governmental laws and regulations at the federal, state and local levels in connection with the development, ownership and operation of our power plants. Ongoing state, regional and federal initiatives to implement new environmental and other governmental regulations are expected to have a significant impact on the power generation industry. Such changes could have positive or negative impacts on our existing business. 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, please see “— Governmental and Regulatory Matters” in Part I, Item 1. of our 2010 Form 10-K.

Dodd-Frank Act

As disclosed in our 2010 Form 10-K, the anticipated regulations that will arise under the Dodd-Frank Act are being written by various regulatory agencies. While we are closely monitoring this rule writing process, the exact impact of new rules on our business remains uncertain. We will continue to monitor all relevant developments and rule-making initiatives in the implementation of the Dodd-Frank Act, and we expect to successfully implement any new applicable legislative and regulatory 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.

The EPA Toxics Rule

The Clean Air Act regulates a large number of air pollutants that are known to cause or may reasonably be anticipated to cause adverse effects to human health or adverse environmental effects, known as hazardous air pollutants (“HAPs”). On October 22, 2009, the EPA signed a consent decree that was lodged in the U.S. District Court for the District of Columbia by the EPA in settlement of a suit brought by several environmental groups alleging that the EPA failed to promulgate final emissions standards based on maximum achievable control technology for hazardous air pollutants from coal- and oil-fired power plants, pursuant to Section 112(d) of the Clean Air Act, by the statutorily-mandated deadline. On March 16, 2011, the EPA published proposed National Emission Standards for Hazardous Air Pollutants from Coal- and Oil-fired Electric Utility Steam Generating Units (The Toxics Rule). We are not directly affected by the rule because it does not apply to natural gas-fired units, peaker units or units that use oil as a backup fuel. The consent decree requires the EPA to promulgate final HAP emission standards by November 2011. We believe that the proposed emission standards are sufficiently stringent to force coal units without emission controls to retire or to install acid gas, mercury, and particulate matter controls by 2014 or 2015, which could benefit our competitive position.

Clean Water Act and the Water Intake Rule

The federal Clean Water Act establishes rules regulating the discharge of pollutants into waters of the U.S. 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 once-through cooling, 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.

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 United States. 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 are 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 establishes 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 generally will be allocated sufficient allowances; thus, this legislation is not expected to have a material impact on our operations. We expect the overall impact of this rule will be a net positive to Calpine as the significant emission reductions will require coal-fired electric generating units to either purchase allowances, switch to more expensive fuels, install air pollution controls, or reduce or discontinue operations.

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Court Rulings

In the absence of federal climate change legislation, litigation raising claims relating to GHG emissions is working its way through the federal courts. Recent federal court decisions are divided as to whether large emitters of GHGs may be sued under common law theories of nuisance and negligence.

On September 21, 2009, the U.S. Court of Appeals for the Second Circuit (“Second Circuit”) issued a ruling in State of Connecticut, et al. v. American Electric Power Company Inc., et al., reversing a lower court's dismissal of two public nuisance claims filed by various states, municipalities and private entities against operators of coal-fired power plants. Plaintiffs argued that the power plant defendants contribute to global warming by emitting 650 million tons per year of CO2 and these emissions are causing and will continue to cause serious harm affecting human health and natural resources. The lower court held that plaintiffs' claims presented a non-legal political question and dismissed the complaints. The Second Circuit vacated the lower court's decision, ruling in favor of the plaintiffs. The Second Circuit’s decision was appealed to the U.S. Supreme Court. On June 20, 2011, the Supreme Court issued a decision rejecting the plaintiffs’ federal common law claim. The Court found that even if a federal common law claim could be made by plaintiffs, the CAA essentially “displaced” that claim. The case was remanded to the Second Circuit for further consideration of other issues in the case, including whether the plaintiffs may raise their claims under state common law or whether those claims are also displaced by federal law. We cannot predict the outcome of this case on remand or what impact the precedent of this case could have on our business.

Station Power Ruling

On August 30, 2010, FERC issued an order on remand (“remand order”) regarding its station power policies in response to a ruling by the U.S. Court of Appeals for the D.C. Circuit (“D.C. Circuit”). The D.C. Circuit’s ruling vacated and remanded FERC’s prior orders on CAISO’s station power procedures, finding that FERC had not adequately justified its decision that no retail sale occurs when a generator self-supplies station power over a monthly netting period. In its remand order, FERC reversed its prior orders relating to a generator’s self-supply of station power in the markets administered by CAISO, concluding that FERC’s jurisdiction covers only the transmission of station power and the states have exclusive jurisdiction to determine when the use of station power results in a retail sale. The remand order could impact FERC’s station power policies in all of the organized markets throughout the nation. Calpine, along with several other parties sought rehearing of FERC’s decision. On February 28, 2011, FERC denied all requests for rehearing. Calpine and several other generators filed an appeal of the FERC’s decision. If left unchanged, FERC’s remand order could result in our power plants paying more for station power service. However, we do not believe such increases will be material to us.

California 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. In implementing the law, CARB is working towards a cap-and-trade program that will commence on January 1, 2012 which will include allocation, auction, trading and other activities. However, because the first compliance obligation now begins in 2013, allowances distributed in 2012 will be used for the 2013 compliance period. Additionally, there are pending legal suits that continue to threaten implementation of the program. On March 18, 2011, a San Francisco Superior Court judge issued an order in Association of Irritated Residents, et al. v. California Air Resources Board (CARB), suspending implementation of CARB’s scoping plans for a cap-and-trade program to implement AB 32, until the scoping plan complies with portions of the California Environmental Quality Act (“CEQA”). The judge agreed with plaintiffs that CARB did not adequately consider alternatives to cap-and-trade when it established the scoping plan. The state filed an appeal of the judge’s ruling and that appeal triggered a stay of the judge’s injunction against further work on cap-and-trade. As such, CARB continues to promulgate regulations for cap-and-trade implementation which will be final later this year. Furthermore, despite the pending appeal, CARB is working to remedy the judge’s described deficiencies with regard to CEQA and will provide the judge with its additional analysis in late summer 2012.

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 classes 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 tradable renewable energy credits (“TRECs”) — 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 TRECs become more limited over the course of the implementation period.

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The adoption of a 33% RPS had been slowed by controversy over the use of TRECs for compliance with the standard. On January 13, 2011, the CPUC approved a decision authorizing the use of TRECs for compliance with its 20% RPS, but with significant restrictions. In particular, the decision limits the use of TRECs to 25% of a load serving entity’s compliance obligation. The decision also reclassifies many existing contracts for renewable energy from out-of-state resources as “unbundled” and hence counting against the TREC cap. Uncertainties remain regarding implementation of the new law including how the CPUC will progress in light of its January decision.

QFs and California State Regulation of Power

Cogeneration and certain small power production facilities are eligible to be QFs under PURPA, which provides certain exemptions and other benefits to the QF, including, in some cases, the right to sell power to utilities at the utilities’ avoided cost (“PURPA put”). In California, five of our natural gas-fired power plants are QFs affected by a recently approved CPUC settlement that has the potential to change significant aspects of policy towards these plants. Our geothermal QF power plants at the Geysers Assets sell power under RPS contracts and are not subject to this policy change.

Energy pricing under many of these QF contracts is intended to become “market based” once functioning wholesale markets exist. The California Investor Owned Utilities (“IOUs”) have argued that the launch of CAISO’s MRTU satisfies the conditions necessary to end their mandatory purchase obligation under the PURPA put and that prices from the MRTU markets should provide the basis for energy pricing under existing QF contracts. Moreover, independent of issues related to existing QFs, CARB’s scoping plan to implement AB 32 includes mandates for load serving entities to procure existing and new efficient combined heat and power sales. Stakeholders, including Calpine and other QF generators, the CPUC, and the California IOUs, engaged in lengthy settlement negotiations to resolve issues related to the PURPA put, power pricing for generators under existing QF contracts and prospective combined heat and power procurement mandates. A settlement was reached by most major parties and approved by the CPUC on December 16, 2010. The settlement establishes new power pricing options for QFs under long-term contracts, including the option to shed the QF host and efficiency obligations and become dispatchable, and specifies mechanisms for the California IOUs to procure both existing combined heat and power that is not otherwise under contract and new combined heat and power. Implementation of the QF settlement is pending the resolution of certain issues contained in the decision which are expected to be resolved in a few months. Furthermore, the settlement is likely to be appealed and will not go into effect until the appeals have run their course.

PJM Capacity Market

Certain states in the PJM market region have taken actions that could impact the PJM capacity market. Late last year, the Maryland Public Service Commission issued a draft Request for Proposals (“RFP”) for public comment for up to 1,800 MW of new generation, but it remains unclear whether, and if so when, the Commission will issue an RFP. Similarly, in New Jersey, legislation enacted earlier this year required the New Jersey Board of Public Utilities (“BPU”) to solicit interest in 2,000 MW of new generation. Market participants and others were concerned that either or both of these efforts could result in the award of long term contracts that could impact the clearing prices of future PJM capacity auctions. The BPU subsequently held an RFP and awarded contracts for approximately 2,000 MW to three prospective project developers. We believe that none of the project developers intended to bid into the 2012 annual PJM capacity auction. Moreover, on April 12, 2011, FERC issued an order that is intended to limit or eliminate the impact these state actions will have on capacity auction prices. 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.

Texas Disgorgement Bill

On June 17, 2011, Texas Governor Rick Perry signed House Bill 2133 into law effective September 1, 2011. Under this law, for a violation of market power abuse under the Utilities Code, the PUCT is now required to order disgorgement of all revenue in excess of revenue that would have occurred absent a violation. Disgorgement is in addition to any penalty the PUCT may assess. For any other violation of statutes, rules or protocols relating to wholesale electric markets, the PUCT has the discretion to order disgorgement of excess revenue resulting from a violation. The PUCT and an alleged violator can develop and enter into a voluntary mitigation plan relating to a violation. Adherence to the plan would constitute an absolute defense against an alleged violation with respect to activities covered by the plan. This law applies only to violations occurring on or after September 1, 2011.

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 will impact Greenfield LP in future years. Greenfield LP’s power supply contract with the Ontario Power Authority 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.

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Results of Operations for the Three Months Ended June 30, 2011 and 2010

Below are the results of operations for the three months ended June 30, 2011, as compared to the same period in 2010 (in millions, except for percentages and operating performance metrics). Our 2011 results of operations and performance metrics also include our results from the assets we acquired from Conectiv on July 1, 2010, with no similar amounts included in our results of operations for the three months ended June 30, 2010. 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.

	2011			2010			$ Change			% Change
Operating revenues:
Commodity revenue	$	1,570		$	1,379		$	191			14
Mark-to-market activity(1)		60			32			28			88
Other revenue		3			19			(16	)		(84	)
Operating revenues		1,633			1,430			203			14
Operating expenses:
Fuel and purchased energy expense:
Commodity expense		966			841			(125	)		(15	)
Mark-to-market activity(1)		34			63			29			46
Fuel and purchased energy expense		1,000			904			(96	)		(11	)
Plant operating expense		261			213			(48	)		(23	)
Depreciation and amortization expense		131			135			4			3
Sales, general and other administrative expense		34			50			16			32
Other operating expenses(2)		22			26			4			15
Total operating expenses		1,448			1,328			(120	)		(9	)
(Income) loss from unconsolidated investments in power plants		2			(6	)		(8	)		#
Income from operations		183			108			75			69
Interest expense		192			224			32			14
(Gain) loss on interest rate derivatives, net		37			(8	)		(45	)		#
Interest (income)		(2	)		(4	)		(2	)		(50	)
Debt extinguishment costs		5			7			2			29
Other (income) expense, net		3			1			(2	)		#
Loss before income taxes and discontinued operations		(52	)		(112	)		60			54
Income tax expense		18			6			(12	)		#
Loss before discontinued operations		(70	)		(118	)		48			41
Discontinued operations, net of tax expense		—			4			(4	)		#
Net loss		(70	)		(114	)		44			39
Net income attributable to the noncontrolling interest		—			(1	)		1			#
Net loss attributable to Calpine	$	(70	)	$	(115	)	$	45			39

	2011			2010			Change			% Change
Operating Performance Metrics:
MWh generated (in thousands)(3)		19,394			19,246			148			1
Average availability		84.8	%		87.7	%		(2.9	)		(3	)
Average total MW in operation(3)		27,314			23,057			4,257			18
Average capacity factor, excluding peakers		37.6	%		42.5	%		(4.9	)		(12	)
Steam Adjusted Heat Rate		7,451			7,306			(145	)		(2	)

_________

# Variance of 100% or greater.

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

(2) Includes $2 million and $5 million of RGGI compliance and other environmental costs for the three months ended June 30, 2011 and 2010, respectively, which are components of Commodity Margin.

(3) Represents generation and capacity from power plants that we both consolidate and operate and excludes Greenfield LP, Whitby, Freeport Energy Center and 21.5% of Hidalgo Energy Center for both the three months ended June 30, 2011 and 2010. Excludes 25% of Freestone Energy Center for the three months ended June 30, 2011.

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We evaluate our commodity revenue and commodity expense on a collective basis because the price of power and natural gas 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 under “Commodity Margin and Adjusted EBITDA.”

Commodity revenue, net of commodity expense, increased $66 million for the three months ended June 30, 2011 compared to the same period in 2010, primarily due to:

• an increase in the North primarily due to the Conectiv Acquisition which closed on July 1, 2010; partially offset by

• a decrease of $10 million in REC revenue relating to the timing of revenue recognized during the second quarter of 2010 associated with the receipt of CPUC approval, weaker price conditions in the West resulting from an increase in hydroelectric generation in California and an increase in unscheduled outages in the Southeast and West in the second quarter of 2011 compared to 2010.

Our average total MW in operation increased by 4,257 MW, or 18%, primarily due to the Conectiv Acquisition which closed on July 1, 2010 partially offset by the sale of a 25% undivided interest in the assets of our Freestone power plant in December 2010. Generation increased 1% as a result of higher generation in the North due to the Conectiv Acquisition partially offset by a decrease in generation due to weaker price conditions in the West and lower generation in Texas attributable to the sale of a 25% undivided interest in the assets of our Freestone power plant in December 2010. Our average capacity factor, excluding peakers decreased 12% largely due to the decrease in generation in the West resulting from the factors previously discussed.

Unrealized mark-to-market earnings from hedging our future generation and fuel needs had a favorable variance of $57 million primarily driven by the impact of a larger decrease in forward power and natural gas prices during the three months ended June 30, 2011 compared to the three months ended June 30, 2010 that resulted in higher unrealized gains on our short power and natural gas hedge position that did not qualify for hedge accounting.

Other revenue decreased for the three months ended June 30, 2011, compared to the same period in 2010 due primarily to higher revenue recognized in the second quarter of 2010 which included a $16 million adjustment related to prior periods on a major maintenance contract.

Plant operating expense increased for the three months ended June 30, 2011 compared to the same period in 2010 due primarily to an increase of $19 million related to our Mid-Atlantic assets acquired in the Conectiv Acquisition, an increase of $30 million in major maintenance expense resulting from our plant outage schedule, a $5 million increase in costs from scrap parts related to outages, a $1 million increase in stock-based compensation expense and $1 million in costs related to our voluntary departure incentive program which was initiated in the second quarter of 2011. Our normal, recurring plant operating expense related to our legacy power plants decreased $8 million for the three months ended June 30, 2011 compared to the same period in 2010.

Depreciation and amortization expense decreased for the three months ended June 30, 2011 compared to the same period in 2010, primarily resulting from a decrease of $7 million in the second quarter of 2011 related to a revision in the expected settlement dates of the asset retirement obligations for our power plants, a decrease of $9 million due to assets being fully depreciated primarily at Broad River and a decrease of $1 million due to the sale of a 25% undivided interest in the assets of our Freestone power plant in December 2010. The decrease was partially offset by an increase of $12 million related to our Mid-Atlantic assets acquired in the Conectiv Acquisition.

Sales, general and other administrative expense decreased for the three months ended June 30, 2011 compared to the same period in 2010, primarily resulting from $19 million in Conectiv acquisition-related costs incurred during the second quarter of 2010.

Other operating expenses decreased for the three months ended June 30, 2011 compared to the same period in 2010, resulting from a decrease of $2 million in operating lease expense due to our purchase from a third party of the entity that held the lease for our South Point power plant in December 2010. In addition, there was a $1 million decrease in royalty expense due to lower revenues from our Geysers Assets resulting from lower power prices in the second quarter of 2011 compared to 2010.

(Income) loss from unconsolidated investments in power plants had an unfavorable variance for the three months ended June 30, 2011 compared to the same period in 2010 primarily due to a $7 million decrease related to Greenfield LP due to outages during the second quarter of 2011.

Interest expense decreased for the three months ended June 30, 2011 compared to the same period in 2010, primarily due to a $30 million favorable change in unrealized mark-to-market activity related to the interest rate swaps hedging our variable rate debt that do not qualify for hedge accounting and a $3 million decrease due to repayment of our Commodity Collateral Revolver in July 2010. Also contributing to the favorable period over period change in interest expense was a decrease in our annualized effective

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interest rate on our consolidated debt, excluding the impacts of capitalized interest and unrealized gains (losses) on interest rate swaps, which decreased to 7.6% for the three months ended June 30, 2011 from 8.3% for the same period in 2010.

(Gain) loss on interest rate derivatives, net had an unfavorable change of $45 million for the three months ended June 30, 2011 compared to the same period in 2010. The period over period change was related to an increase of $17 million due to interest rate swap breakage costs related to the repayment of project debt in June 2011. Also contributing to the unfavorable period over period change were changes in fair value and settlements subsequent to the reclassification date of the interest rate swaps formerly hedging our First Lien Credit Facility term loans for the three months ended June 30, 2011 compared to the same period in 2010. See Note 7 of the Notes to Consolidated Condensed Financial Statements for further discussion of our interest rate swaps formerly hedging our First Lien Credit Facility and other project debt.

Debt extinguishment costs for the three months ended June 30, 2011 consisted of $5 million related to the write-off of unamortized deferred financing costs related to the repayment of project debt in June 2011. See Note 5 of the Notes to Consolidated Condensed Financial Statements for further information regarding the issuance of our New Term Loan. Debt extinguishment costs for the three months ended June 30, 2010 consisted of $7 million related to the write-off of unamortized deferred financing costs associated with the repayment of term loans under the First Lien Credit Facility in May 2010.

During the three months ended June 30, 2011, we recorded income tax expense of $18 million compared to $6 million for the three months ended June 30, 2010. The period over period change primarily resulted from an increase of $49 million related to the application of intraperiod tax allocation partially offset by a decrease in federal income tax of $20 million and various state and foreign jurisdiction income taxes of $16 million.

Income from discontinued operations for the three months ended June 30, 2010 consists of the results of operations for Blue Spruce and Rocky Mountain which were sold in December 2010. See Note 2 of the Notes to Consolidated Condensed Financial Statements for further discussion of our discontinued operations.

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Results of Operations for the Six Months Ended June 30, 2011 and 2010

Below are the results of operations for the six months ended June 30, 2011, as compared to the same period in 2010 (in millions, except for percentages and operating performance metrics). Our 2011 results of operations and performance metrics also include our results from the assets we acquired from Conectiv on July 1, 2010, with no similar amounts included in our results of operations for the six months ended June 30, 2010. 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.

	2011			2010			$ Change			% Change
Operating revenues
Commodity revenue	$	3,090		$	2,929		$	161			5
Mark-to-market activity(1)		35			(7	)		42			#
Other revenue		7			22			(15	)		(68	)
Operating revenues		3,132			2,944			188			6
Operating expenses:
Fuel and purchased energy expense:
Commodity expense		1,995			1,961			(34	)		(2	)
Mark-to-market activity(1)		74			(88	)		(162	)		#
Fuel and purchased energy expense		2,069			1,873			(196	)		(10	)
Plant operating expense		499			431			(68	)		(16	)
Depreciation and amortization expense		262			271			9			3
Sales, general and other administrative expense		66			72			6			8
Other operating expenses(2)		42			52			10			19
Total operating expenses		2,938			2,699			(239	)		(9	)
(Income) from unconsolidated investments in power plants		(7	)		(13	)		(6	)		(46	)
Income from operations		201			258			(57	)		(22	)
Interest expense		383			405			22			5
(Gain) loss on interest rate derivatives, net		146			3			(143	)		#
Interest (income)		(5	)		(6	)		(1	)		(17	)
Debt extinguishment costs		98			7			(91	)		#
Other (income) expense, net		10			6			(4	)		(67	)
Loss before income taxes and discontinued operations		(431	)		(157	)		(274	)		#
Income tax expense (benefit)		(65	)		17			82			#
Loss before discontinued operations		(366	)		(174	)		(192	)		#
Discontinued operations, net of tax expense		—			12			(12	)		#
Net loss		(366	)		(162	)		(204	)		#
Net income attributable to the noncontrolling interest		(1	)		—			(1	)		—
Net loss attributable to Calpine	$	(367	)	$	(162	)	$	(205	)		#

	2011			2010			Change			% Change
Operating Performance Metrics:
MWh generated (in thousands)(3)		37,521			39,604			(2,083	)		(5	)
Average availability		86.8	%		89.0	%		(2.2	)		(2	)
Average total MW in operation(3)		27,110			23,069			4,041			18
Average capacity factor, excluding peakers		37.2	%		44.3	%		(7.1	)		(16	)
Steam Adjusted Heat Rate		7,411			7,266			(145	)		(2	)

_________

# Variance of 100% or greater.

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

(2) Includes $4 million and $5 million of RGGI compliance and other environmental costs for the six months ended June 30, 2011 and 2010, respectively, which are components of Commodity Margin.

(3) Represents generation and capacity from power plants that we both consolidate and operate and excludes Greenfield LP, Whitby, Freeport Energy Center and 21.5% of Hidalgo Energy Center for both the six months ended June 30, 2011 and 2010. Excludes 25% of Freestone Energy Center for the six months ended June 30, 2011.

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We evaluate our commodity revenue and commodity expense on a collective basis because the price of power and natural gas 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 under “Commodity Margin and Adjusted EBITDA.”

Commodity revenue, net of commodity expense, increased $127 million for the six months ended June 30, 2011 compared to the same period in 2010, primarily due to:

• an increase in the North primarily due to the Conectiv Acquisition which closed on July 1, 2010; partially offset by

• the negative impact in Texas of unplanned outages at some of our power plants caused by an extreme cold weather event in early February 2011 that required us to purchase physical replacement power at prices substantially above our hedged price.

Our average total MW in operation increased by 4,041 MW, or 18%, primarily due to the Conectiv Acquisition which closed on July 1, 2010 partially offset by the sale of a 25% undivided interest in the assets of our Freestone power plant in December 2010. Generation decreased 5% due primarily to weaker price conditions in the West and lower generation in Texas caused by an increase in scheduled outages and the sale of a 25% undivided interest in the assets of our Freestone power plant in December 2010. The decrease in generation was partially offset by higher generation in the North due to the Conectiv Acquisition. Our average capacity factor, excluding peakers decreased 16% largely due to the decrease in generation in the West and Texas resulting from the factors previously discussed.

Unrealized mark-to-market earnings from hedging our future generation and fuel needs had an unfavorable variance of $120 million primarily driven by the impact of a decrease in forward natural gas prices during the six months ended June 30, 2010 with no similar decrease in forward natural gas prices during the six months ended June 30, 2011 that resulted in $88 million of unrealized gains on our short natural gas hedge position that did not qualify for hedge accounting in the first half of 2010.

Other revenue decreased for the six months ended June 30, 2011, compared to the same period in 2010 due primarily to higher revenue recognized in the second quarter of 2010 which included a $15 million adjustment related to prior periods on a major maintenance contract.

Plant operating expense increased for the six months ended June 30, 2011 compared to the same period in 2010 due primarily to an increase of $38 million related to our Mid-Atlantic assets acquired in the Conectiv Acquisition, an increase of $32 million in major maintenance expense resulting from our plant outage schedule, a $4 million increase in costs from scrap parts related to outages, a $2 million increase in stock-based compensation expense, a $2 million increase in costs related to unscheduled outages and $1 million in costs related to our voluntary departure incentive program which was initiated in the second quarter of 2011. Our normal, recurring plant operating expense related to our legacy power plants decreased $11 million for the six months ended June 30, 2011 compared to the same period in 2010.

Depreciation and amortization expense decreased for the six months ended June 30, 2011 compared to the same period in 2010, primarily resulting from a decrease of $17 million in the first half of 2011 related to a revision in the expected settlement dates of the asset retirement obligations for our power plants, a decrease of $15 million due to assets being fully depreciated primarily at Broad River, a decrease of $4 million in depreciation for rotable parts and a decrease of $3 million due to the sale of a 25% undivided interest in the assets of our Freestone power plant in December 2010. The decrease was partially offset by an increase of $29 million related to our Mid-Atlantic assets acquired in the Conectiv Acquisition.

Sales, general and other administrative expense decreased for the six months ended June 30, 2011 compared to the same period in 2010, primarily resulting from $19 million in Conectiv acquisition-related costs incurred during the second quarter of 2010. The decrease was partially offset by an increase of $10 million due to the reversal of a bad debt allowance in the first quarter of 2010 as a result of Lyondell Chemical Co.’s emergence from Chapter 11 bankruptcy and the bankruptcy court’s acceptance of our claim in the first quarter of 2010.

Other operating expenses decreased for the six months ended June 30, 2011 compared to the same period in 2010, resulting from a decrease of $5 million in operating lease expense due to our purchase from a third party of the entity that held the lease for our South Point power plant in December 2010, a decrease of $2 million in royalty expense due to lower revenues from our Geysers Assets resulting from lower power prices in the first half of 2011 compared to 2010 and a decrease of $1 million in RGGI compliance and other environmental costs.

Income from unconsolidated investments in power plants decreased for the six months ended June 30, 2011 compared to the same period in 2010 primarily due to a $6 million decrease related to Greenfield LP due to outages during the second quarter of 2011.

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Interest expense decreased for the six months ended June 30, 2011 compared to the same period in 2010, primarily due to a $36 million favorable change in unrealized mark-to-market activity related to the interest rate swaps hedging our variable rate debt that do not qualify for hedge accounting, a decrease of $9 million due primarily to higher capitalized interest in the first half of 2011 compared to 2010 resulting from an increase in construction projects and a decrease of $14 million due to the repayment of our Commodity Collateral Revolver in July 2010 and project debt in December 2010. Also contributing to the favorable period over period change in interest expense was a decrease in our annualized effective interest rate on our consolidated debt, excluding the impacts of capitalized interest and unrealized gains (losses) on interest rate swaps, which decreased to 7.8% for the six months ended June 30, 2011 from 8.1% for the same period in 2010. The decrease was partially offset by an increase of $38 million in interest expense related to the NDH Project Debt which was repaid in March 2011 with proceeds received from the Term Loan.

(Gain) loss on interest rate derivatives, net had an unfavorable change of $143 million for the six months ended June 30, 2011 compared to the same period in 2010 due to the reclassification of approximately $91 million in historical unrealized losses during the first quarter of 2011 previously deferred in AOCI related to interest rate swaps formerly hedging our First Lien Credit Facility term loans. Also contributing to the unfavorable period over period change was an increase of $17 million resulting from interest rate swap breakage costs related to the repayment of project debt in June 2011 and changes in fair value and settlements subsequent to the reclassification date of the interest rate swaps formerly hedging our First Lien Credit Facility term loans for the six months ended June 30, 2011 compared to the same period in 2010. See Note 7 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 six months ended June 30, 2011 consisted of $74 million associated with the repayment of the NDH Project Debt in March 2011, $19 million associated with the retirement of the First Lien Credit Facility term loans in January 2011 in connection with the issuance of the 2023 First Lien Notes and $5 million related to the write-off of unamortized deferred financing costs related to the repayment of project debt in June 2011. See Note 5 of the Notes to Consolidated Condensed Financial Statements for further information regarding the issuance of the 2023 First Lien Notes, the repayment of the NDH Project Debt and the repayment of other project debt. Debt extinguishment costs for the six months ended June 30, 2010 consisted of $7 million related to the write-off of unamortized deferred financing costs associated with the repayment of the term loans under the First Lien Credit Facility in May 2010.

During the six months ended June 30, 2011, we recorded an income tax benefit of $65 million compared to income tax expense of $17 million for the six months ended June 30, 2010. The period over period change primarily resulted from a decrease in federal income tax of $94 million due primarily from a one-time $76 million benefit to reduce our valuation allowance due to the election to consolidate the CCFC group with the Calpine group for 2011 for federal income tax reporting purposes. See Note 9 of the Notes to Consolidated Condensed Financial Statements for further discussion of the election to consolidate the CCFC group and the Calpine group for federal tax reporting purposes. The overall period over period change was partially offset by an increase in various state and foreign jurisdiction income taxes of $12 million for the six months ended June 30, 2011 compared to the six months ended June 30, 2010.

Income from discontinued operations for the six months ended June 30, 2010 consists of the results of operations for Blue Spruce and Rocky Mountain which were sold in December 2010. See Note 2 of the Notes to Consolidated Condensed Financial Statements for further discussion of our discontinued operations.

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Commodity Margin and Adjusted EBITDA

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

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

Commodity Margin by Segment for the Three Months Ended June 30, 2011 and 2010

The following tables show our Commodity Margin and related operating performance metrics by segment for the three months ended June 30, 2011 and 2010. Our Commodity Margin and performance metrics for the three months ended June 30, 2011 reported below for our North segment include our results from the assets we acquired in the Conectiv Acquisition with no similar amounts for the three months ended June 30, 2010. In the comparative tables below, favorable variances are shown without brackets while unfavorable variances are shown with brackets.

West:	2011			2010			Change			% Change
Commodity Margin (in millions)	$	236		$	258		$	(22	)		(9	)
Commodity Margin per MWh generated	$	68.33		$	47.04		$	21.29			45
MWh generated (in thousands)		3,454			5,485			(2,031	)		(37	)
Average availability		75.9	%		88.4	%		(12.5	)		(14	)
Average total MW in operation		6,888			6,904			(16	)		—
Average capacity factor, excluding peakers		25.3	%		40.2	%		(14.9	)		(37	)
Steam Adjusted Heat Rate		7,755			7,359			(396	)		(5	)

West — Commodity Margin in our West segment decreased by $22 million, or 9%, for the three months ended June 30, 2011 compared to the same period in 2010, resulting from a decrease of $10 million in REC revenue relating to the timing of revenue recognized during the second quarter of 2010 associated with the receipt of CPUC approval. In addition, Commodity Margin decreased due to lower Market Heat Rates on our off-peak open position resulting from an increase in hydroelectric generation in California which is forecast to be significantly higher in 2011 compared to 2010, and from an unscheduled outage at OMEC during the second quarter of 2011. The decrease was partially offset by higher average hedge prices for the second quarter of 2011 compared to 2010. Consistent with weaker price conditions, generation decreased 37% for the three months ended June 30, 2011 compared to 2010. Average availability decreased by 14% due to an increase in the duration of outages during the second quarter of 2011 compared to 2010, as the weaker price environment provided an opportunity to extend the duration of scheduled maintenance outages due to limited opportunity costs. Our Steam Adjusted Heat Rate in the West decreased 5% due to an unscheduled outage on a steam turbine at OMEC during the second quarter of 2011 which caused the remaining turbine to run simple-cycle during the outage.

Texas:	2011			2010			Change			% Change
Commodity Margin (in millions)	$	128		$	128		$	—			—
Commodity Margin per MWh generated	$	16.27		$	15.53		$	0.74			5
MWh generated (in thousands)		7,867			8,243			(376	)		(5	)
Average availability		89.1	%		88.4	%		0.7			1
Average total MW in operation		6,984			7,197			(213	)		(3	)
Average capacity factor, excluding peakers		51.6	%		52.4	%		(0.8	)		(2	)
Steam Adjusted Heat Rate		7,204			7,222			18			—

Texas — Commodity Margin in our Texas segment was comparable for the three months ended June 30, 2011 compared to the same period in 2010. During the second quarter of 2011, we realized higher average hedge prices and higher Market Heat Rates on our open position which was largely offset by lower Commodity Margin due to the sale of a 25% undivided interest in the assets of

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our Freestone power plant in December 2010. Generation decreased 5% which was primarily attributable to the sale of a 25% undivided interest in the assets of our Freestone power plant in December 2010, which also drove a 213 MW, or 3% decrease in our average total MW in operation.

North:	2011			2010			Change			% Change
Commodity Margin (in millions)	$	179		$	79		$	100			#
Commodity Margin per MWh generated	$	47.27		$	60.96		$	(13.69	)		(22	)
MWh generated (in thousands)		3,787			1,296			2,491			#
Average availability		88.4	%		85.4	%		3.0			4
Average total MW in operation		7,359			2,873			4,486			#
Average capacity factor, excluding peakers		34.6	%		31.3	%		3.3			11
Steam Adjusted Heat Rate		7,985			7,648			(337	)		(4	)

North — Commodity Margin in our North segment increased by $100 million primarily due to the Conectiv Acquisition which closed on July 1, 2010 and was also the primary driver of the period over period increase in generation as well as the 4,486 MW increase in average total MW in operation in the second quarter of 2011 compared to the same period in 2010. Commodity Margin among our legacy power plants was comparable for the three months ended June 30, 2011 compared to the three months ended June 30, 2010.

Southeast:	2011			2010			Change			% Change
Commodity Margin (in millions)	$	59		$	68		$	(9	)		(13	)
Commodity Margin per MWh generated	$	13.77		$	16.11		$	(2.34	)		(15	)
MWh generated (in thousands)		4,286			4,222			64			2
Average availability		85.3	%		87.1	%		(1.8	)		(2	)
Average total MW in operation		6,083			6,083			—			—
Average capacity factor, excluding peakers		36.0	%		35.3	%		0.7			2
Steam Adjusted Heat Rate		7,322			7,319			(3	)		—

Southeast — Commodity Margin in our Southeast segment decreased by $9 million, or 13%, for the three months ended June 30, 2011 compared to the same period in 2010 largely due to the expiration of certain hedge contracts which benefited the second quarter of 2010 as well as lower Commodity Margin that resulted from unscheduled outages that occurred during the second quarter of 2011. Generation increased 2% largely driven by higher generation at power plants contracted and dispatched by third parties during the second quarter of 2011 compared to the second quarter of 2010.

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Commodity Margin by Segment for the Six Months Ended June 30, 2011 and 2010

The following tables show our Commodity Margin and related operating performance metrics by segment for the six months ended June 30, 2011 and 2010. Our Commodity Margin and performance metrics for the six months ended June 30, 2011 reported below for our North segment include our results from the assets we acquired in the Conectiv Acquisition with no similar amounts for the six months ended June 30, 2010. In the comparative tables below, favorable variances are shown without brackets while unfavorable variances are shown with brackets.

West:	2011			2010			Change			% Change
Commodity Margin (in millions)	$	469		$	471		$	(2	)		—
Commodity Margin per MWh generated	$	48.61		$	32.04		$	16.57			52
MWh generated (in thousands)		9,649			14,702			(5,053	)		(34	)
Average availability		83.9	%		90.8	%		(6.9	)		(8	)
Average total MW in operation		6,887			6,936			(49	)		(1	)
Average capacity factor, excluding peakers		35.7	%		54.2	%		(18.5	)		(34	)
Steam Adjusted Heat Rate		7,495			7,298			(197	)		(3	)

West — Commodity Margin in our West segment was comparable for the six months ended June 30, 2011 compared to the same period in 2010. During the first half of 2011, we experienced higher average hedge prices as well as the positive impact on the first half of 2011 of origination activities. The increase was partially offset by lower Market Heat Rates on our open position resulting from an increase in hydroelectric generation in California which is forecast to be significantly higher in 2011 compared to 2010, and lower Commodity Margin resulting from an unscheduled outage at OMEC during the second quarter of 2011. Consistent with weaker price conditions, generation decreased 34% for the six months ended June 30, 2011 compared to 2010. Average availability decreased by 8% due to an increase in the duration of outages during the second quarter of 2011 compared to 2010, as the weaker price environment provided an opportunity to extend the duration of scheduled maintenance outages due to limited opportunity costs. Our average total MW in operation decreased 49 MW, or 1%, due to the retirement of our Pittsburg power plant in March 2010 as well as the expiration of our operating lease and subsequent retirement of our Watsonville (Monterey) cogeneration power plant in May 2010.

Texas:	2011			2010			Change			% Change
Commodity Margin (in millions)	$	195		$	235		$	(40	)		(17	)
Commodity Margin per MWh generated	$	14.79		$	15.79		$	(1.00	)		(6	)
MWh generated (in thousands)		13,186			14,885			(1,699	)		(11	)
Average availability		84.3	%		85.5	%		(1.2	)		(1	)
Average total MW in operation		6,973			7,177			(204	)		(3	)
Average capacity factor, excluding peakers		43.5	%		47.8	%		(4.3	)		(9	)
Steam Adjusted Heat Rate		7,224			7,169			(55	)		(1	)

Texas — Commodity Margin in our Texas segment decreased by $40 million, or 17%, for the six months ended June 30, 2011 compared to the same period in 2010. Despite an increase in average hedge prices, Commodity Margin was negatively impacted by unplanned outages at some of our power plants caused by an extreme cold weather event which occurred on February 2, 2011. Power prices increased dramatically as a result of the cold weather event and the plant outages, which required us to purchase physical replacement power at prices substantially above our hedged prices. Lower average availability in the first quarter of 2011, influenced by higher scheduled outages, as well as the sale of a 25% undivided interest in the assets of our Freestone power plant in December 2010, also contributed to the period over period decrease in Commodity Margin. Generation decreased 11% which was attributable to higher period over period outages as well as the sale of a 25% undivided interest in the assets of our Freestone power plant in December 2010, which also drove a 204 MW, or 3% decrease in our average total MW in operation. Average capacity factor decreased 9% due primarily to dispatch changes under ERCOT’s new nodal market and higher period over period scheduled outages.

North:	2011			2010			Change			% Change
Commodity Margin (in millions)	$	314		$	131		$	183			#
Commodity Margin per MWh generated	$	51.35		$	55.27		$	(3.92	)		(7	)
MWh generated (in thousands)		6,115			2,370			3,745			#
Average availability		89.7	%		88.9	%		0.8			1
Average total MW in operation		7,167			2,873			4,294			#
Average capacity factor, excluding peakers		29.6	%		28.8	%		0.8			3
Steam Adjusted Heat Rate		7,888			7,613			(275	)		(4	)

North — Commodity Margin in our North segment increased by $183 million primarily due to the Conectiv Acquisition which closed on July 1, 2010 and was also the primary driver of the period over period increase in generation as well as the 4,294 MW

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increase in average total MW in operation in the first half of 2011 compared to the same period in 2010. The increase in Commodity Margin also resulted from higher realized Spark Spreads on open positions among our legacy power plants driven by an increase in Market Heat Rates, and higher average hedge prices for the six months ended June 30, 2011 compared to the six months ended June 30, 2010.

Southeast:	2011			2010			Change			% Change
Commodity Margin (in millions)	$	113		$	126		$	(13	)		(10	)
Commodity Margin per MWh generated	$	13.18		$	16.48		$	(3.30	)		(20	)
MWh generated (in thousands)		8,571			7,647			924			12
Average availability		89.8	%		91.4	%		(1.6	)		(2	)
Average total MW in operation		6,083			6,083			—			—
Average capacity factor, excluding peakers		37.0	%		32.8	%		4.2			13
Steam Adjusted Heat Rate		7,310			7,305			(5	)		—

Southeast — Commodity Margin in our Southeast segment decreased by $13 million, or 10%, for the six months ended June 30, 2011 compared to the same period in 2010 largely due to the expiration of certain hedge contracts which benefited the first half of 2010 as well as lower Commodity Margin that resulted from unscheduled outages that occurred during the second quarter of 2011. Generation increased 12% largely driven by higher generation at power plants contracted and dispatched by third parties during the first half of 2011 compared to the first half of 2010.

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Adjusted EBITDA

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

	Three Months Ended June 30, 2011
	West			Texas			North		Southeast			Consolidation and Elimination			Total
Net loss attributable to Calpine															$	(70	)
Income tax expense																18
Other (income) expense and debt extinguishment costs, net																8
(Gain) loss on interest rate derivatives, net																37
Interest expense, net																190
Income (loss) from operations	$	70		$	41		$	82	$	(12	)	$	2		$	183
Add:
Adjustments to reconcile income (loss) from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs(1)		43			35			33		22			(2	)		131
Major maintenance expense		31			21			7		17			—			76
Operating lease expense		2			—			7		—			—			9
Unrealized (gain) loss on commodity derivative mark-to-market activity		(9	)		(20	)		2		1			—			(26	)
Adjustments to reflect Adjusted EBITDA from unconsolidated investments(2)		—			—			13		—			—			13
Stock-based compensation expense		2			3			—		2			—			7
Non-cash loss on dispositions of assets		1			1			1		1			—			4
Other		1			—			7		1			—			9
Total Adjusted EBITDA	$	141		$	81		$	152	$	32		$	—		$	406

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	Three Months Ended June 30, 2010
	West			Texas			North			Southeast		Consolidation and Elimination			Total
Net loss attributable to Calpine															$	(115	)
Net income attributable to noncontrolling interest																1
Discontinued operations, net of tax expense																(4	)
Income tax expense																6
Other (income) expense and debt extinguishment costs, net																8
(Gain) loss on interest rate derivatives, net																(8	)
Interest expense, net																220
Income (loss) from operations	$	107		$	(11	)	$	17		$	—	$	(5	)	$	108
Add:
Adjustments to reconcile income (loss) from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs(1)		51			40			19			28		(2	)		136
Major maintenance expense		10			24			3			6		—			43
Operating lease expense		5			—			6			—		—			11
Unrealized (gain) loss on commodity derivative mark-to-market activity		(7	)		31			(3	)		10		—			31
Adjustments to reflect Adjusted EBITDA from unconsolidated investments(2)		—			—			8			—		—			8
Stock-based compensation expense		2			3			1			—		—			6
Non-cash loss on dispositions of assets		(1	)		—			—			—		—			(1	)
Conectiv acquisition-related costs		—			—			19			—		—			19
Adjusted EBITDA from continuing operations		167			87			70			44		(7	)		361
Adjusted EBITDA from discontinued operations		20			—			—			—		—			20
Total Adjusted EBITDA	$	187		$	87		$	70		$	44	$	(7	)	$	381

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	Six Months Ended June 30, 2011
	West			Texas			North			Southeast			Consolidation and Elimination			Total
Net loss attributable to Calpine																$	(367	)
Net income attributable to noncontrolling interest																	1
Income tax benefit																	(65	)
Other (income) expense and debt extinguishment costs, net																	108
(Gain) loss on interest rate derivatives, net																	146
Interest expense, net																	378
Income (loss) from operations	$	156		$	(72	)	$	139		$	(24	)	$	2		$	201
Add:
Adjustments to reconcile income (loss) from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs(1)		88			65			66			46			(2	)		263
Major maintenance expense		38			59			13			26			—			136
Operating lease expense		4			—			13			—			—			17
Unrealized (gain) loss on commodity derivative mark-to-market activity		(11	)		45			(1	)		6			—			39
Adjustments to reflect Adjusted EBITDA from unconsolidated investments(2)		—			—			21			—			—			21
Stock-based compensation expense		5			4			1			2			—			12
Non-cash loss on dispositions of assets		2			4			1			2			—			9
Other		1			—			9			1			—			11
Total Adjusted EBITDA	$	283		$	105		$	262		$	59		$	—		$	709

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	Six Months Ended June 30, 2010
	West			Texas			North		Southeast			Consolidation and Elimination			Total
Net loss attributable to Calpine															$	(162	)
Discontinued operations, net of tax expense																(12	)
Income tax expense																17
Other (income) expense and debt extinguishment costs, net																13
(Gain) loss on interest rate derivatives, net																3
Interest expense, net																399
Income from operations	$	153		$	65		$	20	$	16		$	4		$	258
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs(1)		104			76			39		58			(4	)		273
Major maintenance expense		19			60			6		13			—			98
Operating lease expense		9			—			13		—			—			22
Unrealized (gain) loss on commodity derivative mark-to-market activity		(11	)		(61	)		1		(10	)		—			(81	)
Adjustments to reflect Adjusted EBITDA from unconsolidated investments(2)		—			—			15		—			—			15
Stock-based compensation expense		5			5			1		1			—			12
Non-cash loss on dispositions of assets		(1	)		5			—		1			—			5
Conectiv acquisition-related costs		—			—			19		—			—			19
Other		1			—			—		—			—			1
Adjusted EBITDA from continuing operations		279			150			114		79			—			622
Adjusted EBITDA from discontinued operations		41			—			—		—			—			41
Total Adjusted EBITDA	$	320		$	150		$	114	$	79		$	—		$	663

_________

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

(2) Adjustments to reflect Adjusted EBITDA from unconsolidated investments include unrealized gains (losses) on mark-to-market activity of nil for the three and six months ended June 30, 2011 and 2010.

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Liquidity and Capital Resources

Our business is capital intensive. Our ability to successfully implement our strategy is dependent on the continued availability of capital on attractive terms. In addition, our ability to successfully operate our business is dependent on maintaining sufficient liquidity. We believe that we have adequate resources from a combination of cash and cash equivalents on hand and cash expected to be generated from future operations to continue to meet our obligations as they become due.

Liquidity

At June 30, 2011, we had $1,147 million in cash and cash equivalents and $217 million of restricted cash. Amounts available for future cash borrowings were $631 million under the Corporate Revolving Facility. The following table provides a summary of our liquidity position at June 30, 2011, and December 31, 2010 (in millions):

	June 30, 2011		December 31, 2010
Cash and cash equivalents, corporate(1)	$	846	$	1,058
Cash and cash equivalents, non-corporate		301		269
Total cash and cash equivalents		1,147		1,327
Restricted cash		217		248
Revolving facility(ies) availability(2)		631		623
Letter of credit availability(3)		7		35
Total current liquidity availability	$	2,002	$	2,233

_________

(1) Includes nil and $6 million of margin deposits held by us posted by our counterparties at June 30, 2011, and December 31, 2010, respectively.

(2) On December 10, 2010, we executed our $1.0 billion Corporate Revolving Facility, which replaced our $1.0 billion revolver under our First Lien Credit Facility. At December 31, 2010, the letters of credit issued under our First Lien Credit Facility were either replaced by letters of credit issued by the Corporate Revolving Facility or back-stopped by an irrevocable standby letter of credit issued by a third party. Our letters of credit under our Corporate Revolving Facility at December 31, 2010 include those that were back-stopped of approximately $83 million. The back-stopped letters of credit were returned and extinguished during the first quarter of 2011. The balance at December 31, 2010 includes availability under the NDH Project Debt, which was retired on March 9, 2011.

(3) Includes availability under Calpine Development Holdings, Inc.

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. 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 intercompany 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 credit-worthy 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 July 15, 2011, an increase of $1/MMBtu in natural gas prices would result in an increase of collateral required by approximately $134 million. If natural gas prices decreased by $1/MMBtu, we estimate that our collateral requirements would decrease by approximately $108 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

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influenced by the absolute price of natural gas; therefore, we derived a statistical analysis that implies that a change of $1/MMBtu in natural gas approximates an average Market Heat Rate change of 300 Btu/KWh at current natural gas price levels. We estimate that at July 15, 2011, an increase of 300 Btu/KWh in the Market Heat Rate would result in an increase in collateral required by approximately $35 million. If Market Heat Rates were to fall at a similar rate, we estimate that our collateral required would decrease by $33 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 substantial portion of our generation and natural gas portfolio mostly through power and natural gas forward physical and financial transactions for 2011; 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;

• improving the efficiency and profitability of our operations;

• continued compliance with the covenants under our existing financing obligations, including our First Lien Notes, Term Loan, New Term Loan, Corporate Revolving Facility, CCFC 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 June 30, 2011, and December 31, 2010 (in millions):

	June 30, 2011		December 31, 2010
Corporate Revolving Facility(1)	$	369	$	443
Calpine Development Holdings, Inc.		193		165
NDH Project Debt credit facility(2)		—		34
Various project financing facilities		100		69
Total	$	662	$	711

_________

(1) When we entered into our $1.0 billion Corporate Revolving Facility on December 10, 2010, the letters of credit issued under our First Lien Credit Facility were either replaced with letters of credit issued by our Corporate Revolving Facility or back-stopped by an irrevocable standby letter of credit issued by a third-party. Our letters of credit under our Corporate Revolving Facility at December 31, 2010 include those that were back-stopped of approximately $83 million. The back-stopped letters of credit were returned and extinguished during the first quarter of 2011.

(2) We repaid and terminated the NDH Project Debt on March 9, 2011.

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Capital Management and Significant Financing Transactions 

In connection with our goals of enhancing shareholder value and leveraging our three scale regions, we have completed four key capital and financing transactions during the first half of 2011, as further described below. While we cannot provide any assurance that we will continue to be successful in the future, if credit and capital markets present favorable opportunities, we will continue to execute future transactions consistent with our strategy.

Issuance of the 2023 First Lien Notes and Termination of the First Lien Credit Facility

On January 14, 2011, we issued the 2023 First Lien Notes, which, together with operating cash on hand, were used to fully repay the remaining First Lien Credit Facility term loans thereby terminating the First Lien Credit Facility in accordance with its terms. See Note 5 of the Notes to Consolidated Condensed Financial Statements for further discussion of the issuance of the 2023 First Lien Notes and the termination of the First Lien Credit Facility. The issuance of the First Lien Notes, the refinancing of the First Lien Credit Facility revolver with the Corporate Revolving Facility in 2010 and the resulting termination of the First Lien Credit Facility, provide us with significant benefits. The termination of the First Lien Credit Facility eliminated the more restrictive of our debt covenants, resulting in increased operational, strategic and financial flexibility in managing our capital resources including the flexibility to reinvest more earnings for internal growth, issue and/or buyback shares of our common stock and incur additional debt, if needed for acquisition or development. Additionally, we extended the remaining contractual debt maturities under the First Lien Credit Facility of approximately $1.2 billion, due in 2014 to 2023. Under the First Lien Notes and Corporate Revolving Facility, subject in each case to the limitations contained therein and in the Collateral Agency and Intercreditor Agreement, we may:

• re-invest future earnings internally for additional growth and/or may elect to return cash to shareholders;

• issue and/or buyback additional shares of our common stock;

• incur additional first lien indebtedness up to certain consolidated net tangible asset ratios;

• incur additional subordinated or junior secured debt; and

• use corporate resources to freely invest in our subsidiaries which are not first lien guarantors.

Additionally, except as required under certain of our project debt, we are no longer subject to an excess cash flow payment calculation or cash sweeps, and we are no longer limited in the amount of capital expenditures for future growth.

Closing the Term Loan and New Term Loan and Termination of the NDH Project Debt and Other Project Debt

On March 9, 2011, we closed on the $1.3 billion Term Loan, and we used the proceeds received, together with operating cash on hand to fully retire the approximately $1.3 billion NDH Project Debt in accordance with its repayment terms. The NDH Project Debt was originally established to partially fund the Conectiv Acquisition. On June 17, 2011, we repaid approximately $340 million of project debt with the proceeds received from $360 million in borrowings under the New Term Loan. The Term Loan and New Term Loan refinancing reduces our overall cost of debt and simplifies our capital structure by bringing debt up to the corporate level from the subsidiary level, eliminating the need for subsidiary level reporting and the potential for cash to be temporarily trapped at the subsidiary level. Additionally, these transactions demonstrate our continued ability to strategically access capital markets. The Term Loan and New Term Loan contain very similar covenants, qualifications, exceptions and limitations as the First Lien Notes.

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, a 619 MW combined-cycle power plant under construction in Hayward, CA, which comprises 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 and borrowings bear interest initially at LIBOR plus 2.25%. At June 30, 2011, approximately $69 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 is 75% and the pro rata share related to the noncontrolling interest is 25%.

See also Note 5 of the Notes to Consolidated Condensed Financial Statements for further discussion of our First Lien Notes, Term Loan, New Term Loan and Russell City Project Debt.

Possible Disposition of Non-core Assets

When we believe that we may not be the best owner for a given power plant or other asset, we perform an analysis to determine whether it is more financially beneficial to divest of those assets than to retain ownership. Recently, we performed this analysis and reviewed opportunities for our Broad River and Mankato power plants. Although definitive plans for divestiture of these power plants were never made, we initiated efforts to market these assets during the second quarter of 2011. In July 2011, we concluded our marketing efforts and elected to retain these power plants.

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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. We will consider selective acquisitions or additions of new capacity supported by long-term hedging programs, including PPAs and natural gas tolling agreements, particularly where limited or non-recourse project financing is available. In addition, we believe that upgrades and expansions to our current assets offer proven and financially disciplined opportunities to improve our operations, capacity and efficiencies. Our significant projects under construction, growth initiatives and upgrades are discussed below.

York Energy Center

We acquired the York Energy Center, a 565 MW dual fuel, combined-cycle power plant under construction as part of the Conectiv Acquisition. York Energy Center achieved COD on March 2, 2011, three months early, and sells power under a six-year PPA with a third party which commenced on June 1, 2011.

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 on-going 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

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 308 MW combined-cycle generation power plant, which will also increase the efficiency and environmental performance of the power plant by lowering the Heat Rate. The PPA and related agreements with PG&E have received all of the necessary approvals and licenses, which are now effective. The California Energy Commission has renewed our license and emission limits, which is final. The Bay Area Air Quality Management District issued its renewal of the Authority to Construct. We have executed contracts for all major equipment and have selected and contracted with the engineering, procurement and construction contractor. We began construction in the second quarter of 2011 and are in the process of obtaining project financing which is expected to be completed in the third quarter of 2011. We expect COD in 2013.

Turbine Upgrades 

We continue to move forward with our turbine upgrade program. Through June 30, 2011, we have completed the upgrade of eight Siemens and five GE turbines and have agreed to upgrade approximately eight 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 Heat Rates falling in line with expectations.

Geysers Assets Expansion

We continue to look to expand our production from our Geysers Assets. Beginning in the fourth quarter of 2009, we conducted an exploratory drilling program, which effectively proved the commercial viability of the steam field in the northern part of our Geysers Assets; however, permitting challenges have emerged that we are continuing to resolve, and we expect to receive the Sonoma County permit in the second half of 2011. We were planning to target a 2013 COD for an expansion of our Geysers Assets and had been, in parallel, negotiating commercial arrangements to support that, but due to the permitting challenges we may not meet a 2013 COD. We continue to believe our northern Geysers Assets have potential for development. In the near term, we will connect the test wells to our existing power plants to capture incremental production from those wells, while continuing with the permitting process, baseline engineering work and sales efforts for an expansion.

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PJM

Given our view of the potential need for new generation in the PJM region, driven both by market growth and the expected impacts of environmental regulations on older, less efficient generation within the region, we view the PJM region as a market with an attractive growth profile. In order to capitalize on this outlook, we are actively pursuing a set of development options, including projects at:

• Edge Moor (Delaware): Feasibility study under way with PJM for the addition of 300 MW of combined-cycle capacity at our existing site, leveraging existing infrastructure;

• Garrison (Delaware): Actively permitting 309 MW of new combined-cycle capacity at a development site secured by a lease option;

• Talbert (Maryland): Existing interconnect agreement for 200 MW of new simple-cycle capacity at a development site secured by a lease option;

• Powell (Maryland): Existing interconnect agreement for 300 – 500 MW of new simple-cycle capacity at a development site that we are currently in the process of purchasing; and

• Other locations that we feel provide similar opportunity to position us for growth within the region.

Customer-Oriented Origination Business

We continue to focus on providing products and services that are beneficial to our customers.

• We have entered into a new ten-year PPA with a third party to provide 485 MW of power generated by our Carville Energy Center which will commence in June 2012.

• We continue to expand our use of seasonal contracts in the Southeast.

NOLs

We have significant NOLs that will provide future tax deductions when we generate sufficient taxable income during the applicable carryover periods. As discussed in Note 9 of the Notes to Consolidated Condensed Financial Statements, we elected to consolidate our CCFC and Calpine groups for federal income tax reporting purposes during the first quarter of 2011. As a result of the consolidation, we will be able to utilize approximately $76 million additional Calpine group NOLs against CCFC group deferred tax liabilities. At December 31, 2010, our consolidated federal NOLs totaled approximately $7.4 billion. See Note 9 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 six months ended June 30, 2011 and 2010 (in millions):

	2011			2010
Beginning cash and cash equivalents	$	1,327		$	989
Net cash provided by (used in):
Operating activities		239			170
Investing activities		(421	)		124
Financing activities		2			(312	)
Net decrease in cash and cash equivalents		(180	)		(18	)
Ending cash and cash equivalents	$	1,147		$	971

Net Cash Provided By Operating Activities

Cash flows provided by operating activities for the six months ended June 30, 2011, resulted in net inflows of $239 million compared to $170 million for the same period in 2010. The increase in cash flows from operating activities was primarily due to:

• Income from operations — Income from operations, adjusted for non-cash items increased by $55 million for the six months ended June 30, 2011, as compared to the six months ended June 30, 2010. Non-cash items consist primarily of depreciation and amortization, income from unconsolidated investments and unrealized gains and losses in mark-to-market activity.

• Interest Paid — Cash paid for interest, inclusive of interest rate swaps in hedging relationships, decreased by $70 million to $292 million for the six months ended June 30, 2011, as compared to $362 million for the six months ended June 30,

54

2010. The decrease 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.

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

• Working capital — Working capital employed increased by approximately $19 million during the period after adjusting for debt related balances which did not impact cash provided by operating activities. The increase was primarily due to a decrease in the reductions in margin requirements in the current year as compared to the same period in 2010.

• Prepayment Premiums — For the six months ended June 30, 2011, we paid $13 million of prepayment premiums related to the extinguishment of the NDH Project Debt.

Net Cash Used In Investing Activities

Cash flows used in investing activities for the six months ended June 30, 2011, were $421 million compared to cash flows provided by investing activities of $124 million for the six months ended June 30, 2010. The difference was primarily due to:

• Capital expenditures — Capital expenditures increased by approximately $244 million primarily resulting from construction activity at the Russell City Energy Center, Los Esteros Critical Energy Facility and York Energy Center combined with our turbine upgrade program.

• Settlement of non-hedging interest rate swaps — During the six months ended June 30, 2011, we made 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 $103 million compared to payments of $14 million during the six months ended 2010. Since these payments were recognized in net loss and effectively reduced our interest payable, the offset to the amount reflected in net cash provided by (used in) investing activities is included in the reconciliation of net loss to net cash provided by operating activities in the line item liabilities related to non-hedging interest rate swaps on our Consolidated Condensed Statements of Cash Flows.

• Restricted cash — The net reduction in restricted cash was $30 million for the six months ended June 30, 2011 compared to $224 million for the same period in 2010. The decrease in restricted cash in 2011 as compared to 2010 was due mainly to the maturity of project debt and the corresponding reduction in restricted cash requirements during the first quarter of 2010.

Net Cash Provided By Financing Activities

Cash flows provided by financing activities for the six months ended June 30, 2011, were $2 million compared to cash flows used in financing activities of $312 million for the same period in 2010. The increase was primarily due to:

• Issuance of First Lien Notes — During the six months ended June 30, 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 $13 million during the six months ended June 30, 2011. During the six months ended June 30, 2010, we received proceeds of approximately $400 million from the issuance of First Lien Notes and made repayments on our First Lien Credit Facility of approximately $430 million resulting in a net decrease of $30 million.

• Issuance of the Term Loan and New Term Loan — During the six months ended June 30, 2011, we received proceeds of approximately $1.7 billion from the issuance of the Term Loan and New Term Loan. We used the proceeds to repay NDH Project Debt and other project debt of approximately $1.6 billion resulting in a net increase of $34 million.

The increase was partially offset by:

• Additional finance costs — During the six months ended June 30, 2011, largely due to the refinancing of the First Lien Credit Facility and the NDH Project Debt, we incurred $67 million of financing costs compared to $15 million during the six months ended June 30, 2010.

• Higher Repayments of Project Debt — Excluding the repayment of the NDH Project Debt and other project debt noted above, during the six months ended June 30, 2011, we made scheduled payments on project debt of approximately $79 million compared to payments of approximately $277 million in the six months ended June 30, 2010.

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 Energy Center, LLC, Goose Haven

55

Energy Center, LLC, 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.

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Risk Management and Commodity Accounting

Our hedging strategy focuses first on protecting our balance sheet, given our debt obligations, our committed capital expenditures and other obligations. Secondly, our hedge efforts attempt to maximize our risk adjusted Commodity Margin by leveraging our knowledge, experience and fundamental views on natural gas and power.

We actively seek to manage and limit 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 364 MW of capacity from power plants where we purchase fuel oil to meet our generation requirements; however, we have not currently entered into any hedging or optimization transactions for fuel oil as we do not expect our fuel oil requirements to be material to us, but may elect to do so in the future.

Along with our portfolio of hedging transactions, we enter into power and natural gas positions that often act as hedges to our asset portfolio, but do not qualify as hedges under hedge accounting guidelines, such as commodity options transactions and instruments that settle on power price to natural gas price relationships (Heat Rate swaps and options). 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.

While we enter into these transactions primarily to provide us with improved price and price volatility transparency, as well as greater market access, which benefits our hedging activities, 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 either hedge accounting or the normal purchase normal sale exemption are recognized currently in earnings in mark-to-market activity 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 substantial portion of our expected generation and natural gas portfolio mostly through power and natural gas forward physical and financial transactions for 2011; 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. At June 30, 2011, the maximum length of our PPAs extends 24 years into the future and the maximum length of time over which we were hedging using commodity and interest rate derivative instruments was 2 and 15 years, respectively.

We have historically used interest rate swaps to adjust the mix between our fixed and variable rate debt. The majority of our interest rate swaps mature in years 2011 through 2012. 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 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 is presented separate from interest expense as (gain) loss on interest rate derivatives, net on our Consolidated Condensed Statement 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 swaps of approximately $91 million remaining in AOCI were reclassified out of AOCI and into income as additional (gain) loss on interest rate derivatives, net, during the first quarter of 2011. In addition, we reclassified approximately $17 million in unrealized losses in AOCI to (gain) loss on interest rate derivatives, net during the second quarter of 2011 resulting from the repayment of project debt in June 2011.

Assuming constant June 30, 2011, power and natural gas prices and interest rates, we estimate that pre-tax net gains of $45 million 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 natural gas and power prices as well as 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

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derivatives over time, driven both by price volatility and the changes in volume of open derivative transactions. Our derivative assets and (liabilities) have decreased to approximately $0.7 billion and $(0.9) billion at June 30, 2011, compared to $0.9 billion and $(1.1) billion at December 31, 2010, respectively. At June 30, 2011, 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 6 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, 2011, through June 30, 2011, is summarized in the table below (in millions):

	Interest Rate Swaps			Commodity Instruments			Total
Fair value of contracts outstanding at January 1, 2011	$	(367	)	$	174		$	(193	)
Items recognized or otherwise settled during the period(1)(2)		117			(133	)		(16	)
Fair value attributable to new contracts		—			3			3
Changes in fair value attributable to price movements		(49	)		84			35
Change in fair value attributable to nonperformance risk		(14	)		—			(14	)
Fair value of contracts outstanding at June 30, 2011(3)	$	(313	)	$	128		$	(185	)

_________

(1) Interest rate settlements consist of recognized losses from former interest rate cash flow hedges of $18 million that were de-designated as a result of the repayment of project debt in June 2011, $33 million related to recognition of losses from settlements of designated cash flow hedges, and $66 million in losses from settlements of undesignated interest rate swaps (represents a portion of interest expense and (gain) loss on interest rate derivatives, net as reported on our Consolidated Condensed Statements of Operations).

(2) Gains on settlement of commodity contracts not designated as hedging instruments of $104 million (represents a portion of operating revenues and fuel and purchased energy expense as reported on our Consolidated Condensed Statements of Operations) and $29 million related to recognition of gains from cash flow hedges, previously reflected in OCI, partially offset by other changes in derivative assets and liabilities not reflected in OCI or net income.

(3) Net commodity and interest rate derivative assets and liabilities reported in Notes 6 and 7 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 current 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 not designated as hedging instruments and where these components were recorded on our Consolidated Condensed Statements of Operations for the periods indicated (in millions):

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Realized gain (loss)
Interest rate swaps	$	(60	)	$	(6	)	$	(106	)	$	(12	)
Commodity derivative instruments		42			59			52			52
Total realized gain (loss)	$	(18	)	$	53		$	(54	)	$	40
Unrealized gain (loss) (1)
Interest rate swaps	$	24		$	(16	)	$	(38	)	$	(19	)
Commodity derivative instruments		26			(31	)		(39	)		81
Total unrealized gain (loss)	$	50		$	(47	)	$	(77	)	$	62
Total mark-to-market activity	$	32		$	6		$	(131	)	$	102

_________

(1) Changes in unrealized gain (loss) include 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.

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	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Realized and unrealized gain (loss)
Power contracts included in operating revenues	$	48		$	41		$	(9	)	$	12
Natural gas contracts included in fuel and purchased energy expense		20			(13	)		22			121
Interest rate swaps included in interest expense		1			(30	)		2			(28	)
Gain (loss) on interest rate derivatives, net		(37	)		8			(146	)		(3	)
Total mark-to-market activity	$	32		$	6		$	(131	)	$	102

Our change in AOCI from an accumulated loss of $125 million at December 31, 2010, to an accumulated loss of $83 million at June 30, 2011 was primarily driven by the reclassification adjustment of $91 million for cash flow hedges formerly hedging our First Lien Credit Facility term loans realized in net income plus additional interest rate swap settlements partially offset by the effect of income taxes, which includes a net $16 million increase to tax expense in OCI with an offsetting benefit to continuing operations related to the intraperiod tax allocation provisions under U.S. GAAP.

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

The net fair value of outstanding derivative commodity instruments at June 30, 2011, based on price source and the period during which the instruments will mature, are summarized in the table below (in millions):

Fair Value Source:	2011			2012 - 2013		2014 - 2015		After 2015		Total
Prices actively quoted	$	58		$	5	$	—	$	—	$	63
Prices provided by other external sources		19			29		—		—		48
Prices based on models and other valuation methods		(3	)		18		2		—		17
Total fair value	$	74		$	52	$	2	$	—	$	128

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 plus the following two calendar years. We measure VAR using a variance/covariance approach based on a confidence level of 95%, a one-day holding period, and actual observed historical correlation. While we believe that our VAR assumptions and approximations are reasonable, different assumptions and/or approximations could produce materially different estimates.

The table below presents the high, low and average of our daily VAR for the three and six months ended June 30, 2011 and 2010, as well as our VAR at June 30, 2011 and 2010 (in millions):

	2011		2010
Three months ended June 30:
High	$	39	$	29
Low	$	20	$	23
Average	$	30	$	26
Six months ended June 30:
High	$	39	$	58
Low	$	20	$	23
Average	$	33	$	33
At June 30	$	21	$	24

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 the actual changes 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.

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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 8 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 believe that our credit policies and portfolio of transactions adequately monitor and diversify our credit risk. We currently have no individual significant concentrations of credit risk to a single counterparty; however, a series of defaults or events of nonperformance by several of our individual counterparties could impact our liquidity and future results of operations. We monitor and manage our total comprehensive credit risk associated with all of our contracts and PPAs irrespective of whether they are accounted for as an executory contract, a normal purchase normal sale or whether they are marked-to-market and included in our derivative assets and liabilities on our Consolidated Condensed Balance Sheets. Our counterparty credit quality associated with the net fair value of outstanding derivative commodity instruments is included in our derivative assets and liabilities at June 30, 2011, 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 at June 30, 2011
	2011			2012 - 2013			2014 - 2015		After 2015		Total
Investment grade	$	78		$	54		$	2	$	—	$	134
Non-investment grade		—			1			—		—		1
No external ratings		(4	)		(3	)		—		—		(7	)
Total fair value	$	74		$	52		$	2	$	—	$	128

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 high quality institutions and 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 formerly hedging our First Lien Credit Facility of approximately $(3) million, and would result in a change in the fair value of our interest rate swaps hedging our other variable rate debt of approximately $(13) million at June 30, 2011.

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.

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Item 3.  Quantitative and Qualitative Disclosures About Market Risk

See “Risk Management and Commodity Accounting” in Item 2.

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 our 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 and 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 principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

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) during the second quarter of fiscal 2011 that materially affected, or are reasonably likely to materially affect our internal control over financial reporting.

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PART II — OTHER INFORMATION

Item 1.  Legal Proceedings

See Note 12 of the Notes to Consolidated Condensed Financial Statements for a description of our legal proceedings.

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

Repurchase of Equity Securities — 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 make tax withholding payments in cash. As set forth in the table below, during the second quarter of 2011, we withheld a total of 7,445 shares in the indicated months that are included in treasury stock. These were the only repurchases of equity securities made by us during this period. We do not have a stock repurchase program.

	(a) Total Number of Shares Purchased		(b) Average Price Paid Per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		(d) Maximum Number of Shares That May Yet Be Purchased Under the Plan or Programs
April		3,498	$	16.23		—		N/A
May		897	$	16.09		—		N/A
June		3,050	$	15.52		—		N/A
Total		7,445	$	15.92		—		N/A

Item 5.   Other Information

On June 17, 2011, we executed assumption agreements to the amended and restated guarantee and collateral agreement, to add Deer Park Holdings, LLC, Metcalf Holdings, LLC, Deer Park Energy Center LLC and Metcalf Energy Center, LLC as guarantors of our Corporate Revolving Facility, Term Loan and New Term Loan. On July 22, 2011, we executed supplemental indentures for the First Lien Notes to add Deer Park Holdings, LLC, Metcalf Holdings, LLC, Deer Park Energy Center LLC and Metcalf Energy Center, LLC as guarantors.

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Item 6.  Exhibits

The following exhibits are filed herewith unless otherwise indicated:

EXHIBIT INDEX

Exhibit
Number	Description
4.1	Second Supplemental Indenture dated as of July 22, 2011, among each of  Deer Park Energy Center LLC, Deer Park Holdings, LLC, Metcalf Energy Center, LLC, Metcalf Holdings, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of October 21, 2009, providing for the issuance of 7.25% Senior Secured Notes due 2017.
4.2	Second Supplemental Indenture dated as of July 22, 2011, among each of  Deer Park Energy Center LLC, Deer Park Holdings, LLC, Metcalf Energy Center, LLC, Metcalf Holdings, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of May 25, 2010, providing for the issuance of 8.0% Senior Secured Notes due 2019.
4.3	Second Supplemental Indenture dated as of July 22, 2011, among each of  Deer Park Energy Center LLC, Deer Park Holdings, LLC, Metcalf Energy Center, LLC, Metcalf Holdings, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of July 23, 2010, providing for the issuance of 7.875% Senior Secured Notes due 2020.
4.4	Second Supplemental Indenture dated as of July 22, 2011, among each of  Deer Park Energy Center LLC, Deer Park Holdings, LLC, Metcalf Energy Center, LLC, Metcalf Holdings, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of October 22, 2010, providing for the issuance of 7.50% Senior Secured Notes due 2021.
4.5	Second Supplemental Indenture dated as of July 22, 2011, among each of  Deer Park Energy Center LLC, Deer Park Holdings, LLC, Metcalf Energy Center, LLC, Metcalf Holdings, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of  January 14, 2011, providing for the issuance of 7.875% Senior Secured Notes due 2023.
10.1	Amended and Restated Guarantee and Collateral Agreement, dated as of December 10, 2010, made by the Company and certain of the Company's subsidiaries party thereto in favor of Goldman Sachs Credit Partners, L.P., as collateral agent.
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†

__________

† XBRL 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.

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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:  July 28, 2011

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EXHIBIT INDEX

Exhibit
Number	Description
4.1	Second Supplemental Indenture dated as of July 22, 2011, among each of  Deer Park Energy Center LLC, Deer Park Holdings, LLC, Metcalf Energy Center, LLC, Metcalf Holdings, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of October 21, 2009, providing for the issuance of 7.25% Senior Secured Notes due 2017.
4.2	Second Supplemental Indenture dated as of July 22, 2011, among each of  Deer Park Energy Center LLC, Deer Park Holdings, LLC, Metcalf Energy Center, LLC, Metcalf Holdings, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of May 25, 2010, providing for the issuance of 8.0% Senior Secured Notes due 2019.
4.3	Second Supplemental Indenture dated as of July 22, 2011, among each of  Deer Park Energy Center LLC, Deer Park Holdings, LLC, Metcalf Energy Center, LLC, Metcalf Holdings, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of July 23, 2010, providing for the issuance of 7.875% Senior Secured Notes due 2020.
4.4	Second Supplemental Indenture dated as of July 22, 2011, among each of  Deer Park Energy Center LLC, Deer Park Holdings, LLC, Metcalf Energy Center, LLC, Metcalf Holdings, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of October 22, 2010, providing for the issuance of 7.50% Senior Secured Notes due 2021.
4.5	Second Supplemental Indenture dated as of July 22, 2011, among each of  Deer Park Energy Center LLC, Deer Park Holdings, LLC, Metcalf Energy Center, LLC, Metcalf Holdings, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of  January 14, 2011, providing for the issuance of 7.875% Senior Secured Notes due 2023.
10.1	Amended and Restated Guarantee and Collateral Agreement, dated as of December 10, 2010, made by the Company and certain of the Company's subsidiaries party thereto in favor of Goldman Sachs Credit Partners, L.P., as collateral agent.
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†

__________

† XBRL 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.

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