CALPINE CORP (Form: 10-Q, Received: 07/29/2011 06:02:12)

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

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

CO 2		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

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 (CO 2 ), and including methane (CH 4 ), nitrous oxide (N 2 O), sulfur hexafluoride (SF 6 ), 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

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.

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

SO 2		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.

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

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.

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.

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

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.

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.

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

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.

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.

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.

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.

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.

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.

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.

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

	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.

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.

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.

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

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

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.

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.

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

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.

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.

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.

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

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.

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	)

	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	)

	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.

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.

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.

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 SO 2 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 SO 2 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 SO 2 and annual NOx reductions and May 1, 2012 for ozone season NOx reductions. Significant additional SO 2 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 SO 2 (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.

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 CO 2 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.

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.

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.

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

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.

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.

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.

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.

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

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.

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

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.

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

	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

	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

	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.

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

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)

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

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

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.

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.

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,

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

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.

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

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.

	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

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.

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.

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.

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.

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.

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

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 †

__________

†

EXHIBIT 4.1

SECOND SUPPLEMENTAL INDENTURE

Second Supplemental Indenture (this “ 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 and Metcalf Holdings, LLC (collectively, the “ Guaranteeing Subsidiaries ”), each a subsidiary of Calpine Corporation, a Delaware corporation (the “ Company ”), the Company, each of the guarantors party to the Indenture (as defined below) (the “Existing Guarantors” ) and Wilmington Trust Company, as trustee under the Indenture referred to below (the “ Trustee ”).

W I T N E S S E T H

WHEREAS, the Company and the guarantors party thereto have heretofore executed and delivered to the Trustee an indenture, dated as of October 21, 2009 (as supplemented by the First Supplemental Indenture dated as of April 26, 2011, the “Indenture” ), providing for the issuance of 7.25% Senior Secured Notes due 2017 (the “ Notes ”);

WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiaries shall execute and deliver to the Trustee a supplemental indenture pursuant to which each of the Guaranteeing Subsidiaries shall agree to guarantee all of the Company’s Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “ Note Guarantee ”); and

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Second Supplemental Indenture.

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, each of the Guaranteeing Subsidiaries and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders as follows:

1. Capitalized Terms . Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2. Agreement to Guarantee . Each of the Guaranteeing Subsidiaries hereby agrees to become subject to the Guarantee and Collateral Agreement pursuant to Section 4.13 of the Indenture.

3. No Recourse Against Others . No past, present or future director, officer, employee, incorporator, stockholder or agent of any of the Guaranteeing Subsidiaries, as such, shall have any liability for any obligations of the Company, any of the Existing Guarantors or any of the Guaranteeing Subsidiaries under the Notes, any Note Guarantees, the Indenture or this Second Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities under the federal securities laws and it is the view of the Commission that such a waiver is against public policy.

4. NEW YORK LAW TO GOVERN. THE INTERNAL LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SECOND SUPPLEMENTAL INDENTURE WITHOUT GIVING EFFECT TO APPLICABLE PRINCIPLES OF CONFLICTS OF LAW TO THE EXTENT THAT THE APPLICATION OF THE LAWS OF ANOTHER JURISDICTION WOULD BE REQUIRED THEREBY.

5. Counterparts . The parties may sign any number of copies of this Second Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings . The Section headings herein are for convenience only and shall not affect the construction hereof.

7. The Trustee . The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Second Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by each of the Guaranteeing Subsidiaries, the Company and the Existing Guarantors.

IN WITNESS HEREOF, the parties hereto have caused this Second Supplemental Indenture to be duly executed and attested, all as of the date first above written.

	ON BEHALF OF THE GUARANTEEING
	SUBSIDIARIES LISTED ON SCHEDULE I

	By:	/s/ ZAMIR RAUF
		Name: Zamir Rauf Title: Chief Financial Officer

	ON BEHALF OF THE EXISTING
	GUARANTORS LISTED ON SCHEDULE II

	By:	/s/ HETHER BENJAMIN-BROWN
		Name: Hether Benjamin-Brown Title: Vice President

	ON BEHALF OF THE EXISTING
	GUARANTORS LISTED ON SCHEDULE III

	By:	/s/ W. THADDEUS MILLER
		Name: W. Thaddeus Miller Title: Corporate Secretary and Chief Legal Officer

	ON BEHALF OF THE EXISTING
	SUBSIDIARIES LISTED ON SCHEDULE IV

	By:	/s/ TODD THORNTON
		Name: Todd Thornton Title: Vice President

	CALPINE CORPORATION

	By:	/s/ ZAMIR RAUF
		Name: Zamir Rauf Title: Chief Financial Officer

	WILMINGTON TRUST COMPANY,
	as Trustee

	By:	/s/ PRITAL PATEL
		Authorized Signatory

SCHEDULE I

Name of Guarantor

Deer Park Energy Center LLC

Deer Park Holdings, LLC

Metcalf Energy Center, LLC

Metcalf Holdings, LLC

SCHEDULE II

Name of Guarantor

Calpine Construction Management Company, Inc.

Calpine Mid-Atlantic Operating, LLC

Calpine Operating Services Company, Inc.

Calpine Power Services, Inc.

Thomassen Turbine Systems America, Inc.

SCHEDULE III

Name of Guarantor

Anacapa Land Company, LLC

Anderson Springs Energy Company

Auburndale Peaker Energy Center, LLC

Aviation Funding Corp.

Baytown Energy Center, LLC

Bellingham Cogen, Inc.

CalGen Expansion Company, LLC

CalGen Finance Corp.

CalGen Project Equipment Finance Company Three, LLC

Calpine Administrative Services Company, Inc.

Calpine Auburndale Holdings, LLC

Calpine c*Power, Inc.

Calpine CalGen Holdings, Inc.

Calpine California Holdings, Inc.

Calpine Calistoga Holdings, LLC

Calpine CCFC Holdings, Inc.

Calpine Central Texas GP, Inc.

Calpine Central, Inc.

Calpine Central, L.P.

Calpine Central-Texas, Inc.

Calpine Cogeneration Corporation

Calpine Eastern Corporation

Calpine Edinburg, Inc.

Calpine Energy Management, L.P.

Calpine Energy Services Holdings, Inc.

Calpine Energy Services, L.P.

Calpine Fuels Corporation

Calpine Generating Company, LLC

Calpine Geysers Company, L.P.

Calpine Gilroy 1, Inc.

Name of Guarantor

Calpine Gilroy 2, Inc.

Calpine Global Services Company, Inc.

Calpine Hidalgo Energy Center, L.P.

Calpine Hidalgo Holdings, Inc.

Calpine Hidalgo, Inc.

Calpine Jupiter, LLC

Calpine Kennedy Operators, Inc.

Calpine KIA, Inc.

Calpine King City, Inc.

Calpine King City, LLC

Calpine Leasing Inc.

Calpine Long Island, Inc.

Calpine Magic Valley Pipeline, Inc.

Calpine MVP, Inc.

Calpine Newark, LLC

Calpine Northbrook Holdings Corporation

Calpine Northbrook Investors, LLC

Calpine Northbrook Project Holdings, LLC

Calpine Oneta Power, LLC

Calpine Operations Management Company, Inc.

Calpine Power Company

Calpine Power, Inc.

Calpine Power Management, Inc.

Calpine Power Management, LLC

Calpine PowerAmerica, Inc.

Calpine PowerAmerica, LLC

Calpine PowerAmerica-CA, LLC

Calpine PowerAmerica-CT, LLC

Calpine PowerAmerica-MA, LLC

Calpine PowerAmerica-ME, LLC

Calpine PowerAmerica-NH, LLC

Name of Guarantor

Calpine PowerAmerica-NY, LLC

Calpine PowerAmerica-OR, LLC

Calpine PowerAmerica-PA, LLC

Calpine PowerAmerica-RI, LLC

Calpine Project Holdings, Inc.

Calpine Pryor, Inc.

Calpine Rumford I, Inc.

Calpine Rumford, Inc.

Calpine Schuylkill, Inc.

Calpine Sonoran Pipeline, LLC

Calpine Stony Brook Operators, Inc.

Calpine Stony Brook, Inc.

Calpine Sumas, Inc.

Calpine TCCL Holdings, Inc.

Calpine Texas Pipeline GP, Inc.

Calpine Texas Pipeline LP, Inc.

Calpine Texas Pipeline, L.P.

Calpine Tiverton I, Inc.

Calpine Tiverton, Inc.

Calpine University Power, Inc.

Carville Energy LLC

CCFC Development Company, LLC

CES Marketing IX, LLC

CES Marketing V, L.P.

CES Marketing X, LLC

Channel Energy Center, LLC

Clear Lake Cogeneration Limited Partnership

Columbia Energy LLC

Corpus Christi Cogeneration, LLC

CPN 3 rd Turbine, Inc.

CPN Acadia, Inc.

Name of Guarantor

CPN Cascade, Inc.

CPN Clear Lake, Inc.

CPN East Fuels, LLC

CPN Energy Services GP, Inc.

CPN Energy Services LP, Inc.

CPN Pipeline Company

CPN Pryor Funding Corporation

CPN Telephone Flat, Inc.

Decatur Energy Center, LLC

Delta Energy Center, LLC

East Altamont Energy Center, LLC

Fontana Energy Center, LLC

Freestone Power Generation, LLC

GEC Bethpage Inc.

Geysers Power Company, LLC

Geysers Power I Company

Hillabee Energy Center, LLC

Idlewild Fuel Management Corp.

JMC Bethpage, Inc.

Lone Oak Energy Center, LLC

Los Medanos Energy Center LLC

Magic Valley Pipeline, L.P.

Moapa Energy Center, LLC

Mobile Energy LLC

Modoc Power, Inc.

Morgan Energy Center, LLC

Northwest Cogeneration, Inc.

NTC Five, Inc.

Pastoria Energy Center, LLC

Pastoria Energy Facility, L.L.C.

Pine Bluff Energy, LLC

Name of Guarantor

RockGen Energy LLC

Rumford Power Associates Limited Partnership

San Joaquin Valley Energy Center, LLC

Santa Rosa Energy Center, LLC

Stony Brook Cogeneration, Inc.

Stony Brook Fuel Management Corp.

Sutter Dryers, Inc.

Texas City Cogeneration, LLC

Texas Cogeneration Five, Inc.

Texas Cogeneration One Company

Thermal Power Company

Tiverton Power Associates Limited Partnership

Wawayanda Energy Center, LLC

Zion Energy LLC

SCHEDULE IV

Name of Guarantor

Calpine Bethlehem, LLC

Calpine Mid-Atlantic Energy, LLC

Calpine Mid-Atlantic Generation, LLC

Calpine Mid-Atlantic Marketing, LLC

Calpine New Jersey Generation, LLC

Calpine Solar, LLC

Calpine Vineland Solar, LLC

New Development Holdings, LLC

EXHIBIT 4.2

SECOND SUPPLEMENTAL INDENTURE

W I T N E S S E T H

WHEREAS, the Company and the guarantors party thereto have heretofore executed and delivered to the Trustee an amended and restated indenture, dated as of May 25, 2010 (as supplemented by the First Supplemental Indenture dated as of April 26, 2011, the “Indenture” ), providing for the issuance of 8% Senior Secured Notes due 2019 (the “ Notes ”);

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Second Supplemental Indenture.

1. Capitalized Terms . Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2. Agreement to Guarantee . Each of the Guaranteeing Subsidiaries hereby agrees to become subject to the Guarantee and Collateral Agreement pursuant to Section 4.13 of the Indenture.

5. Counterparts . The parties may sign any number of copies of this Second Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings . The Section headings herein are for convenience only and shall not affect the construction hereof.

IN WITNESS HEREOF, the parties hereto have caused this Second Supplemental Indenture to be duly executed and attested, all as of the date first above written.

	ON BEHALF OF THE GUARANTEEING
	SUBSIDIARIES LISTED ON SCHEDULE I

	By:	/s/ ZAMIR RAUF
		Name: Zamir Rauf Title: Chief Financial Officer

	ON BEHALF OF THE EXISTING
	GUARANTORS LISTED ON SCHEDULE II

	By:	/s/ HETHER BENJAMIN-BROWN
		Name: Hether Benjamin-Brown Title: Vice President

	ON BEHALF OF THE EXISTING
	GUARANTORS LISTED ON SCHEDULE III

	By:	/s/ W. THADDEUS MILLER
		Name: W. Thaddeus Miller Title: Corporate Secretary and Chief Legal Officer

	ON BEHALF OF THE EXISTING
	SUBSIDIARIES LISTED ON SCHEDULE IV

	By:	/s/ TODD THORNTON
		Name: Todd Thornton Title: Vice President

	CALPINE CORPORATION

	By:	/s/ ZAMIR RAUF
		Name: Zamir Rauf Title: Chief Financial Officer

	WILMINGTON TRUST COMPANY,
	as Trustee

	By:	/s/ PRITAL PATEL
		Authorized Signatory

SCHEDULE I

Name of Guarantor

Deer Park Energy Center LLC

Deer Park Holdings, LLC

Metcalf Energy Center, LLC

Metcalf Holdings, LLC

SCHEDULE II

Name of Guarantor

Calpine Construction Management Company, Inc.

Calpine Mid-Atlantic Operating, LLC

Calpine Operating Services Company, Inc.

Calpine Power Services, Inc.

Thomassen Turbine Systems America, Inc.

SCHEDULE III

Name of Guarantor

Anacapa Land Company, LLC

Anderson Springs Energy Company

Auburndale Peaker Energy Center, LLC

Aviation Funding Corp.

Baytown Energy Center, LLC

Bellingham Cogen, Inc.

CalGen Expansion Company, LLC

CalGen Finance Corp.

CalGen Project Equipment Finance Company Three, LLC

Calpine Administrative Services Company, Inc.

Calpine Auburndale Holdings, LLC

Calpine c*Power, Inc.

Calpine CalGen Holdings, Inc.

Calpine California Holdings, Inc.

Calpine Calistoga Holdings, LLC

Calpine CCFC Holdings, Inc.

Calpine Central Texas GP, Inc.

Calpine Central, Inc.

Calpine Central, L.P.

Calpine Central-Texas, Inc.

Calpine Cogeneration Corporation

Calpine Eastern Corporation

Calpine Edinburg, Inc.

Calpine Energy Management, L.P.

Calpine Energy Services Holdings, Inc.

Calpine Energy Services, L.P.

Calpine Fuels Corporation

Calpine Generating Company, LLC

Calpine Geysers Company, L.P.

Calpine Gilroy 1, Inc.

Name of Guarantor

Calpine Gilroy 2, Inc.

Calpine Global Services Company, Inc.

Calpine Hidalgo Energy Center, L.P.

Calpine Hidalgo Holdings, Inc.

Calpine Hidalgo, Inc.

Calpine Jupiter, LLC

Calpine Kennedy Operators, Inc.

Calpine KIA, Inc.

Calpine King City, Inc.

Calpine King City, LLC

Calpine Leasing Inc.

Calpine Long Island, Inc.

Calpine Magic Valley Pipeline, Inc.

Calpine MVP, Inc.

Calpine Newark, LLC

Calpine Northbrook Holdings Corporation

Calpine Northbrook Investors, LLC

Calpine Northbrook Project Holdings, LLC

Calpine Oneta Power, LLC

Calpine Operations Management Company, Inc.

Calpine Power Company

Calpine Power, Inc.

Calpine Power Management, Inc.

Calpine Power Management, LLC

Calpine PowerAmerica, Inc.

Calpine PowerAmerica, LLC

Calpine PowerAmerica-CA, LLC

Calpine PowerAmerica-CT, LLC

Calpine PowerAmerica-MA, LLC

Calpine PowerAmerica-ME, LLC

Calpine PowerAmerica-NH, LLC

Name of Guarantor

Calpine PowerAmerica-NY, LLC

Calpine PowerAmerica-OR, LLC

Calpine PowerAmerica-PA, LLC

Calpine PowerAmerica-RI, LLC

Calpine Project Holdings, Inc.

Calpine Pryor, Inc.

Calpine Rumford I, Inc.

Calpine Rumford, Inc.

Calpine Schuylkill, Inc.

Calpine Sonoran Pipeline, LLC

Calpine Stony Brook Operators, Inc.

Calpine Stony Brook, Inc.

Calpine Sumas, Inc.

Calpine TCCL Holdings, Inc.

Calpine Texas Pipeline GP, Inc.

Calpine Texas Pipeline LP, Inc.

Calpine Texas Pipeline, L.P.

Calpine Tiverton I, Inc.

Calpine Tiverton, Inc.

Calpine University Power, Inc.

Carville Energy LLC

CCFC Development Company, LLC

CES Marketing IX, LLC

CES Marketing V, L.P.

CES Marketing X, LLC

Channel Energy Center, LLC

Clear Lake Cogeneration Limited Partnership

Columbia Energy LLC

Corpus Christi Cogeneration, LLC

CPN 3 rd Turbine, Inc.

CPN Acadia, Inc.

Name of Guarantor

CPN Cascade, Inc.

CPN Clear Lake, Inc.

CPN East Fuels, LLC

CPN Energy Services GP, Inc.

CPN Energy Services LP, Inc.

CPN Pipeline Company

CPN Pryor Funding Corporation

CPN Telephone Flat, Inc.

Decatur Energy Center, LLC

Delta Energy Center, LLC

East Altamont Energy Center, LLC

Fontana Energy Center, LLC

Freestone Power Generation, LLC

GEC Bethpage Inc.

Geysers Power Company, LLC

Geysers Power I Company

Hillabee Energy Center, LLC

Idlewild Fuel Management Corp.

JMC Bethpage, Inc.

Lone Oak Energy Center, LLC

Los Medanos Energy Center LLC

Magic Valley Pipeline, L.P.

Moapa Energy Center, LLC

Mobile Energy LLC

Modoc Power, Inc.

Morgan Energy Center, LLC

Northwest Cogeneration, Inc.

NTC Five, Inc.

Pastoria Energy Center, LLC

Pastoria Energy Facility, L.L.C.

Pine Bluff Energy, LLC

Name of Guarantor

RockGen Energy LLC

Rumford Power Associates Limited Partnership

San Joaquin Valley Energy Center, LLC

Santa Rosa Energy Center, LLC

Stony Brook Cogeneration, Inc.

Stony Brook Fuel Management Corp.

Sutter Dryers, Inc.

Texas City Cogeneration, LLC

Texas Cogeneration Five, Inc.

Texas Cogeneration One Company

Thermal Power Company

Tiverton Power Associates Limited Partnership

Wawayanda Energy Center, LLC

Zion Energy LLC

SCHEDULE IV

Name of Guarantor

Calpine Bethlehem, LLC

Calpine Mid-Atlantic Energy, LLC

Calpine Mid-Atlantic Generation, LLC

Calpine Mid-Atlantic Marketing, LLC

Calpine New Jersey Generation, LLC

Calpine Solar, LLC

Calpine Vineland Solar, LLC

New Development Holdings, LLC

EXHIBIT 4.3

SECOND SUPPLEMENTAL INDENTURE

W I T N E S S E T H

WHEREAS, the Company and the guarantors party thereto have heretofore executed and delivered to the Trustee an indenture, dated as of July 23, 2010 (as supplemented by the First Supplemental Indenture dated as of April 26, 2011, the “Indenture” ), providing for the issuance of 7.875% Senior Secured Notes due 2020 (the “ Notes ”);

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Second Supplemental Indenture.

1. Capitalized Terms . Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2. Agreement to Guarantee . Each of the Guaranteeing Subsidiaries hereby agrees to become subject to the Guarantee and Collateral Agreement pursuant to Section 4.13 of the Indenture.

5. Counterparts . The parties may sign any number of copies of this Second Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings . The Section headings herein are for convenience only and shall not affect the construction hereof.

IN WITNESS HEREOF, the parties hereto have caused this Second Supplemental Indenture to be duly executed and attested, all as of the date first above written.

	ON BEHALF OF THE GUARANTEEING
	SUBSIDIARIES LISTED ON SCHEDULE I

	By:	/s/ ZAMIR RAUF
		Name: Zamir Rauf Title: Chief Financial Officer

	ON BEHALF OF THE EXISTING
	GUARANTORS LISTED ON SCHEDULE II

	By:	/s/ HETHER BENJAMIN-BROWN
		Name: Hether Benjamin-Brown Title: Vice President

	ON BEHALF OF THE EXISTING
	GUARANTORS LISTED ON SCHEDULE III

	By:	/s/ W. THADDEUS MILLER
		Name: W. Thaddeus Miller Title: Corporate Secretary and Chief Legal Officer

	ON BEHALF OF THE EXISTING
	SUBSIDIARIES LISTED ON SCHEDULE IV

	By:	/s/ TODD THORNTON
		Name: Todd Thornton Title: Vice President

	CALPINE CORPORATION

	By:	/s/ ZAMIR RAUF
		Name: Zamir Rauf Title: Chief Financial Officer

	WILMINGTON TRUST COMPANY,
	as Trustee

	By:	/s/ PRITAL PATEL
		Authorized Signatory

SCHEDULE I

Name of Guarantor

Deer Park Energy Center LLC

Deer Park Holdings, LLC

Metcalf Energy Center, LLC

Metcalf Holdings, LLC

SCHEDULE II

Name of Guarantor

Calpine Construction Management Company, Inc.

Calpine Mid-Atlantic Operating, LLC

Calpine Operating Services Company, Inc.

Calpine Power Services, Inc.

Thomassen Turbine Systems America, Inc.

SCHEDULE III

Name of Guarantor

Anacapa Land Company, LLC

Anderson Springs Energy Company

Auburndale Peaker Energy Center, LLC

Aviation Funding Corp.

Baytown Energy Center, LLC

Bellingham Cogen, Inc.

CalGen Expansion Company, LLC

CalGen Finance Corp.

CalGen Project Equipment Finance Company Three, LLC

Calpine Administrative Services Company, Inc.

Calpine Auburndale Holdings, LLC

Calpine c*Power, Inc.

Calpine CalGen Holdings, Inc.

Calpine California Holdings, Inc.

Calpine Calistoga Holdings, LLC

Calpine CCFC Holdings, Inc.

Calpine Central Texas GP, Inc.

Calpine Central, Inc.

Calpine Central, L.P.

Calpine Central-Texas, Inc.

Calpine Cogeneration Corporation

Calpine Eastern Corporation

Calpine Edinburg, Inc.

Calpine Energy Management, L.P.

Calpine Energy Services Holdings, Inc.

Calpine Energy Services, L.P.

Calpine Fuels Corporation

Calpine Generating Company, LLC

Calpine Geysers Company, L.P.

Calpine Gilroy 1, Inc.

Name of Guarantor

Calpine Gilroy 2, Inc.

Calpine Global Services Company, Inc.

Calpine Hidalgo Energy Center, L.P.

Calpine Hidalgo Holdings, Inc.

Calpine Hidalgo, Inc.

Calpine Jupiter, LLC

Calpine Kennedy Operators, Inc.

Calpine KIA, Inc.

Calpine King City, Inc.

Calpine King City, LLC

Calpine Leasing Inc.

Calpine Long Island, Inc.

Calpine Magic Valley Pipeline, Inc.

Calpine MVP, Inc.

Calpine Newark, LLC

Calpine Northbrook Holdings Corporation

Calpine Northbrook Investors, LLC

Calpine Northbrook Project Holdings, LLC

Calpine Oneta Power, LLC

Calpine Operations Management Company, Inc.

Calpine Power Company

Calpine Power, Inc.

Calpine Power Management, Inc.

Calpine Power Management, LLC

Calpine PowerAmerica, Inc.

Calpine PowerAmerica, LLC

Calpine PowerAmerica-CA, LLC

Calpine PowerAmerica-CT, LLC

Calpine PowerAmerica-MA, LLC

Calpine PowerAmerica-ME, LLC

Calpine PowerAmerica-NH, LLC

Name of Guarantor

Calpine PowerAmerica-NY, LLC

Calpine PowerAmerica-OR, LLC

Calpine PowerAmerica-PA, LLC

Calpine PowerAmerica-RI, LLC

Calpine Project Holdings, Inc.

Calpine Pryor, Inc.

Calpine Rumford I, Inc.

Calpine Rumford, Inc.

Calpine Schuylkill, Inc.

Calpine Sonoran Pipeline, LLC

Calpine Stony Brook Operators, Inc.

Calpine Stony Brook, Inc.

Calpine Sumas, Inc.

Calpine TCCL Holdings, Inc.

Calpine Texas Pipeline GP, Inc.

Calpine Texas Pipeline LP, Inc.

Calpine Texas Pipeline, L.P.

Calpine Tiverton I, Inc.

Calpine Tiverton, Inc.

Calpine University Power, Inc.

Carville Energy LLC

CCFC Development Company, LLC

CES Marketing IX, LLC

CES Marketing V, L.P.

CES Marketing X, LLC

Channel Energy Center, LLC

Clear Lake Cogeneration Limited Partnership

Columbia Energy LLC

Corpus Christi Cogeneration, LLC

CPN 3 rd Turbine, Inc.

CPN Acadia, Inc.

Name of Guarantor

CPN Cascade, Inc.

CPN Clear Lake, Inc.

CPN East Fuels, LLC

CPN Energy Services GP, Inc.

CPN Energy Services LP, Inc.

CPN Pipeline Company

CPN Pryor Funding Corporation

CPN Telephone Flat, Inc.

Decatur Energy Center, LLC

Delta Energy Center, LLC

East Altamont Energy Center, LLC

Fontana Energy Center, LLC

Freestone Power Generation, LLC

GEC Bethpage Inc.

Geysers Power Company, LLC

Geysers Power I Company

Hillabee Energy Center, LLC

Idlewild Fuel Management Corp.

JMC Bethpage, Inc.

Lone Oak Energy Center, LLC

Los Medanos Energy Center LLC

Magic Valley Pipeline, L.P.

Moapa Energy Center, LLC

Mobile Energy LLC

Modoc Power, Inc.

Morgan Energy Center, LLC

Northwest Cogeneration, Inc.

NTC Five, Inc.

Pastoria Energy Center, LLC

Pastoria Energy Facility, L.L.C.

Pine Bluff Energy, LLC

Name of Guarantor

RockGen Energy LLC

Rumford Power Associates Limited Partnership

San Joaquin Valley Energy Center, LLC

Santa Rosa Energy Center, LLC

Stony Brook Cogeneration, Inc.

Stony Brook Fuel Management Corp.

Sutter Dryers, Inc.

Texas City Cogeneration, LLC

Texas Cogeneration Five, Inc.

Texas Cogeneration One Company

Thermal Power Company

Tiverton Power Associates Limited Partnership

Wawayanda Energy Center, LLC

Zion Energy LLC

SCHEDULE IV

Name of Guarantor

Calpine Bethlehem, LLC

Calpine Mid-Atlantic Energy, LLC

Calpine Mid-Atlantic Generation, LLC

Calpine Mid-Atlantic Marketing, LLC

Calpine New Jersey Generation, LLC

Calpine Solar, LLC

Calpine Vineland Solar, LLC

New Development Holdings, LLC

EXHIBIT 4.4

SECOND SUPPLEMENTAL INDENTURE

W I T N E S S E T H

WHEREAS, the Company and the guarantors party thereto have heretofore executed and delivered to the Trustee an indenture, dated as of October 22, 2010 (as supplemented by the First Supplemental Indenture dated as of April 26, 2011, the “Indenture” ), providing for the issuance of 7.50% Senior Secured Notes due 2021 (the “ Notes ”);

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Second Supplemental Indenture.

1. Capitalized Terms . Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2. Agreement to Guarantee . Each of the Guaranteeing Subsidiaries hereby agrees to become subject to the Guarantee and Collateral Agreement pursuant to Section 4.13 of the Indenture.

5. Counterparts . The parties may sign any number of copies of this Second Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings . The Section headings herein are for convenience only and shall not affect the construction hereof.

IN WITNESS HEREOF, the parties hereto have caused this Second Supplemental Indenture to be duly executed and attested, all as of the date first above written.

	ON BEHALF OF THE GUARANTEEING
	SUBSIDIARIES LISTED ON SCHEDULE I

	By:	/s/ ZAMIR RAUF
		Name: Zamir Rauf Title: Chief Financial Officer

	ON BEHALF OF THE EXISTING
	GUARANTORS LISTED ON SCHEDULE II

	By:	/s/ HETHER BENJAMIN-BROWN
		Name: Hether Benjamin-Brown Title: Vice President

	ON BEHALF OF THE EXISTING
	GUARANTORS LISTED ON SCHEDULE III

	By:	/s/ W. THADDEUS MILLER
		Name: W. Thaddeus Miller Title: Corporate Secretary and Chief Legal Officer

	ON BEHALF OF THE EXISTING
	SUBSIDIARIES LISTED ON SCHEDULE IV

	By:	/s/ TODD THORNTON
		Name: Todd Thornton Title: Vice President

	CALPINE CORPORATION

	By:	/s/ ZAMIR RAUF
		Name: Zamir Rauf Title: Chief Financial Officer

	WILMINGTON TRUST COMPANY,
	as Trustee

	By:	/s/ PRITAL PATEL
		Authorized Signatory

SCHEDULE I

Name of Guarantor

Deer Park Energy Center LLC

Deer Park Holdings, LLC

Metcalf Energy Center, LLC

Metcalf Holdings, LLC

SCHEDULE II

Name of Guarantor

Calpine Construction Management Company, Inc.

Calpine Mid-Atlantic Operating, LLC

Calpine Operating Services Company, Inc.

Calpine Power Services, Inc.

Thomassen Turbine Systems America, Inc.

SCHEDULE III

Name of Guarantor

Anacapa Land Company, LLC

Anderson Springs Energy Company

Auburndale Peaker Energy Center, LLC

Aviation Funding Corp.

Baytown Energy Center, LLC

Bellingham Cogen, Inc.

CalGen Expansion Company, LLC

CalGen Finance Corp.

CalGen Project Equipment Finance Company Three, LLC

Calpine Administrative Services Company, Inc.

Calpine Auburndale Holdings, LLC

Calpine c*Power, Inc.

Calpine CalGen Holdings, Inc.

Calpine California Holdings, Inc.

Calpine Calistoga Holdings, LLC

Calpine CCFC Holdings, Inc.

Calpine Central Texas GP, Inc.

Calpine Central, Inc.

Calpine Central, L.P.

Calpine Central-Texas, Inc.

Calpine Cogeneration Corporation

Calpine Eastern Corporation

Calpine Edinburg, Inc.

Calpine Energy Management, L.P.

Calpine Energy Services Holdings, Inc.

Calpine Energy Services, L.P.

Calpine Fuels Corporation

Calpine Generating Company, LLC

Calpine Geysers Company, L.P.

Calpine Gilroy 1, Inc.

Name of Guarantor

Calpine Gilroy 2, Inc.

Calpine Global Services Company, Inc.

Calpine Hidalgo Energy Center, L.P.

Calpine Hidalgo Holdings, Inc.

Calpine Hidalgo, Inc.

Calpine Jupiter, LLC

Calpine Kennedy Operators, Inc.

Calpine KIA, Inc.

Calpine King City, Inc.

Calpine King City, LLC

Calpine Leasing Inc.

Calpine Long Island, Inc.

Calpine Magic Valley Pipeline, Inc.

Calpine MVP, Inc.

Calpine Newark, LLC

Calpine Northbrook Holdings Corporation

Calpine Northbrook Investors, LLC

Calpine Northbrook Project Holdings, LLC

Calpine Oneta Power, LLC

Calpine Operations Management Company, Inc.

Calpine Power Company

Calpine Power, Inc.

Calpine Power Management, Inc.

Calpine Power Management, LLC

Calpine PowerAmerica, Inc.

Calpine PowerAmerica, LLC

Calpine PowerAmerica-CA, LLC

Calpine PowerAmerica-CT, LLC

Calpine PowerAmerica-MA, LLC

Calpine PowerAmerica-ME, LLC

Calpine PowerAmerica-NH, LLC

Name of Guarantor

Calpine PowerAmerica-NY, LLC

Calpine PowerAmerica-OR, LLC

Calpine PowerAmerica-PA, LLC

Calpine PowerAmerica-RI, LLC

Calpine Project Holdings, Inc.

Calpine Pryor, Inc.

Calpine Rumford I, Inc.

Calpine Rumford, Inc.

Calpine Schuylkill, Inc.

Calpine Sonoran Pipeline, LLC

Calpine Stony Brook Operators, Inc.

Calpine Stony Brook, Inc.

Calpine Sumas, Inc.

Calpine TCCL Holdings, Inc.

Calpine Texas Pipeline GP, Inc.

Calpine Texas Pipeline LP, Inc.

Calpine Texas Pipeline, L.P.

Calpine Tiverton I, Inc.

Calpine Tiverton, Inc.

Calpine University Power, Inc.

Carville Energy LLC

CCFC Development Company, LLC

CES Marketing IX, LLC

CES Marketing V, L.P.

CES Marketing X, LLC

Channel Energy Center, LLC

Clear Lake Cogeneration Limited Partnership

Columbia Energy LLC

Corpus Christi Cogeneration, LLC

CPN 3 rd Turbine, Inc.

CPN Acadia, Inc.

Name of Guarantor

CPN Cascade, Inc.

CPN Clear Lake, Inc.

CPN East Fuels, LLC

CPN Energy Services GP, Inc.

CPN Energy Services LP, Inc.

CPN Pipeline Company

CPN Pryor Funding Corporation

CPN Telephone Flat, Inc.

Decatur Energy Center, LLC

Delta Energy Center, LLC

East Altamont Energy Center, LLC

Fontana Energy Center, LLC

Freestone Power Generation, LLC

GEC Bethpage Inc.

Geysers Power Company, LLC

Geysers Power I Company

Hillabee Energy Center, LLC

Idlewild Fuel Management Corp.

JMC Bethpage, Inc.

Lone Oak Energy Center, LLC

Los Medanos Energy Center LLC

Magic Valley Pipeline, L.P.

Moapa Energy Center, LLC

Mobile Energy LLC

Modoc Power, Inc.

Morgan Energy Center, LLC

Northwest Cogeneration, Inc.

NTC Five, Inc.

Pastoria Energy Center, LLC

Pastoria Energy Facility, L.L.C.

Pine Bluff Energy, LLC

Name of Guarantor

RockGen Energy LLC

Rumford Power Associates Limited Partnership

San Joaquin Valley Energy Center, LLC

Santa Rosa Energy Center, LLC

Stony Brook Cogeneration, Inc.

Stony Brook Fuel Management Corp.

Sutter Dryers, Inc.

Texas City Cogeneration, LLC

Texas Cogeneration Five, Inc.

Texas Cogeneration One Company

Thermal Power Company

Tiverton Power Associates Limited Partnership

Wawayanda Energy Center, LLC

Zion Energy LLC

SCHEDULE IV

Name of Guarantor

Calpine Bethlehem, LLC

Calpine Mid-Atlantic Energy, LLC

Calpine Mid-Atlantic Generation, LLC

Calpine Mid-Atlantic Marketing, LLC

Calpine New Jersey Generation, LLC

Calpine Solar, LLC

Calpine Vineland Solar, LLC

New Development Holdings, LLC

EXHIBIT 4.5

SECOND SUPPLEMENTAL INDENTURE

W I T N E S S E T H

WHEREAS, the Company and the guarantors party thereto have heretofore executed and delivered to the Trustee an indenture, dated as of January 14, 2011 (as supplemented by the First Supplemental Indenture dated as of April 26, 2011, the “Indenture” ), providing for the issuance of 7.875% Senior Secured Notes due 2023 (the “ Notes ”);

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Second Supplemental Indenture.

1. Capitalized Terms . Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2. Agreement to Guarantee . Each of the Guaranteeing Subsidiaries hereby agrees to become subject to the Guarantee and Collateral Agreement pursuant to Section 4.13 of the Indenture.

5. Counterparts . The parties may sign any number of copies of this Second Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings . The Section headings herein are for convenience only and shall not affect the construction hereof.

IN WITNESS HEREOF, the parties hereto have caused this Second Supplemental Indenture to be duly executed and attested, all as of the date first above written.

	ON BEHALF OF THE GUARANTEEING
	SUBSIDIARIES LISTED ON SCHEDULE I

	By:	/s/ ZAMIR RAUF
		Name: Zamir Rauf Title: Chief Financial Officer

	ON BEHALF OF THE EXISTING
	GUARANTORS LISTED ON SCHEDULE II

	By:	/s/ HETHER BENJAMIN-BROWN
		Name: Hether Benjamin-Brown Title: Vice President

	ON BEHALF OF THE EXISTING
	GUARANTORS LISTED ON SCHEDULE III

	By:	/s/ W. THADDEUS MILLER
		Name: W. Thaddeus Miller Title: Corporate Secretary and Chief Legal Officer

	ON BEHALF OF THE EXISTING
	SUBSIDIARIES LISTED ON SCHEDULE IV

	By:	/s/ TODD THORNTON
		Name: Todd Thornton Title: Vice President

	CALPINE CORPORATION

	By:	/s/ ZAMIR RAUF
		Name: Zamir Rauf Title: Chief Financial Officer

	WILMINGTON TRUST COMPANY,
	as Trustee

	By:	/s/ PRITAL PATEL
		Authorized Signatory

SCHEDULE I

Name of Guarantor

Deer Park Energy Center LLC

Deer Park Holdings, LLC

Metcalf Energy Center, LLC

Metcalf Holdings, LLC

SCHEDULE II

Name of Guarantor

Calpine Construction Management Company, Inc.

Calpine Mid-Atlantic Operating, LLC

Calpine Operating Services Company, Inc.

Calpine Power Services, Inc.

Thomassen Turbine Systems America, Inc.

SCHEDULE III

Name of Guarantor

Anacapa Land Company, LLC

Anderson Springs Energy Company

Auburndale Peaker Energy Center, LLC

Aviation Funding Corp.

Baytown Energy Center, LLC

Bellingham Cogen, Inc.

CalGen Expansion Company, LLC

CalGen Finance Corp.

CalGen Project Equipment Finance Company Three, LLC

Calpine Administrative Services Company, Inc.

Calpine Auburndale Holdings, LLC

Calpine c*Power, Inc.

Calpine CalGen Holdings, Inc.

Calpine California Holdings, Inc.

Calpine Calistoga Holdings, LLC

Calpine CCFC Holdings, Inc.

Calpine Central Texas GP, Inc.

Calpine Central, Inc.

Calpine Central, L.P.

Calpine Central-Texas, Inc.

Calpine Cogeneration Corporation

Calpine Eastern Corporation

Calpine Edinburg, Inc.

Calpine Energy Management, L.P.

Calpine Energy Services Holdings, Inc.

Calpine Energy Services, L.P.

Calpine Fuels Corporation

Calpine Generating Company, LLC

Calpine Geysers Company, L.P.

Calpine Gilroy 1, Inc.

Name of Guarantor

Calpine Gilroy 2, Inc.

Calpine Global Services Company, Inc.

Calpine Hidalgo Energy Center, L.P.

Calpine Hidalgo Holdings, Inc.

Calpine Hidalgo, Inc.

Calpine Jupiter, LLC

Calpine Kennedy Operators, Inc.

Calpine KIA, Inc.

Calpine King City, Inc.

Calpine King City, LLC

Calpine Leasing Inc.

Calpine Long Island, Inc.

Calpine Magic Valley Pipeline, Inc.

Calpine MVP, Inc.

Calpine Newark, LLC

Calpine Northbrook Holdings Corporation

Calpine Northbrook Investors, LLC

Calpine Northbrook Project Holdings, LLC

Calpine Oneta Power, LLC

Calpine Operations Management Company, Inc.

Calpine Power Company

Calpine Power, Inc.

Calpine Power Management, Inc.

Calpine Power Management, LLC

Calpine PowerAmerica, Inc.

Calpine PowerAmerica, LLC

Calpine PowerAmerica-CA, LLC

Calpine PowerAmerica-CT, LLC

Calpine PowerAmerica-MA, LLC

Calpine PowerAmerica-ME, LLC

Calpine PowerAmerica-NH, LLC

Name of Guarantor

Calpine PowerAmerica-NY, LLC

Calpine PowerAmerica-OR, LLC

Calpine PowerAmerica-PA, LLC

Calpine PowerAmerica-RI, LLC

Calpine Project Holdings, Inc.

Calpine Pryor, Inc.

Calpine Rumford I, Inc.

Calpine Rumford, Inc.

Calpine Schuylkill, Inc.

Calpine Sonoran Pipeline, LLC

Calpine Stony Brook Operators, Inc.

Calpine Stony Brook, Inc.

Calpine Sumas, Inc.

Calpine TCCL Holdings, Inc.

Calpine Texas Pipeline GP, Inc.

Calpine Texas Pipeline LP, Inc.

Calpine Texas Pipeline, L.P.

Calpine Tiverton I, Inc.

Calpine Tiverton, Inc.

Calpine University Power, Inc.

Carville Energy LLC

CCFC Development Company, LLC

CES Marketing IX, LLC

CES Marketing V, L.P.

CES Marketing X, LLC

Channel Energy Center, LLC

Clear Lake Cogeneration Limited Partnership

Columbia Energy LLC

Corpus Christi Cogeneration, LLC

CPN 3 rd Turbine, Inc.

CPN Acadia, Inc.

Name of Guarantor

CPN Cascade, Inc.

CPN Clear Lake, Inc.

CPN East Fuels, LLC

CPN Energy Services GP, Inc.

CPN Energy Services LP, Inc.

CPN Pipeline Company

CPN Pryor Funding Corporation

CPN Telephone Flat, Inc.

Decatur Energy Center, LLC

Delta Energy Center, LLC

East Altamont Energy Center, LLC

Fontana Energy Center, LLC

Freestone Power Generation, LLC

GEC Bethpage Inc.

Geysers Power Company, LLC

Geysers Power I Company

Hillabee Energy Center, LLC

Idlewild Fuel Management Corp.

JMC Bethpage, Inc.

Lone Oak Energy Center, LLC

Los Medanos Energy Center LLC

Magic Valley Pipeline, L.P.

Moapa Energy Center, LLC

Mobile Energy LLC

Modoc Power, Inc.

Morgan Energy Center, LLC

Northwest Cogeneration, Inc.

NTC Five, Inc.

Pastoria Energy Center, LLC

Pastoria Energy Facility, L.L.C.

Pine Bluff Energy, LLC

Name of Guarantor

RockGen Energy LLC

Rumford Power Associates Limited Partnership

San Joaquin Valley Energy Center, LLC

Santa Rosa Energy Center, LLC

Stony Brook Cogeneration, Inc.

Stony Brook Fuel Management Corp.

Sutter Dryers, Inc.

Texas City Cogeneration, LLC

Texas Cogeneration Five, Inc.

Texas Cogeneration One Company

Thermal Power Company

Tiverton Power Associates Limited Partnership

Wawayanda Energy Center, LLC

Zion Energy LLC

SCHEDULE IV

Name of Guarantor

Calpine Bethlehem, LLC

Calpine Mid-Atlantic Energy, LLC

Calpine Mid-Atlantic Generation, LLC

Calpine Mid-Atlantic Marketing, LLC

Calpine New Jersey Generation, LLC

Calpine Solar, LLC

Calpine Vineland Solar, LLC

New Development Holdings, LLC

EXHIBIT 10.1

AMENDED AND RESTATED

GUARANTEE AND COLLATERAL AGREEMENT

made by

CALPINE CORPORATION

and certain of its Subsidiaries

in favor of

GOLDMAN SACHS CREDIT PARTNERS L.P.,

as Collateral Agent

Dated as of January 31, 2008 and

amended and restated as of December 10, 2010

		Page

SECTION 1. Defined Terms		4

1.1	Defined Terms	4
1.2	Other Definitional Provisions	10

SECTION 2. Guarantee		10

2.1	Guarantee	10
2.2	Right of Contribution	11
2.3	No Subrogation	12
2.4	Amendments, etc. with respect to the Guaranteed Obligations	12
2.5	Guarantee Absolute and Unconditional	12
2.6	Reinstatement	13
2.7	Payments	13

SECTION 3. Grant of Security Interest		14

SECTION 4. Representations and Warranties		15

4.1	Title; No Other Liens	15
4.2	Perfected First Priority Liens	16
4.3	Jurisdiction of Organization; Chief Executive Office	16
4.4	Farm Products	16
4.5	Investment Property	16
4.6	Receivables	17
4.7	Intellectual Property	17
4.8	Commercial Tort Claims	17

SECTION 5. Covenants		17

5.1	Delivery of Instruments, Certificated Securities and Chattel Paper	18
5.2	Maintenance of Insurance	18
5.3	Maintenance of Perfected Security Interest; Further Documentation	18
5.4	Changes in Name, etc.	19
5.5	Notices	19
5.6	Investment Property	19
5.7	Intellectual Property	20
5.8	Commercial Tort Claims	21

SECTION 6. Remedial Provisions		22

6.1	Certain Matters Relating to Receivables	22
6.2	Communications with Obligors; Grantors Remain Liable	22
6.3	Pledged Stock	23
6.4	Proceeds to be Turned Over To Collateral Agent	24
6.5	Application of Proceeds	24
6.6	Code and Other Remedies	25

6.7	Registration Rights	25
6.8	Subordination	26
6.9	Deficiency	26
6.10	Intercreditor Agreement	26

SECTION 7. The Collateral Agent		26

7.1	Collateral Agent’s Appointment as Attorney-in-Fact, etc.	26
7.2	Duty of Collateral Agent	28
7.3	Execution of Financing Statements	28
7.4	Authority of Collateral Agent	29
7.5	Intercreditor Agreement	29

SECTION 8. Miscellaneous

8.1	Amendments in Writing	29
8.2	Notices	29
8.3	No Waiver by Course of Conduct; Cumulative Remedies	29
8.4	Enforcement Expenses; Indemnification	30
8.5	Successors and Assigns	30
8.6	Set-Off; Limitation on Individual Actions	30
8.7	Counterparts	31
8.8	Severability	31
8.9	Section Headings	32
8.10	Integration	32
8.11	GOVERNING LAW	32
8.12	Submission To Jurisdiction; Waivers	32
8.13	Acknowledgements	33
8.14	Additional Grantors; Release of Guarantors; Releases of Collateral;	34
8.15	WAIVER OF JURY TRIAL	35
8.16	Amendment and Restatement	35
8.17	Reaffirmation and Grant of Security Interest	35

SCHEDULES

Schedule 1	—	Notice Address
Schedule 2	—	Investment Property
Schedule 3	—	Perfection Matters
Schedule 4	—	Jurisdictions of Organizational and Chief Executive Offices
Schedule 5	—	Intellectual Property

AMENDED AND RESTATED GUARANTEE AND COLLATERAL AGREEMENT

AMENDED AND RESTATED GUARANTEE AND COLLATERAL AGREEMENT, dated as of January 31, 2008 and amended and restated as of December 10, 2010, made by each of the signatories hereto (together with any other entity that may become a party hereto as provided herein, the “ Guarantors ”), in favor of GOLDMAN SACHS CREDIT PARTNERS L.P. (“ GSCP ”), as Collateral Agent (in such capacity, the “ Collateral Agent ”) for (i) the banks and other financial institutions or entities (the “ Existing Lenders ”) from time to time party to the Credit Agreement, dated as of January 31, 2008 (as amended, supplemented or otherwise modified from time to time, the “ Existing Credit Agreement ”), among CALPINE CORPORATION, (the “ Borrower ”), the Lenders, General Electric Capital Corporation (including its successors, “ GE Capital ”), as Sub-Agent for the Revolving Lenders thereunder (in such capacity and including any successors, the “ Sub-Agent ”), Credit Suisse, GSCP, Deutsche Bank Securities Inc. and Morgan Stanley Senior Funding, Inc., as co-documentation agents and as co-syndication agents, and GSCP, as the administrative agent (in such capacity, the “ Existing Administrative Agent ”) and Collateral Agent, (ii) the banks and other financial institutions or entities (the “ Permitted Revolving Lenders ”) from time to time party to the Credit Agreement, dated as of December 10, 2010 (as amended, supplemented or otherwise modified from time to time, the “ Revolving Credit Agreement ”), among the Borrower, the Permitted Revolving Lenders, Goldman Sachs Bank USA, as administrative agent (in such capacity, the “ Revolving Facility Administrative Agent ” and, together with the Existing Administrative Agent, the “ Administrative Agents ” and each an “ Administrative Agent ”), the Collateral Agent and the other parties thereto, and (iii) each other holder from time to time of First Lien Obligations other than those described in preceding clauses (i) and (ii) above.

W I T N E S S E T H :

WHEREAS, pursuant to the Existing Credit Agreement, the Existing Lenders have severally agreed to make extensions of credit to the Borrower upon the terms and subject to the conditions set forth therein;

WHEREAS, pursuant to the Existing Credit Agreement, the Borrower, the Guarantors and the Collateral Agent previously entered into that certain Guarantee and Collateral Agreement, dated as of January 31, 2008 (as heretofore amended, supplemented or otherwise modified from time to time, and in effect immediately before giving effect to the amendment and restatement thereof, the “ Existing Guarantee and Collateral Agreement ”);

WHEREAS, pursuant to the Revolving Credit Agreement, the Permitted Revolving Lenders have severally agreed to make extensions of credit to the Borrower upon the terms and subject to the conditions set forth therein;

WHEREAS, the Borrower is a member of an affiliated group of companies that includes each other Grantor;

WHEREAS, the proceeds of the extensions of credit under the Existing Credit Agreement and the Revolving Credit Agreement will be used in part to enable the Borrower to

make valuable transfers to one or more of the other Grantors in connection with the operation of their respective businesses;

WHEREAS, the Borrower and the other Grantors are engaged in related businesses, and each Grantor will derive substantial direct and indirect benefit from the making of the extensions of credit under the Existing Credit Agreement and the Revolving Credit Agreement;

WHEREAS, it is a condition precedent to the obligation of the Permitted Revolving Lenders to make their respective extensions of credit to the Borrower under the Revolving Credit Agreement that the Grantors shall have executed and delivered this Agreement to the Collateral Agent for the ratable benefit of the Secured Parties;

WHEREAS, the Grantors would also like to induce other creditors to make available from time to time First Lien Debt (other than as described above) subject to the terms of the Intercreditor Agreement;

WHEREAS, each of the Guarantors has agreed to guaranty the Obligations and to secure its respective Obligations by reaffirming its grant to Collateral Agent, for the benefit of the Secured Parties, of a first-priority security interest in the Collateral described herein; and

WHEREAS, it is the intent of the parties hereto that this Agreement not constitute a novation of the obligations and liabilities of the parties under the Existing Guarantee and Collateral Agreement and that this Agreement amend and restate in its entirety the Existing Guarantee and Collateral Agreement and re-evidence the Obligations as contemplated hereby.

NOW, THEREFORE, in consideration of the premises and to induce the Collateral Agent and the Existing Lenders to continue to make their respective extensions of credit to the Borrower under the Existing Credit Agreement, to induce the Collateral Agent and the Permitted Revolving Lenders to enter into the Revolving Credit Agreement, to induce the Permitted Revolving Lenders to make their respective extensions of credit to the Borrower under the Revolving Credit Agreement, and to induce other First Lien Secured Parties to extend additional First Lien Debt to the various Grantors, each Grantor hereby agrees with the Collateral Agent, for the ratable benefit of the Secured Parties, as follows:

SECTION 1. Defined Terms

1.1 Definitions . (a) Unless otherwise defined herein, capitalized terms used but not defined herein shall have the meanings given to them in the Existing Credit Agreement or, to the extent not defined therein or if the context otherwise requires, in the Revolving Credit Agreement (provided that, if neither the Existing Credit Agreement nor the Revolving Credit Agreement is outstanding, such terms shall have the meanings given to any substantially similar defined term in any Credit Agreement then in effect), and the following terms are used herein as defined in the New York UCC: Accounts (as defined in Article 9 of the New York UCC), Certificated Security, Chattel Paper, Commercial Tort Claims, Contract, Documents, Equipment, Farm Products, Fixture, General Intangibles, Goods, Instruments, Inventory, Letter-of-Credit Rights and Supporting Obligations.

(b) The following terms shall have the following meanings:

“ Agreement ”: this Guarantee and Collateral Agreement, as the same may be amended, supplemented or otherwise modified from time to time.

“ Borrower Obligations ”: the collective reference to (i) the unpaid principal of and interest on the Loans and Letter of Credit Outstandings and all other obligations and liabilities of the Borrower (including, without limitation, interest accruing at the then applicable rate provided in the applicable Credit Agreement after the maturity of the respective Loans and Letter of Credit Outstandings and interest accruing at the then applicable rate provided in the applicable Credit Agreement after the filing of any petition in bankruptcy, or the commencement of any insolvency, reorganization or like proceeding, relating to the Borrower, whether or not a claim for post-filing or post-petition interest is allowed in such proceeding) to each Administrative Agent, the Sub-Agent, the Collateral Agent or any Lender (or, in the case of any Specified Swap Agreement and Specified Cash Management Agreements, any Affiliate of any Lender), whether direct or indirect, absolute or contingent, due or to become due, or now existing or hereafter incurred, which may arise under, out of, or in connection with, any Credit Agreement, this Agreement, the other Loan Documents, any Letter of Credit, or any other document made, delivered or given in connection with any of the foregoing, in each case whether on account of principal, interest, premiums (if any), reimbursement obligations, fees, indemnities, costs, expenses or otherwise (including, without limitation, all fees and disbursements of counsel to the Collateral Agent or to the Lenders that are required to be paid by the Borrower pursuant to the terms of any of the foregoing agreements) and (ii) all other First Lien Obligations of the Borrower at any time incurred or outstanding.

“ Collateral ”: as defined in Section 3 .

“ Collateral Account ”: any collateral account established by the Collateral Agent as provided in Section 6.1 or Section 6.4 .

“ Copyrights ”: (i) all copyrights arising under the laws of the United States, any other country or any political subdivision thereof, whether registered or unregistered and whether published or unpublished (including, without limitation, those listed in Schedule 5 ), all registrations and recordings thereof, and all applications in connection therewith, including, without limitation, all registrations, recordings and applications in the United States Copyright Office, and (ii) the right to obtain all renewals thereof.

“ Copyright Licenses ”: any written agreement naming any Grantor as licensor or licensee (including, without limitation, those listed in Schedule 5 ), granting any right under any Copyright, including, without limitation, the grant of rights to manufacture, distribute, exploit and sell materials derived from any Copyright.

“ Credit Agreement ”: the collective reference to (i) the Existing Credit Agreement, (ii) the Revolving Credit Agreement and (iii) any other credit agreement, loan agreement, note agreement, promissory note, indenture or other agreement or instrument evidencing or governing the terms of any indebtedness or other financial accommodation that has been incurred to extend, increase, renew, refund, replace (whether upon or after termination

or otherwise) or refinance (including by means of sales of debt securities to institutional investors) in whole or in part from time to time the indebtedness and other obligations outstanding under the Existing Credit Agreement, the Revolving Credit Agreement or any other agreement or instrument referred to in this clause (iii); provided that any agreement or instrument described above in clause (iii) shall only constitute a “Credit Agreement” (or a portion thereof) if the respective agreement or instrument provides that such agreement or instrument (or indebtedness thereunder) shall constitute “First Lien Debt” for purposes of the Intercreditor Agreement (and so long as same satisfies the requirements of clause (2) of the definition of First Lien Debt contained in the Intercreditor Agreement) and the respective First Lien Representative shall have notified the Collateral Agent that such agreement or instrument shall constitute a Credit Agreement (or a portion thereof) and shall have executed and delivered to the Collateral Agent a joinder to the Intercreditor Agreement and the other actions specified in Sections 3.8(a) and (b) of the Intercreditor Agreement shall have been taken with respect to the relevant Series of Secured Debt (as each such term is defined in the Intercreditor Agreement) being issued or incurred. Any reference to a Credit Agreement hereunder shall be deemed a reference to any Credit Agreement then extant. Notwithstanding the foregoing, in no event shall any Permitted Notes Document (as defined in the Existing Credit Agreement) or any indenture governing the 2017 Notes, the 2019 Notes, the 2020 Notes or the 2021 Notes (as each such term is defined in the Revolving Credit Agreement) be deemed to constitute the Credit Agreement hereunder.

“ Default ”: any “Default” under, and as defined in, any then effective First Lien Document.

“ Deposit Account ”: as defined in the Uniform Commercial Code of any applicable jurisdiction and, in any event, including, without limitation, any demand, time, savings, passbook or like account maintained with a depositary institution.

“ Event of Default ”: any “Event of Default” (i) under, and as defined in, the Existing Credit Agreement, the Revolving Credit Agreement and/or under any other Credit Agreement, as applicable, or (ii) at such time as a Credit Agreement is no longer effective, under, and as defined in, any then effective First Lien Document.

“ First Lien Debt ”: as defined in the Intercreditor Agreement.

“ First Lien Documents ”: as defined in the Intercreditor Agreement.

“ First Lien Obligations ”: as defined in the Intercreditor Agreement.

“ First Lien Representative ”: as defined in the Intercreditor Agreement.

“ First Lien Secured Party ”: as defined in the Intercreditor Agreement.

“ First Lien Security Document ”: as defined in the Intercreditor Agreement.

“ Foreign Subsidiary ”: any Subsidiary organized under the laws of any jurisdiction outside the United States of America.

“ Foreign Subsidiary Voting Stock ”: the voting Capital Stock of any Foreign Subsidiary.

“ Funding Office ”: as such term is defined in each of the Existing Credit Agreement and the Revolving Credit Agreement, and as such term (or any other defined term having a similar purpose) is defined in any other Credit Agreement, as applicable.

“ Guaranteed Obligations ”: in (A) the case of the Borrower, all Other Loan Party Obligations of each Non-Borrower Guarantor and (B) the case of any Non-Borrower Guarantor, all Borrower Obligations and all Other Loan Party Obligations of each other Guarantor.

“ Guarantors ”: as defined in the preamble hereto.

“ Grantors ”: the collective reference to each Guarantor identified as a Grantor on Annex I to the signature page hereto, together with any other entity that may become a party hereto (and is identified as a Grantor) as provided herein.

“ Intellectual Property ”: the collective reference to all rights, priorities and privileges relating to intellectual property, whether arising under United States, multinational or foreign laws or otherwise, including, without limitation, the Copyrights, the Copyright Licenses, the Patents, the Patent Licenses, the Trademarks and the Trademark Licenses, and any transferable rights to sue at law or in equity for any infringement or other impairment thereof, including the right to receive all proceeds and damages therefrom.

“ Intercompany Note ”: any promissory note evidencing loans made by any Grantor to the Borrower or any of its Subsidiaries.

“ Intercreditor Agreement ”: the Collateral Agency and Intercreditor Agreement, dated as of January 31, 2008, as same may be amended, supplemented or otherwise modified from time to time.

“ Investment Property ”: the collective reference to (i) all “investment property” as such term is defined in Section 9-102(a)(49) of the New York UCC (other than any Foreign Subsidiary Voting Stock excluded from the definition of “Pledged Stock”) and (ii) whether or not constituting “investment property” as so defined, all Pledged Notes and all Pledged Stock.

“ Issuers ”: the collective reference to each issuer of any Investment Property.

“ Lenders ”: each Existing Lender, each Permitted Revolving Lender and/or each “Lender” (or any other defined term having a similar purpose) as defined in any other Credit Agreement, as applicable (including any institution acting as “Swingline Lender” under the Existing Credit Agreement or the Revolving Credit Agreement or in a substantially similar capacity under any other Credit Agreement, as applicable, and any “Fronting Bank” under the Existing Credit Agreement or the Revolving Credit Agreement or any “Issuing Bank” or similar letter of credit issuer under any other Credit Agreement, as applicable).

“ Letter of Credit ”: as such term is defined in each of the Existing Credit Agreement and the Revolving Credit Agreement, and as such term (or any other defined term having a similar purpose) is defined in any other Credit Agreement, as applicable.

“ Letter of Credit Outstandings ”: as such term is defined in each of the Existing Credit Agreement and the Revolving Credit Agreement, and as such term (or any other defined term having a similar purpose) is defined in any other Credit Agreement, as applicable.

“ Lien ”: as such term is defined in each of the Existing Credit Agreement and the Revolving Credit Agreement, and as such term (or any other defined term having a similar purpose) is defined in any other Credit Agreement, as applicable.

“ Loan Documents ”: as such term is defined in each of the Existing Credit Agreement and the Revolving Credit Agreement, and as such term (or any other defined term having a similar purpose) is defined in any other Credit Agreement, as applicable.

“ Loans ”: as such term is defined in each of the Existing Credit Agreement and the Revolving Credit Agreement, and as such term (or any other defined term having a similar purpose) is defined in any other Credit Agreement, as applicable.

“ New York UCC ”: the Uniform Commercial Code as from time to time in effect in the State of New York.

“ Non-Borrower Guarantor ”: each Guarantor other than the Borrower.

“ Obligations ”: (i) in the case of the Borrower, the Borrower Obligations, and (ii) in the case of each Non-Borrower Guarantor, its Other Loan Party Obligations.

“ Officer’s Certificate ”: a certificate of a Responsible Officer of the Borrower.

“ Original Closing Date ”: January 31, 2008.

“ Other Loan Party Obligations ”: with respect to any Non-Borrower Guarantor, all obligations and liabilities of such Guarantor which may arise under or in connection with this Agreement (including, without limitation, pursuant to Section 2 hereof), any Credit Agreement, any other Loan Document, or any other First Lien Document to which such Guarantor is a party, in each case whether on account of guarantee obligations, reimbursement obligations, fees, indemnities, costs, expenses or otherwise (including, without limitation, all fees and disbursements of counsel to the applicable Administrative Agent, the Collateral Agent or other relevant First Lien Secured Party, or to the Lenders or other First Lien Secured Parties that are required to be paid by such Guarantor pursuant to the terms of this Agreement, any Credit Agreement, any other Loan Document or any other First Lien Documents) and all other First Lien Obligations of such Guarantor.

“ Patents ”: (i) all letters patent of the United States, any other country or any political subdivision thereof, all reissues and extensions thereof and all goodwill associated therewith, including, without limitation, any of the foregoing referred to in Schedule 5 , (ii) all applications for letters patent of the United States or any other country and all divisions,

continuations and continuations-in-part thereof, including, without limitation, any of the foregoing referred to in Schedule 5 , and (iii) all rights to obtain any reissues or extensions of the foregoing.

“ Patent License ”: all agreements, whether written or oral, providing for the grant by or to any Grantor of any right to manufacture, use or sell any invention covered in whole or in part by a Patent, including, without limitation, any of the foregoing referred to in Schedule 5 .

“ Pledged Notes ”: all promissory notes listed on Schedule 2 , all Intercompany Notes at any time issued to any Grantor and all other promissory notes in principal amounts in excess of $500,000 issued to or held by any Grantor (other than promissory notes issued in connection with extensions of trade credit by any Grantor in the ordinary course of business).

“ Pledged Stock ”: the shares of Capital Stock listed on Schedule 2 , together with any other shares, stock certificates, options, interests or rights of any nature whatsoever in respect of the Capital Stock of any Person that may be issued or granted to, or held by, any Grantor while this Agreement is in effect; provided that in no event shall more than 65% of the total outstanding Foreign Subsidiary Voting Stock of any Foreign Subsidiary be required to be pledged hereunder.

“ Proceeds ”: all “proceeds” as such term is defined in Section 9-102(a)(64) of the New York UCC and, in any event, shall include, without limitation, all dividends or other income from the Investment Property, collections thereon or distributions or payments with respect thereto.

“ Receivable ”: any right to payment for goods sold or leased or for services rendered, whether or not such right is evidenced by an Instrument or Chattel Paper and whether or not it has been earned by performance (including, without limitation, any Account).

“ Responsible Officer ”: the chief executive officer, president, any executive vice president or financial officer of the Borrower.

“ Secured Debt Termination Date ”: as defined in the Intercreditor Agreement.

“ Secured Parties ”: the collective reference to the Collateral Agent, and all other First Lien Secured Parties.

“ Securities Act ”: the Securities Act of 1933, as amended.

“ Series of First Lien Debt ”: as defined in the Intercreditor Agreement.

“ Specified Cash Management Agreement ”: as such term is defined in each of the Existing Credit Agreement and the Revolving Credit Agreement, and as such term (or any other defined term having a similar purpose) is defined in any other Credit Agreement, as applicable.

“ Specified Swap Agreement ”: as such term is defined in each of the Existing Credit Agreement and the Revolving Credit Agreement, and as such term (or any other defined term having a similar purpose) is defined in any other Credit Agreement, as applicable.

“ Trademarks ”: (i) all trademarks, trade names, corporate names, company names, business names, fictitious business names, trade styles, service marks, logos and other source or business identifiers, and all goodwill associated therewith, all registrations and recordings thereof, and all applications in connection therewith (other than “intent to use” applications), whether in the United States Patent and Trademark Office or in any similar office or agency of the United States, any State thereof or any other country or any political subdivision thereof, or otherwise, and all common-law rights related thereto, including, without limitation, any of the foregoing referred to in Schedule 5 , and (ii) the right to obtain all renewals thereof.

“ Trademark License ”: any agreement, whether written or oral, providing for the grant by or to any Grantor of any right to use any Trademark, including, without limitation, any of the foregoing referred to in Schedule 5 .

1.2 Other Definitional Provisions . (a) The words “hereof,” “herein”, “hereto” and “hereunder” and words of similar import when used in this Agreement shall refer to this Agreement as a whole and not to any particular provision of this Agreement, and Section and Schedule references are to this Agreement unless otherwise specified.

(b) The meanings given to terms defined herein shall be equally applicable to both the singular and plural forms of such terms.

(c) Where the context requires, terms relating to the Collateral or any part thereof, when used in relation to a Grantor, shall refer to such Grantor’s Collateral or the relevant part thereof.

(d) Notwithstanding anything to the contrary in this Agreement or the Intercreditor Agreement, (i) “First Lien Debt” and “First Lien Obligations” as used in this Agreement shall include obligations incurred by Guarantors of the type described in clause (2) of the definition of “First Lien Debt” in the Intercreditor Agreement, so long as the requirements that would need to be satisfied for such obligations (if such obligations were instead incurred by Company and not a Guarantor) to constitute First Lien Debt are satisfied; (ii) “First Lien Secured Party” and “Secured Party” (and their respective plural forms) as used in this Agreement shall include any such Persons that hold First Lien Debt or First Lien Obligations incurred by Guarantors that are described in preceding clause (i) (it being understood that preceding clauses (i) and (ii) do not cause the Collateral of any Grantor to directly secure First Lien Obligations incurred by a Guarantor that is not a Grantor, but clarify that (x) each Guarantor’s Guaranteed Obligations include such First Lien Obligations and (y) each Grantor’s Obligations secured by its Collateral include such Grantor’s guaranty of the Guaranteed Obligations described in clause (x)); and (iii) the defined terms described in preceding clauses (i) and (ii) as used in this Agreement shall be construed as if such clauses were in effect at all times on and after the Original Closing Date.

SECTION 2. Guarantee

2.1 Guarantee . (a) Each of the Guarantors hereby, jointly and severally, absolutely, unconditionally and irrevocably, guarantees to the Collateral Agent (and hereby reaffirms its joint and several, absolute, unconditional and irrevocable guarantee under the

Existing Guarantee and Collateral Agreement, which continues hereunder without interruption, to the Collateral Agent), for the ratable benefit of the Secured Parties and their respective successors, indorsees, transferees and assigns, as a primary obligor and not merely as surety, the prompt and complete payment and performance when due (whether at the stated maturity, by acceleration or otherwise) of all Guaranteed Obligations.

(b) Without limiting the generality of paragraph 95 of the Confirmation Order, anything herein, or in any other First Lien Document to the contrary notwithstanding, the maximum liability of each Non-Borrower Guarantor hereunder shall be limited to such amount as will, after giving effect to such maximum liability and all other liabilities (contingent or otherwise) of such Guarantor that are relevant under applicable Federal or state bankruptcy or insolvency laws, fraudulent conveyance or transfer laws, or similar such laws, result in the obligations of such Guarantor hereunder not constituting a fraudulent transfer or conveyance under applicable Federal or state laws (after giving effect to all rights of subrogation, contribution or reimbursement, subject to Sections 2.3 and 8.12(i) ).

(c) Each Non-Borrower Guarantor agrees that the Guaranteed Obligations may at any time and from time to time exceed the amount of the liability of such Guarantor hereunder without impairing the guarantee contained in this Section 2 or affecting the rights and remedies of the Collateral Agent or any Secured Party hereunder.

(d) The guarantee contained in this Section 2 shall remain in full force and effect until the Secured Debt Termination Date with respect to the First Lien Debt shall have occurred, notwithstanding that from time to time during the term of any Credit Agreement or other First Lien Document the Borrower may be free from any Borrower Obligations.

(e) No payment made by the Borrower, any of the Non-Borrower Guarantors, any other guarantor or any other Person or received or collected by the Collateral Agent or any Secured Party from the Borrower, any of the Non-Borrower Guarantors, any other guarantor or any other Person by virtue of any action or proceeding or any set-off or appropriation or application at any time or from time to time in reduction of or in payment of the Guaranteed Obligations shall be deemed to modify, reduce, release or otherwise affect the liability of any Guarantor hereunder which shall, notwithstanding any such payment (other than any payment made by such Guarantor in respect of the Guaranteed Obligations or any payment received or collected from such Guarantor in respect of the Guaranteed Obligations), remain liable for the Guaranteed Obligations up to the maximum liability of such Guarantor hereunder until the Secured Debt Termination Date with respect to the First Lien Debt shall have occurred.

2.2 Right of Contribution . Each Non-Borrower Guarantor hereby agrees that to the extent that a Non-Borrower Guarantor shall have paid more than its proportionate share of any payment made hereunder, such Non-Borrower Guarantor shall be entitled to seek and receive contribution from and against any other Non-Borrower Guarantor hereunder which has not paid its proportionate share of such payment. Each Non-Borrower Guarantor’s right of contribution shall be subject to the terms and conditions of Section 2.3 . The provisions of this Section 2.2 shall in no respect limit the obligations and liabilities of any Guarantor to the Collateral Agent and the Secured Parties, and each Guarantor shall remain liable to the Collateral Agent and the Secured Parties for the full amount guaranteed by such Guarantor hereunder.

2.3 No Subrogation . Notwithstanding any payment made by any Guarantor hereunder or any set-off or application of funds of any Guarantor by the Collateral Agent or any Secured Party, no Guarantor shall be entitled to seek or enforce its right to be subrogated to any of the rights of the Collateral Agent or any Secured Party against the Borrower or any other Guarantor or any collateral security or guarantee or right of offset held by the Collateral Agent or any Secured Party for the payment of the Guaranteed Obligations, nor shall any Guarantor seek or be entitled to seek any contribution or reimbursement from the Borrower or any other Guarantor in respect of payments made by such Guarantor hereunder, until all amounts owing to the Collateral Agent and the Secured Parties by the Borrower on account of the Borrower Obligations are paid in full and the Secured Debt Termination Date with respect to the First Lien Debt shall have occurred. If any amount shall be paid to any Guarantor on account of such subrogation rights at any time when all of the Borrower Obligations shall not have been paid in full or such payment is otherwise prohibited pursuant to the immediately preceding sentence, such amount shall be held by such Guarantor in trust for the Collateral Agent and the Secured Parties, segregated from other funds of such Guarantor, and shall, forthwith upon receipt by such Guarantor, be turned over to the Collateral Agent in the exact form received by such Guarantor (duly indorsed by such Guarantor to the Collateral Agent, if required), to be applied against the Borrower Obligations, whether matured or unmatured, in such order as the Collateral Agent may determine.

2.4 Amendments, etc. with respect to the Guaranteed Obligations . Each Guarantor shall remain obligated hereunder notwithstanding that, without any reservation of rights against any Guarantor and without notice to or further assent by any Guarantor, any demand for payment of any of the Guaranteed Obligations made by the Collateral Agent or any other Secured Party may be rescinded by the Collateral Agent or such Secured Party and any of the Guaranteed Obligations may be continued, and the Guaranteed Obligations, or the liability of any other Person upon or for any part thereof, or any collateral security or guarantee therefor or right of offset with respect thereto, may, from time to time, in whole or in part, be renewed, extended, amended, modified, accelerated, compromised, waived, surrendered or released by the Collateral Agent or any Secured Party, and the First Lien Documents and any other documents executed and delivered in connection therewith may be amended, modified, supplemented or terminated, in whole or in part, as the Collateral Agent (or the relevant Secured Parties, as the case may be) may deem advisable from time to time, and any collateral security, guarantee or right of offset at any time held by the Collateral Agent or any Secured Party for the payment of the Guaranteed Obligations may be sold, exchanged, waived, surrendered or released. Neither the Collateral Agent nor any Lender nor any Secured Party shall have any obligation to protect, secure, perfect or insure any Lien at any time held by it as security for the Guaranteed Obligations or for the guarantee contained in this Section 2 or any property subject thereto.

2.5 Guarantee Absolute and Unconditional . Each Guarantor waives any and all notice of the creation, renewal, extension or accrual of any of the Guaranteed Obligations and notice of or proof of reliance by the Collateral Agent or any other Secured Party upon the guarantee contained in this Section 2 or acceptance of the guarantee contained in this Section 2 ; the Guaranteed Obligations, and any of them, shall conclusively be deemed to have been created, contracted or incurred, or renewed, extended, amended or waived, in reliance upon the guarantee contained in this Section 2 ; and all dealings between the Borrower and any of the Guarantors, on the one hand, and the Collateral Agent and the Secured Parties, on the other hand, likewise shall

be conclusively presumed to have been had or consummated in reliance upon the guarantee contained in this Section 2 . Each Guarantor waives diligence, presentment, protest, demand for payment and notice of default or nonpayment to or upon the Borrower or any of the Non-Borrower Guarantors with respect to the Guaranteed Obligations. Each Guarantor understands and agrees that the guarantee contained in this Section 2 shall be construed as a continuing, absolute and unconditional guarantee of payment without regard to (a) the validity or enforceability of any First Lien Documents, any of the Guaranteed Obligations or any other collateral security therefor or guarantee or right of offset with respect thereto at any time or from time to time held by the Collateral Agent or any other Secured Party, (b) any defense, set-off or counterclaim (other than a defense of payment or performance) which may at any time be available to or be asserted by the Borrower or any other Person against the Collateral Agent or any other Secured Party, or (c) any other circumstance whatsoever (with or without notice to or knowledge of the Borrower, such Guarantor or any other Guarantor) which constitutes, or might be construed to constitute, an equitable or legal discharge of the Borrower or any other obligor for the Guaranteed Obligations, or of such Guarantor under the guarantee contained in this Section 2 , in bankruptcy or in any other instance. When making any demand hereunder or otherwise pursuing its rights and remedies hereunder against any Guarantor, the Collateral Agent or any other Secured Party may, but shall be under no obligation to, make a similar demand on or otherwise pursue such rights and remedies as it may have against the Borrower, any other Guarantor or any other Person or against any collateral security or guarantee for the Guaranteed Obligations or any right of offset with respect thereto, and any failure by the Collateral Agent or any other Secured Party to make any such demand, to pursue such other rights or remedies or to collect any payments from the Borrower, any other Guarantor or any other Person or to realize upon any such collateral security or guarantee or to exercise any such right of offset, or any release of the Borrower, any other Guarantor or any other Person or any such collateral security, guarantee or right of offset, shall not relieve any Guarantor of any obligation or liability hereunder, and shall not impair or affect the rights and remedies, whether express, implied or available as a matter of law, of the Collateral Agent or any other Secured Party against any Guarantor. For the purposes hereof “demand” shall include the commencement and continuance of any legal proceedings.

2.6 Reinstatement . Without limiting the generality of paragraph 95 of the Confirmation Order, the guarantee contained in this Section 2 shall continue to be effective, or be reinstated, as the case may be, if at any time payment, or any part thereof, of any of the Guaranteed Obligations is rescinded or must otherwise be restored or returned by the Collateral Agent or any other Secured Party upon the insolvency, bankruptcy, dissolution, liquidation or reorganization of the Borrower or any Non-Borrower Guarantor, or upon or as a result of the appointment of a receiver, intervenor or conservator of, or trustee or similar officer for, the Borrower or any Non-Borrower Guarantor or any substantial part of its property, or otherwise, all as though such payments had not been made.

2.7 Payments . Each Guarantor hereby jointly and severally guarantees that payments hereunder will be paid to the applicable Administrative Agent without set-off or counterclaim in Dollars at the applicable Funding Office.

SECTION 3. Grant of Security Interest

Each Grantor hereby assigns and transfers to the Collateral Agent, and hereby grants to the Collateral Agent, for the ratable benefit of the Secured Parties, a security interest in (and hereby reaffirms its assignment, transfer and grant under the Existing Guarantee and Collateral Agreement, which continues hereunder without interruption, to the Collateral Agent, for the ratable benefit of the Secured Parties, of a security interest in), all of the following property now owned or at any time hereafter acquired by such Grantor or in which such Grantor now has or at any time in the future may acquire any right, title or interest (collectively, the “ Collateral ”), as collateral security for the prompt and complete payment and performance when due (whether at the stated maturity, by acceleration or otherwise) of such Grantor’s Obligations:

(a) all Accounts;

(b) all Chattel Paper;

(d) all Deposit Accounts and cash;

(e) all Documents;

(f) all Equipment;

(g) all Fixtures;

(h) all General Intangibles;

(i) all Instruments;

(j) all Intellectual Property;

(k) all Inventory;

(l) all Goods;

(m) all Investment Property;

(n) all Letter-of-Credit Rights;

(o) all Commercial Tort Claims described in Section 5.8 hereof;

(p) all books and records pertaining to the Collateral; and

(q) to the extent not otherwise included, all Proceeds, Supporting Obligations and products of any and all of the foregoing and all collateral security and guarantees given by any Person with respect to any of the foregoing;

provided , however , that notwithstanding any of the other provisions set forth in this Section 3 , this Agreement shall not constitute a grant of a security interest in (i) any property to the extent that such grant of a security interest is prohibited by any Requirements of Law of a Governmental Authority, requires a consent not obtained of any Governmental Authority pursuant to such Requirement of Law or is prohibited by, or constitutes a breach or default under or results in the termination of or requires any consent not obtained under, any contract, license, agreement, instrument or other document evidencing or giving rise to such property or, in the case of any Investment Property, Pledged Stock or Pledged Note, any applicable shareholder or similar agreement, except to the extent that such Requirement of Law or the term in such contract, license, agreement, instrument or other document or shareholder or similar agreement providing for such prohibition, breach, default or termination or requiring such consent is ineffective under applicable law; or (ii) any voting Capital Stock of any Foreign Subsidiary (or Domestic Subsidiary of the type described in clause (d) of the definition of Excluded Subsidiary) constituting more than 65% of the outstanding voting Capital Stock thereof; or (iii) any Capital Stock of any Project Subsidiary whose Capital Stock is pledged to secure Limited Recourse Debt so long as such Limited Recourse Debt remains outstanding, in each case so long as the respective Lien and Indebtedness described in this clause (iii) is permitted pursuant to each Credit Agreement, and does not violate the provisions of any other First Lien Document.

SECTION 4. Representations and Warranties

To induce the Collateral Agent and the Existing Lenders to continue to make their respective extensions of credit pursuant to the Existing Credit Agreement, to induce the Permitted Revolving Lenders to make their respective extensions of credit to the Borrower under the Revolving Credit Agreement, and to induce other Secured Parties to extend First Lien Obligations, each Grantor hereby represents and warrants to the Collateral Agent and each Secured Party that:

4.1 Title; No Other Liens . Except for the security interest granted to the Collateral Agent for the ratable benefit of the Secured Parties pursuant to this Agreement and the other Liens permitted to exist on the Collateral under each then outstanding First Lien Document (including the Liens granted to secure any Junior Lien Indebtedness (as defined in each of the Existing Credit Agreement and the Revolving Credit Agreement and/or any other defined term having a similar purpose in any other Credit Agreement)), such Grantor owns, or has rights in, each item of the Collateral free and clear of any and all Liens or claims of others. No effective financing statement or other public notice with respect to all or any part of the Collateral is on file or of record in any public office, except such as have been filed in favor of the Collateral Agent, for the ratable benefit of the Secured Parties, pursuant to this Agreement or as are permitted by each Credit Agreement. For the avoidance of doubt, it is understood and agreed that any Grantor may, as part of its business, grant licenses to third parties to use Intellectual Property owned or developed by a Grantor. For purposes of this Agreement and the other First Lien Documents, such licensing activity shall not constitute a “Lien” on such Intellectual Property. Each of the Collateral Agent and each Secured Party understand that any such licenses may be exclusive to the applicable licensees, and such exclusivity provisions may limit the ability of the Collateral Agent to utilize, sell, lease or transfer the related Intellectual Property or otherwise realize value from such Intellectual Property pursuant hereto.

4.2 Perfected First Priority Liens . The security interests granted pursuant to this Agreement (a) upon completion of the filings and other actions specified on Schedule 3 (which, in the case of all filings and other documents referred to on said Schedule, have been delivered to the Collateral Agent in completed and duly executed form) will constitute valid perfected security interests in all of the Collateral for which such filings and actions are effective to perfect such security interests in favor of the Collateral Agent, for the ratable benefit of the Secured Parties, as collateral security for such Grantor’s Obligations, enforceable in accordance with the terms hereof against all creditors of such Grantor and any Persons purporting to purchase any Collateral from such Grantor, except such Persons who are good faith purchasers to the extent set forth in the New York UCC and (b) are prior to all other Liens on the Collateral in existence on the Original Closing Date except for unrecorded Liens permitted by each Credit Agreement which have priority over the Liens on the Collateral by operation of law or as otherwise permitted to have priority over the Liens on the Collateral under Section 6.2 of the Existing Credit Agreement and Section 6.2 of the Revolving Credit Agreement (and any similar provision of any other Credit Agreement).

4.3 Jurisdiction of Organization; Chief Executive Office . On the date hereof, such Grantor’s jurisdiction of organization, identification number from the jurisdiction of organization (if any), and the location of such Grantor’s chief executive office or sole place of business, as the case may be, are specified on Schedule 4 . Such Grantor has furnished to the Collateral Agent a certified charter, certificate of incorporation or other organization document and long-form good standing certificate as of a date which is recent to the date hereof.

4.4 Farm Products . None of the Collateral constitutes, or is the Proceeds of, Farm Products.

4.5 Investment Property . (a) The shares of Pledged Stock pledged by such Grantor hereunder constitute all the issued and outstanding shares of all classes of the Capital Stock of each Issuer owned by such Grantor or, in the case of Foreign Subsidiary Voting Stock, if less, 65% of the outstanding Foreign Subsidiary Voting Stock of each relevant Issuer.

(b) All the shares of the Pledged Stock issued by an Issuer which is a Subsidiary of such Grantor have been duly and validly issued and are, if such shares are shares of stock in a domestic corporation, fully paid and nonassessable.

(c) Each of the Pledged Notes issued by an Issuer which is a Subsidiary of such Grantor constitutes the legal, valid and binding obligation of the obligor with respect thereto, enforceable in accordance with its terms, subject to the effects of bankruptcy, insolvency, fraudulent conveyance, reorganization, moratorium and other similar laws relating to or affecting creditors’ rights generally, general equitable principles (whether considered in a proceeding in equity or at law) and an implied covenant of good faith and fair dealing.

(d) Such Grantor is the owner of, and has good title to, the Investment Property pledged by it hereunder, free of any and all Liens or options in favor of, or claims of, any other Person, except the security interest created by this Agreement or as otherwise permitted under Section 6.2 of the Existing Credit Agreement and Section 6.2 of the Revolving Credit Agreement (and any similar provision of any other Credit Agreement).

4.6 Receivables . (a) No amount in excess of $500,000 payable to such Grantor under or in connection with any Receivable is evidenced by any Instrument or Chattel Paper which has not been delivered to the Collateral Agent.

(b) The amounts represented by such Grantor to the Lenders from time to time as owing to such Grantor in respect of the Receivables will at such times be accurate in all material respects.

4.7 Intellectual Property . (a) Schedule 5 lists all Intellectual Property owned by such Grantor in its own name on the date hereof and which is registered with the United States Copyright Office or the United States Patent and Trademark Office or any similar office or agency in any other country or any political subdivision thereof.

(b) On the date hereof, all material scheduled Intellectual Property owned, used or held by such Grantor is valid, subsisting, unexpired and in full force and effect, has not been abandoned and does not infringe the intellectual property rights of any other Person.

(c) No holding, decision or judgment has been rendered by any Governmental Authority which would limit, cancel or question the validity of, or such Grantor’s rights in, any Intellectual Property owned, used or held by such Grantor in any respect that could reasonably be expected to have a Material Adverse Effect.

(d) No action or proceeding is pending, or, to the knowledge of such Grantor, threatened, on the date hereof (i) seeking to limit, cancel or question the validity of any Intellectual Property owned, used or held by such Grantor or such Grantor’s ownership interest therein, or (ii) which, if adversely determined, would could reasonably be expected to have a Material Adverse Effect.

4.8 Commercial Tort Claims . (a) On the date hereof, except to the extent listed in Section 3.1 above, no Grantor has rights in any Commercial Tort Claim with a reasonably expected value in excess of $1,000,000.

(b) Upon the filing of a financing statement specifically describing any Commercial Tort Claim referred to in Section 5.8 hereof against such Grantor in the jurisdiction specified in Schedule 3 hereto, the security interest granted in such Commercial Tort Claim will constitute a valid perfected security interest in favor of the Collateral Agent, for the ratable benefit of the Secured Parties, as collateral security for such Grantor’s Obligations, enforceable in accordance with the terms hereof against all creditors of such Grantor and any Persons purporting to purchase such Collateral from Grantor except such Persons who are good faith purchasers to the extent set forth in the New York UCC, which security interest shall be prior to all other Liens on such Collateral except for unrecorded Liens permitted by each Credit Agreement which have priority over the Liens on such Collateral by operation of law or as otherwise permitted to have priority over the Liens on the Collateral under the relevant provisions of the then effective First Lien Documents.

4.9 Amendment and Restatement . This Agreement constitutes an amendment of the Existing Guarantee and Collateral Agreement made under and in accordance with the terms

of Section 9.1 of the Existing Credit Agreement, Section 8.1 of the Existing Guarantee and Collateral Agreement and Section 8.1 of the Intercreditor Agreement.

SECTION 5. Covenants

Each Grantor covenants and agrees with the Collateral Agent and the Secured Parties that, from and after the date of this Agreement and until the Secured Debt Termination Date with respect to the First Lien Debt:

5.1 Delivery of Instruments, Certificated Securities and Chattel Paper . If any amount in excess of $500,000 payable to a Grantor under or in connection with any of the Collateral shall be or become evidenced by any Instrument, Certificated Security or Chattel Paper, such Instrument, Certificated Security or Chattel Paper shall be immediately delivered to the Collateral Agent, duly indorsed in a manner satisfactory to the Collateral Agent, to be held as Collateral pursuant to this Agreement.

5.2 Maintenance of Insurance . (a) Such Grantor will maintain, with financially sound and reputable companies, insurance policies insuring such Grantor and the Collateral Agent against liability for personal injury and property damage relating to Inventory and Equipment, such policies to be in such form and amounts and having such coverage as may be reasonably satisfactory to the Collateral Agent.

(b) All such insurance shall (i) name the Collateral Agent as an additional insured party or loss payee and (ii) be reasonably satisfactory in all other respects to the Collateral Agent.

(c) The Borrower shall deliver to the Collateral Agent a report of a reputable insurance broker with respect to such insurance substantially concurrently with each delivery of the Borrower’s audited annual financial statements and such supplemental reports with respect thereto as the Collateral Agent may from time to time reasonably request.

5.3 Maintenance of Perfected Security Interest; Further Documentation . (a) Such Grantor shall maintain the security interest created by this Agreement as a perfected security interest having at least the priority described in Section 4.2 and shall defend such security interest against the claims and demands of all Persons whomsoever, subject to the rights of such Grantor under the First Lien Documents to dispose of the Collateral.

(b) Such Grantor will furnish to the Collateral Agent and the Lenders from time to time statements and schedules further identifying and describing the assets and property of such Grantor and such other reports in connection therewith as the Collateral Agent may reasonably request, all in reasonable detail.

(c) At any time and from time to time, upon the written request of the Collateral Agent, and at the sole expense of such Grantor, such Grantor will promptly and duly execute and deliver, and have recorded, such further instruments and documents and take such further actions as the Collateral Agent may reasonably request for the purpose of obtaining or preserving the full benefits of this Agreement and of the rights and powers herein granted, including, without limitation, (i) filing any financing or continuation statements under the

Uniform Commercial Code (or other similar laws) in effect in any jurisdiction with respect to the security interests created hereby and (ii) in the case of Investment Property, Deposit Accounts, Letter-of-Credit Rights and any other relevant Collateral, taking any actions necessary to enable the Collateral Agent to obtain “control” (within the meaning of the applicable Uniform Commercial Code) with respect thereto.

5.4 Changes in Name, etc . Such Grantor will not, except upon 15 days’ prior written notice to the Collateral Agent and delivery to the Collateral Agent of all additional financing statements and other executed documents reasonably requested by the Collateral Agent to maintain the validity, perfection and priority of the security interests provided for herein, (i) change its jurisdiction of organization or the location of its chief executive office or sole place of business from that referred to in Section 4.3 or (ii) change its name.

5.5 Notices . Such Grantor will advise the Collateral Agent and the Lenders promptly, in reasonable detail, of:

(a) any Lien (other than security interests created hereby or Liens permitted under the First Lien Documents) on any of the Collateral which would adversely affect the ability of the Collateral Agent to exercise any of its remedies hereunder; and

(b) of the occurrence of any other event which could reasonably be expected to have a material adverse effect on the aggregate value of the Collateral or on the security interests created hereby.

5.6 Investment Property . (a) If such Grantor shall become entitled to receive or shall receive any certificate (including, without limitation, any certificate representing a dividend or a distribution in connection with any reclassification, increase or reduction of capital or any certificate issued in connection with any reorganization), option or rights in respect of the Capital Stock (constituting Collateral hereunder) of any Issuer, whether in addition to, in substitution of, as a conversion of, or in exchange for, any shares of the Pledged Stock, or otherwise in respect thereof, such Grantor shall accept the same as the agent of the Collateral Agent and the Secured Parties, hold the same in trust for the Collateral Agent and the Secured Parties and deliver the same forthwith to the Collateral Agent in the exact form received, duly indorsed by such Grantor to the Collateral Agent, if required, together with an undated stock power covering such certificate duly executed in blank by such Grantor and with, if the Collateral Agent so requests, signature guaranteed, to be held by the Collateral Agent, subject to the terms hereof, as additional collateral security for the Obligations. Any sums paid upon or in respect of the Investment Property constituting Collateral hereunder upon the liquidation or dissolution of any Issuer shall be paid over to the Collateral Agent to be held by it hereunder as additional collateral security for the Obligations, and in case any distribution of capital shall be made on or in respect of such Investment Property or any property shall be distributed upon or with respect to such Investment Property pursuant to the recapitalization or reclassification of the capital of any Issuer or pursuant to the reorganization thereof, the property so distributed shall, unless otherwise subject to a perfected security interest in favor of the Collateral Agent, be delivered to the Collateral Agent to be held by it hereunder as additional collateral security for the Obligations. If any sums of money or property so paid or distributed in respect of such Investment Property shall be received by such Grantor, such Grantor shall, until such money or

property is paid or delivered to the Collateral Agent, hold such money or property in trust for the Collateral Agent and the Secured Parties, segregated from other funds of such Grantor, as additional collateral security for the Obligations.

(b) Without the prior written consent of the Collateral Agent or except as permitted under each Credit Agreement, such Grantor will not (i) vote to enable, or take any other action to permit, any Issuer to issue any Capital Stock of any nature or to issue any other securities convertible into or granting the right to purchase or exchange for any Capital Stock of any nature of any Issuer, unless all such Capital Stock is pledged by such Grantor to the Collateral Agent, for the ratable benefit of the Secured Parties, to the extent such pledge is required under this Agreement or any other First Lien Document, (ii) sell, assign, transfer, exchange, or otherwise dispose of, or grant any option with respect to, the Investment Property or Proceeds thereof constituting Collateral hereunder (except pursuant to a transaction that is permitted by the then effective First Lien Documents), (iii) create, incur or permit to exist any Lien or option in favor of, or any claim of any Person with respect to, any of the Investment Property or Proceeds thereof constituting Collateral hereunder, or any interest therein, except for the security interests created by this Agreement or (iv) enter into any agreement or undertaking restricting the right or ability of such Grantor or the Collateral Agent to sell, assign or transfer any of the Investment Property or Proceeds thereof.

(c) In the case of each Grantor which is an Issuer, such Issuer agrees that (i) it will be bound by the terms of this Agreement relating to the Investment Property issued by it and will comply with such terms insofar as such terms are applicable to it, (ii) it will notify the Collateral Agent promptly in writing of the occurrence of any of the events described in Section 5.6(a) with respect to the Investment Property issued by it and (iii) the terms of Sections 6.3(c) and 6.7 shall apply to it, mutatis mutandis , with respect to all actions that may be required of it pursuant to Section 6.3(c) or 6.7 with respect to the Investment Property issued by it.

5.7 Intellectual Property . (a) Except in such Grantor’s reasonable business judgment, each Grantor will not knowingly do any act or knowingly omit to do any act whereby any material Trademark constituting Collateral hereunder may become invalidated or impaired in any way.

(b) Except in such Grantor’s reasonable business judgment, each Grantor will not knowingly do any act, or knowingly omit to do any act, that could reasonably be expected cause any material Patent owned, used or held by such Grantor to become forfeited, abandoned or dedicated to the public.

(c) Except in such Grantor’s reasonable business judgment, each Grantor will not knowingly do any act or knowingly omit to do any act whereby any material portion of the Copyrights owned, used or held by such Grantor may become invalidated or otherwise impaired nor knowingly do any act whereby any material portion of the Copyrights owned, used or held by such Grantor may fall into the public domain.

(d) Such Grantor will not do any act that knowingly uses any material Intellectual Property owned by such Grantor to infringe the intellectual property rights of any other Person.

(e) Such Grantor will notify the Collateral Agent promptly if it knows, or has reason to know, that any application or registration relating to any material Intellectual Property owned by such Grantor has become forfeited, abandoned or dedicated to the public, or of any adverse determination or development (including, without limitation, the institution of, or any such determination or development in, any proceeding in the United States Patent and Trademark Office, the United States Copyright Office or any court or tribunal in any country) regarding such Grantor’s ownership of, or the validity of, any material Intellectual Property constituting Collateral hereunder or such Grantor’s right to register the same or to own and maintain the same.

(f) Whenever such Grantor, either by itself or through any agent, employee, licensee or designee, shall file an application for the registration of any material Intellectual Property with the United States Patent and Trademark Office, the United States Copyright Office or any similar office or agency in any other country or any political subdivision thereof, such Grantor shall report such filing to the Collateral Agent within five Business Days after the last day of the fiscal quarter in which such filing occurs. Upon request of the Collateral Agent, such Grantor shall execute and deliver, and have recorded, any and all agreements, instruments, documents, and papers as the Collateral Agent may request to evidence the Collateral Agent’s and the Secured Parties’ security interest in such Copyright, Patent or Trademark and the goodwill and general intangibles of such Grantor relating thereto or represented thereby.

(g) Except in such Grantor’s reasonable business judgment, each Grantor will take all reasonable and necessary steps, including, without limitation, in any proceeding before the United States Patent and Trademark Office, the United States Copyright Office or any similar office or agency in any other country or any political subdivision thereof, to maintain and pursue each application (and to obtain the relevant registration) and to maintain each registration of the material Intellectual Property constituting Collateral hereunder, including, without limitation, filing of applications for renewal, affidavits of use and affidavits of incontestability.

(h) In the event that any material Intellectual Property constituting Collateral hereunder is infringed, misappropriated or diluted by a third party, such Grantor shall take such actions as such Grantor shall reasonably deem appropriate under the circumstances to protect such Intellectual Property including, without limitation, in such Grantor’s reasonable business judgment, suing for infringement, misappropriation or dilution, to seek injunctive relief and seeking to recover any and all damages for such infringement, misappropriation or dilution.

5.8 Commercial Tort Claims . If such Grantor shall obtain an interest in any Commercial Tort Claim with a reasonably expected value in excess of $1,000,000, such Grantor shall within (45) days of obtaining such interest advise the Collateral Agent thereof and, if requested by the Collateral Agent in writing, within 30 days after such request sign and deliver documentation acceptable to the Collateral Agent granting a security interest under the terms and provisions of this Agreement in and to such Commercial Tort Claim.

SECTION 6. Remedial Provisions

6.1 Certain Matters Relating to Receivables . (a) The Collateral Agent shall have the right at reasonable times and with reasonable notice to make test verifications of the Receivables constituting Collateral hereunder in any manner and through any medium that it reasonably considers advisable, and each Grantor shall furnish all such assistance and information as the Collateral Agent may reasonably require in connection with such test verifications. At any time (but no more frequently than once per fiscal year (unless an Event of Default shall have occurred and be continuing, in which case there shall be no limits), upon the Collateral Agent’s request and at the expense of the relevant Grantor, such Grantor shall use commercially reasonable efforts to cause independent public accountants or others satisfactory to the Collateral Agent to furnish to the Collateral Agent reports showing reconciliations, aging and test verifications of, and trial balances for, the Receivables constituting Collateral hereunder.

(b) The Collateral Agent hereby authorizes each Grantor to collect such Grantor’s Receivables, subject to the Collateral Agent’s direction and control, and the Collateral Agent may curtail or terminate said authority at any time after the occurrence and during the continuance of an Event of Default. If required by the Collateral Agent at any time after the occurrence and during the continuance of an Event of Default, any payments of Receivables, when collected by any Grantor, (i) shall be forthwith (and, in any event, within three Business Days) deposited by such Grantor in the exact form received, duly indorsed by such Grantor to the Collateral Agent if required, in a Collateral Account maintained under the sole dominion and control of the Collateral Agent, subject to withdrawal by the Collateral Agent for the account of the Secured Parties only as provided in Section 6.5 , and (ii) until so turned over, shall be held by such Grantor in trust for the Collateral Agent and the Secured Parties, segregated from other funds of such Grantor. Each such deposit of Proceeds of Receivables shall be accompanied by a report identifying in reasonable detail the nature and source of the payments included in the deposit.

(c) At the Collateral Agent’s request after the occurrence and during the continuance of an Event of Default, each Grantor shall deliver to the Collateral Agent all original and other documents evidencing, and relating to, the agreements and transactions which gave rise to the Receivables constituting Collateral hereunder, including, without limitation, all original orders, invoices and shipping receipts.

6.2 Communications with Obligors; Grantors Remain Liable . (a) The Collateral Agent in its own name or in the name of others may at any time after the occurrence and during the continuance of an Event of Default communicate with obligors under the Receivables constituting Collateral hereunder and parties to the Contracts constituting Collateral hereunder to verify with them to the Collateral Agent’s satisfaction the existence, amount and terms of any such Receivables or Contracts.

(b) Upon the request of the Collateral Agent at any time after the occurrence and during the continuance of an Event of Default, each Grantor shall notify obligors on the Receivables constituting Collateral hereunder and parties to the Contracts constituting Collateral hereunder that such Receivables and the Contracts have been assigned to the Collateral Agent for

the ratable benefit of the Secured Parties and that payments in respect thereof shall be made directly to the Collateral Agent.

(c) Anything herein to the contrary notwithstanding, each Grantor shall remain liable under each of the Receivables and Contracts to observe and perform all the conditions and obligations to be observed and performed by it thereunder, all in accordance with the terms of any agreement giving rise thereto. Neither the Collateral Agent nor any Secured Party shall have any obligation or liability under any Receivable (or any agreement giving rise thereto) or Contract by reason of or arising out of this Agreement or the receipt by the Collateral Agent or any Secured Party of any payment relating thereto, nor shall the Collateral Agent or any Secured Party be obligated in any manner to perform any of the obligations of any Grantor under or pursuant to any Receivable (or any agreement giving rise thereto) or Contract, to make any payment, to make any inquiry as to the nature or the sufficiency of any payment received by it or as to the sufficiency of any performance by any party thereunder, to present or file any claim, to take any action to enforce any performance or to collect the payment of any amounts which may have been assigned to it or to which it may be entitled at any time or times.

6.3 Pledged Stock . (a) Unless an Event of Default shall have occurred and be continuing and the Collateral Agent shall have given written notice to the relevant Grantor of the Collateral Agent’s intent to exercise its corresponding rights pursuant to Section 6.3(b) , each Grantor shall be permitted to receive all cash dividends paid in respect of the Pledged Stock and all payments made in respect of the Pledged Notes, in each case paid in the normal course of business of the relevant Issuer and consistent with past practice, to the extent permitted in each Credit Agreement, and to exercise all voting and corporate or other organizational rights with respect to the Investment Property; provided that no vote shall be cast or corporate or other organizational right exercised or other action taken which, in the Collateral Agent’s reasonable judgment, would materially impair the Collateral or which would be inconsistent with or result in any violation of any provision of any Credit Agreement, this Agreement or any other First Lien Document.

(b) If an Event of Default shall occur and be continuing and the Collateral Agent shall give written notice of its intent to exercise such rights to the relevant Grantor or Grantors, (i) the Collateral Agent shall have the right to receive any and all cash dividends, payments or other Proceeds paid in respect of the Investment Property constituting Collateral hereunder and make application thereof to the Obligations in such order as the Collateral Agent may determine, and (ii) any or all of the Investment Property shall be registered in the name of the Collateral Agent or its nominee, and the Collateral Agent or its nominee may thereafter exercise (x) all voting, corporate and other rights pertaining to such Investment Property at any meeting of shareholders of the relevant Issuer or Issuers or otherwise and (y) any and all rights of conversion, exchange and subscription and any other rights, privileges or options pertaining to such Investment Property as if it were the absolute owner thereof (including, without limitation, the right to exchange at its discretion any and all of the Investment Property constituting Collateral hereunder upon the merger, consolidation, reorganization, recapitalization or other fundamental change in the corporate or other organizational structure of any Issuer, or upon the exercise by any Grantor or the Collateral Agent of any right, privilege or option pertaining to such Investment Property, and in connection therewith, the right to deposit and deliver any and all of such Investment Property with any committee, depositary, transfer agent, registrar or other

designated agency upon such terms and conditions as the Collateral Agent may determine), all without liability except to account for property actually received by it, but the Collateral Agent shall have no duty to any Grantor to exercise any such right, privilege or option and shall not be responsible for any failure to do so or delay in so doing.

(c) Each Grantor hereby authorizes and instructs each Issuer of any Investment Property pledged by such Grantor hereunder to (i) comply with any instruction received by it from the Collateral Agent in writing that (x) states that an Event of Default has occurred and is continuing and (y) is otherwise in accordance with the terms of this Agreement, without any other or further instructions from such Grantor, and each Grantor agrees that each Issuer shall be fully protected in so complying, and (ii) unless otherwise expressly permitted hereby, pay any dividends or other payments with respect to the Investment Property directly to the Collateral Agent.

6.4 Proceeds to be Turned Over To Collateral Agent . In addition to the rights of the Collateral Agent and the Secured Parties specified in Section 6.1 with respect to payments of Receivables, if an Event of Default shall occur and be continuing, all Proceeds received by any Grantor consisting of cash, checks and other near-cash items shall be held by such Grantor in trust for the Collateral Agent and the Secured Parties, segregated from other funds of such Grantor, and shall, forthwith upon receipt by such Grantor, be turned over to the Collateral Agent in the exact form received by such Grantor (duly indorsed by such Grantor to the Collateral Agent, if required). All Proceeds constituting Collateral hereunder received by the Collateral Agent hereunder shall be held by the Collateral Agent in a Collateral Account maintained under its sole dominion and control. All Proceeds constituting Collateral hereunder while held by the Collateral Agent in a Collateral Account (or by such Grantor in trust for the Collateral Agent and the Secured Parties) shall continue to be held as collateral security for all the Obligations and shall not constitute payment thereof until applied as provided in Section 6.5 .

6.5 Application of Proceeds . At such intervals as may be agreed upon by the Borrower and the Collateral Agent, or, if an Event of Default shall have occurred and be continuing, at any time at the Collateral Agent’s election, the Collateral Agent may apply all or any part of Proceeds constituting Collateral, whether or not held in any Collateral Account, and any proceeds of the guarantee set forth in Section 2 , in payment of the Obligations in the following order:

First , to pay incurred and unpaid fees and expenses of the Collateral Agent under the First Lien Documents;

Second , to the Collateral Agent, for application by it towards payment of amounts then due and owing and remaining unpaid in respect of the Obligations, pro rata among the Secured Parties according to the amounts of the Obligations then due and owing and remaining unpaid to the Secured Parties;

Third , to the Collateral Agent, for application by it towards prepayment of the Obligations, pro rata among the Secured Parties according to the amounts of the Obligations then held by the Secured Parties; and

Fourth , any balance remaining after the Secured Debt Termination Date with respect to the First Lien Debt shall be paid over to the Borrower or to whomsoever may be lawfully entitled to receive the same;

provided that in the event of any inconsistency between the terms of the Intercreditor Agreement and this Section 6.5 , the term of the Intercreditor Agreement shall govern.

6.6 Code and Other Remedies . If an Event of Default shall occur and be continuing, the Collateral Agent, on behalf of the Secured Parties, may exercise, in addition to all other rights and remedies granted to them in this Agreement and in any other instrument or agreement securing, evidencing or relating to the Obligations, all rights and remedies of a secured party under the New York UCC or any other applicable law. Without limiting the generality of the foregoing, the Collateral Agent, without demand of performance or other demand, presentment, protest, advertisement or notice of any kind (except any notice required by law referred to below) to or upon any Grantor or any other Person (all and each of which demands, defenses, advertisements and notices are hereby waived), may, subject to the requirements of applicable law, in such circumstances forthwith collect, receive, appropriate and realize upon the Collateral, or any part thereof, and/or may forthwith sell, lease, assign, give option or options to purchase, or otherwise dispose of and deliver the Collateral or any part thereof (or contract to do any of the foregoing), in one or more parcels at public or private sale or sales, at any exchange, broker’s board or office of the Collateral Agent or any Secured Party or elsewhere upon such terms and conditions as it may deem advisable and at such prices as it may deem best, for cash or on credit or for future delivery without assumption of any credit risk. The Collateral Agent or any Secured Party shall have the right upon any such public sale or sales, and, to the extent permitted by law, upon any such private sale or sales, to purchase the whole or any part of the Collateral so sold, free of any right or equity of redemption in any Grantor, which right or equity is hereby waived and released. Each Grantor further agrees, at the Collateral Agent’s request, to assemble the Collateral and make it available to the Collateral Agent at places which the Collateral Agent shall reasonably select, whether at such Grantor’s premises or elsewhere. The Collateral Agent shall apply the net proceeds of any action taken by it pursuant to this Section 6.6 , after deducting all reasonable costs and expenses of every kind incurred in connection therewith or incidental to the care or safekeeping of any of the Collateral or in any way relating to the Collateral or the rights of the Collateral Agent and the Secured Parties hereunder, including, without limitation, reasonable attorneys’ fees and disbursements, to the payment in whole or in part of the Obligations, in such order as the Collateral Agent may elect, and only after such application and after the payment by the Collateral Agent of any other amount required by any provision of law, including, without limitation, Section 9-615(a)(3) of the New York UCC, need the Collateral Agent account for the surplus, if any, to any Grantor. To the extent permitted by applicable law, each Grantor waives all claims, damages and demands it may acquire against the Collateral Agent or any Secured Party arising out of the exercise by them of any rights hereunder. If any notice of a proposed sale or other disposition of Collateral shall be required by law, such notice shall be deemed reasonable and proper if given at least 10 days before such sale or other disposition.

6.7 Registration Rights . (a) Each Grantor recognizes that the Collateral Agent may be unable to effect a public sale of any or all the Pledged Stock, by reason of certain prohibitions contained in the Securities Act and applicable state securities laws or otherwise, and

may be compelled to resort to one or more private sales thereof to a restricted group of purchasers which will be obliged to agree, among other things, to acquire such securities for their own account for investment and not with a view to the distribution or resale thereof. Each Grantor acknowledges and agrees that any such private sale may result in prices and other terms less favorable than if such sale were a public sale and, notwithstanding such circumstances, agrees that any such private sale shall be deemed to have been made in a commercially reasonable manner. The Collateral Agent shall be under no obligation to delay a sale of any of the Pledged Stock for the period of time necessary to permit the Issuer thereof to register such securities for public sale under the Securities Act, or under applicable state securities laws, even if such Issuer would agree to do so.

(b) Each Grantor agrees to use its commercially reasonable efforts to do or cause to be done all such other acts as may be necessary to make such sale or sales of all or any portion of the Pledged Stock pursuant to this Section 6.7 valid and binding and in compliance with any and all other applicable Requirements of Law. Each Grantor further agrees that a breach of any of the covenants contained in this Section 6.7 will cause irreparable injury to the Collateral Agent and the Secured Parties, that the Collateral Agent and the Secured Parties have no adequate remedy at law in respect of such breach and, as a consequence, that each and every covenant contained in this Section 6.7 shall be specifically enforceable against such Grantor, and such Grantor hereby waives and agrees not to assert any defenses against an action for specific performance of such covenants except for a defense that no Event of Default has occurred.

6.8 Subordination . Each Grantor hereby agrees that, upon the occurrence and during the continuance of an Event of Default, unless otherwise agreed by the Collateral Agent, all Indebtedness owing by it to any Subsidiary of the Borrower shall be fully subordinated to the indefeasible payment in full in cash of such Grantor’s Obligations.

6.9 Deficiency . Each Grantor shall remain liable for any deficiency if the proceeds of any sale or other disposition of the Collateral are insufficient to pay its Obligations and the fees and disbursements of any attorneys employed by the Collateral Agent or any Secured Party to collect such deficiency.

6.10 Intercreditor Agreement . Notwithstanding anything to the contrary in this Section 6 or Section 7.1 , the Intercreditor Agreement shall govern the exercise of rights and the enforcement of remedies hereunder by the Collateral Agent and the Secured Parties. In the event of any conflict between the terms of this Section 6 and the Intercreditor Agreement, the Intercreditor Agreement shall govern.

SECTION 7. The Collateral Agent

7.1 Collateral Agent’s Appointment as Attorney-in-Fact, etc . (a) Each Grantor hereby irrevocably constitutes and appoints the Collateral Agent and any officer or agent thereof, with full power of substitution, as its true and lawful attorney-in-fact with full irrevocable power and authority in the place and stead of such Grantor and in the name of such Grantor or in its own name, for the purpose of carrying out the terms of this Agreement, to take any and all appropriate action and to execute any and all documents and instruments which may be necessary or desirable to accomplish the purposes of this Agreement. At any time when an

Event of Default has occurred and is continuing and without limiting the generality of the foregoing, each Grantor hereby gives the Collateral Agent the power and right, on behalf of such Grantor, without notice to or assent by such Grantor, to do any or all of the following:

(i) in the name of such Grantor or its own name, or otherwise, take possession of and indorse and collect any checks, drafts, notes, acceptances or other instruments for the payment of moneys due under any Receivable or Contract or with respect to any other Collateral and file any claim or take any other action or proceeding in any court of law or equity or otherwise deemed appropriate by the Collateral Agent for the purpose of collecting any and all such moneys due under any Receivable or Contract or with respect to any other Collateral whenever payable;

(ii) in the case of any Intellectual Property, execute and deliver, and have recorded, any and all agreements, instruments, documents and papers as the Collateral Agent may reasonably request to evidence the Collateral Agent’s and the Secured Parties’ security interest in such Intellectual Property and the goodwill and general intangibles of such Grantor relating thereto or represented thereby;

(iii) pay or discharge taxes and Liens levied or placed on or threatened against the Collateral, effect any repairs or any insurance called for by the terms of this Agreement and pay all or any part of the premiums therefor and the costs thereof;

(iv) execute, in connection with any sale provided for in Section 6.6 or 6.7 , any indorsements, assignments or other instruments of conveyance or transfer with respect to the Collateral; and

(v) (1) direct any party liable for any payment under any of the Collateral to make payment of any and all moneys due or to become due thereunder directly to the Collateral Agent or as the Collateral Agent shall direct; (2) ask or demand for, collect, and receive payment of and receipt for, any and all moneys, claims and other amounts due or to become due at any time in respect of or arising out of any Collateral; (3) sign and indorse any invoices, freight or express bills, bills of lading, storage or warehouse receipts, drafts against debtors, assignments, verifications, notices and other documents in connection with any of the Collateral; (4) commence and prosecute any suits, actions or proceedings at law or in equity in any court of competent jurisdiction to collect the Collateral or any portion thereof and to enforce any other right in respect of any Collateral; (5) defend any suit, action or proceeding brought against such Grantor with respect to any Collateral; (6) settle, compromise or adjust any such suit, action or proceeding and, in connection therewith, give such discharges or releases as the Collateral Agent may deem appropriate; (7) assign any Copyright, Patent or Trademark (along with the goodwill of the business to which any such Copyright, Patent or Trademark pertains), throughout the world for such term or terms, on such conditions, and in such manner, as the Collateral Agent shall in its sole discretion determine; and (8) generally, sell, transfer, pledge and make any agreement with respect to or otherwise deal with any of the Collateral as fully and completely as though the Collateral Agent were the absolute owner thereof for all purposes, and do, at the Collateral Agent’s option and such Grantor’s expense, at any time, or from time to time, all acts and things which

the Collateral Agent deems necessary to protect, preserve or realize upon the Collateral and the Collateral Agent’s and the Secured Parties’ security interests therein and to effect the intent of this Agreement, all as fully and effectively as such Grantor might do.

Notwithstanding anything to the contrary in this Section 7.1(a) , the Collateral Agent agrees that it will not exercise any rights under the power of attorney provided for in this Section 7.1(a) unless an Event of Default shall have occurred and be continuing.

(b) If any Grantor fails to perform or comply with any of its agreements contained herein, the Collateral Agent, at its option, but without any obligation so to do, may perform or comply, or otherwise cause performance or compliance, with such agreement.

(c) The reasonable expenses of the Collateral Agent incurred in connection with actions undertaken as provided in this Section 7.1 , together with interest thereon at a rate per annum equal to the highest rate per annum at which interest would then be payable on any category of past due Base Rate Loans under, and as defined (or any other defined term having a similar purpose) in, any Credit Agreement, from the date of payment by the Collateral Agent to the date reimbursed by the relevant Grantor, shall be payable by such Grantor to the Collateral Agent on demand.

(d) Each Grantor hereby ratifies all that said attorneys shall lawfully do or cause to be done by virtue hereof. All powers, authorizations and agencies contained in this Agreement are coupled with an interest and are irrevocable until this Agreement is terminated and the security interests created hereby are released.

7.2 Duty of Collateral Agent . To the full extent permitted by applicable law, the Collateral Agent’s sole duty with respect to the custody, safekeeping and physical preservation of the Collateral in its possession, under Section 9-207 of the New York UCC or otherwise, shall be to deal with it in the same manner as the Collateral Agent deals with similar property for its own account. Neither the Collateral Agent, any Secured Party nor any of their respective officers, directors, employees or agents shall be liable for failure to demand, collect or realize upon any of the Collateral or for any delay in doing so or shall be under any obligation to sell or otherwise dispose of any Collateral upon the request of any Grantor or any other Person or to take any other action whatsoever with regard to the Collateral or any part thereof, except as provided herein. The powers conferred on the Collateral Agent and the Secured Parties hereunder are solely to protect the Collateral Agent’s and the Secured Parties’ interests in the Collateral and shall not impose any duty upon the Collateral Agent or any Secured Party to exercise any such powers. The Collateral Agent and the Secured Parties shall be accountable only for amounts that they actually receive as a result of the exercise of such powers, and neither they nor any of their officers, directors, employees or agents shall be responsible to any Grantor for any act or failure to act hereunder, except for their own gross negligence or willful misconduct.

7.3 Execution of Financing Statements . Pursuant to any applicable law, each Grantor authorizes the Collateral Agent to file or record financing statements and other filing or recording documents or instruments with respect to the Collateral without the signature of such Grantor in such form and in such offices as the Collateral Agent determines appropriate to

perfect the security interests of the Collateral Agent under this Agreement. Each Grantor authorizes the Collateral Agent to use the collateral description “all personal property” in any such financing statements. Each Grantor hereby ratifies and authorizes the filing by the Collateral Agent of any financing statement with respect to the Collateral made on or prior to the date hereof.

7.4 Authority of Collateral Agent . Each Grantor acknowledges that the rights and responsibilities of the Collateral Agent under this Agreement with respect to any action taken by the Collateral Agent or the exercise or non-exercise by the Collateral Agent of any option, voting right, request, judgment or other right or remedy provided for herein or resulting or arising out of this Agreement shall, as between the Collateral Agent and the Secured Parties, be governed by the Intercreditor Agreement and/or relevant First Lien Documents, and by such other agreements with respect thereto as may exist from time to time among any of them, but, as between the Collateral Agent and the Grantors, the Collateral Agent shall be conclusively presumed to be acting as agent for the Secured Parties with full and valid authority so to act or refrain from acting, and no Grantor shall be under any obligation, or entitlement, to make any inquiry respecting such authority.

7.5 Intercreditor Agreement . Each party hereto (and each Secured Party) acknowledges and agrees that the Collateral Agent may act in accordance with, and shall be required to take certain actions as required by, the terms of the Intercreditor Agreement. Each of the parties hereto (and each Secured Party) acknowledges and agrees that any such actions shall be permitted, and further agrees that in the event of a conflict between the provisions of this Agreement and the Intercreditor Agreement, the relevant provisions of the Intercreditor Agreement shall control. The parties hereto (and each Secured Party) also acknowledge and agree that the Collateral Agent shall have the benefit of the provisions contained in the Intercreditor Agreement (including Article V thereof).

SECTION 8. Miscellaneous

8.1 Amendments in Writing . None of the terms or provisions of this Agreement may be waived, amended, supplemented or otherwise modified except in accordance with Section 9.1 of the Existing Credit Agreement, Section 9.1 of the Revolving Credit Agreement and Section 8.1 of the Intercreditor Agreement.

8.2 Notices . All notices, requests and demands to or upon the Collateral Agent or any Grantor hereunder shall be effected in the manner provided for in Section 8.6 of the Intercreditor Agreement.

8.3 No Waiver by Course of Conduct; Cumulative Remedies . Neither the Collateral Agent nor any Secured Party shall by any act (except by a written instrument pursuant to Section 8.1 ), delay, indulgence, omission or otherwise be deemed to have waived any right or remedy hereunder or to have acquiesced in any Default or Event of Default. No failure to exercise, nor any delay in exercising, on the part of the Collateral Agent or any Secured Party any right, power or privilege hereunder shall operate as a waiver thereof. No single or partial exercise of any right, power or privilege hereunder shall preclude any other or further exercise thereof or the exercise of any other right, power or privilege. A waiver by the Collateral Agent

or any Lender of any right or remedy hereunder on any one occasion shall not be construed as a bar to any right or remedy which the Collateral Agent or such Secured Party would otherwise have on any future occasion. The rights and remedies herein provided are cumulative, may be exercised singly or concurrently and are not exclusive of any other rights or remedies provided by law.

8.4 Enforcement Expenses; Indemnification . (a) Each Guarantor agrees to pay or reimburse each Secured Party and the Collateral Agent for all its costs and expenses incurred in collecting against such Guarantor under the guarantee contained in Section 2 or otherwise enforcing or preserving any rights under this Agreement and the other First Lien Documents to which such Guarantor is a party, including, without limitation, the fees and disbursements of counsel (including the allocated fees and expenses of in-house counsel) to each Secured Party and of counsel to the Collateral Agent.

(b) Each Guarantor agrees to pay, and to save the Collateral Agent and the Secured Parties harmless from, any and all liabilities with respect to, or resulting from any delay in paying, any and all stamp, excise, sales or other taxes which may be payable or determined to be payable with respect to any of the Collateral or in connection with any of the transactions contemplated by this Agreement.

(c) Each Guarantor agrees to pay, and to save the Collateral Agent and the Secured Parties harmless from, any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever with respect to the execution, delivery, enforcement, performance and administration of this Agreement to the extent the Borrower would be required to do so pursuant to Section 9.5 of the Existing Credit Agreement, Section 9.5 of the Revolving Credit Agreement or the relevant provisions of any other First Lien Document.

(d) The agreements in this Section 8.4 shall survive repayment of the Obligations and all other amounts payable under the First Lien Documents.

8.5 Successors and Assigns . This Agreement shall be binding upon the successors and assigns of each Grantor and shall inure to the benefit of the Collateral Agent and the Secured Parties and their successors and assigns; provided that no Grantor may assign, transfer or delegate any of its rights or obligations under this Agreement without the prior written consent of the Collateral Agent.

8.6 Set-Off; Limitation on Individual Actions . (a) In addition to any rights and remedies of the Secured Parties provided by law, each Secured Party shall have the right, without notice to any Grantor, any such notice being expressly waived by each Grantor to the extent permitted by applicable law, upon any Obligations becoming due and payable by any Grantor (whether at the stated maturity, by acceleration or otherwise), to apply to the payment of such Obligations, by setoff or otherwise, any and all deposits (general or special, time or demand, provisional or final), in any currency, and any other credits, indebtedness or claims, in any currency, in each case whether direct or indirect, absolute or contingent, matured or unmatured, at any time held or owing by such Secured Party, any affiliate thereof or any of their respective branches or agencies to or for the credit or the account of such Grantor. Each Secured Party

agrees promptly to notify in writing the relevant Grantor and the Collateral Agent after any such application made by such Secured Party, provided that the failure to give such notice shall not affect the validity of such application.

(b) NOTWITHSTANDING THE FOREGOING SUBSECTION (a) OR ANY CONTRARY PROVISION CONTAINED IN ANY FIRST LIEN DOCUMENT, AT ANY TIME THAT ANY OBLIGATION SHALL BE SECURED BY ANY INTEREST IN ANY REAL PROPERTY LOCATED IN CALIFORNIA, NO SECURED PARTY (OTHER THAN THE COLLATERAL AGENT OR ANY ADMINISTRATIVE AGENT) SHALL EXERCISE ANY REMEDIES AGAINST ANY LOAN PARTY OR ANY PROPERTY THEREOF, INCLUDING WITHOUT LIMITATION, A RIGHT OF SETOFF, LIEN OR COUNTERCLAIM OR TAKE ANY COURT OR ADMINISTRATIVE ACTION OR INSTITUTE ANY PROCEEDING TO ENFORCE ANY PROVISION OF THIS AGREEMENT OR ANY SECURITY DOCUMENT OR ANY FIRST LIEN DOCUMENT (ALTHOUGH A SECURED PARTY CAN ACCELERATE THE MATURITY OF ANY FIRST LIEN DEBT IN ACCORDANCE WITH THE TERMS OF THE RESPECTIVE FIRST LIEN DOCUMENT) UNLESS IT IS TAKEN PURSUANT TO AN “ACT OF REQUIRED DEBT HOLDERS” (AS DEFINED IN THE INTERCREDITOR AGREEMENT) OR APPROVED IN WRITING BY THE COLLATERAL AGENT; PROVIDED THAT IF REPUTABLE OUTSIDE CALIFORNIA COUNSEL TO SUCH SECURED PARTY PROVIDES ITS WRITTEN LEGAL OPINION (WITHOUT ANY MATERIAL QUALIFICATION OR EXCEPTION) TO THE EFFECT THAT SUCH SETOFF OR ACTION OR PROCEEDING WOULD NOT (PURSUANT TO APPLICABLE CALIFORNIA STATE LAW, INCLUDING, WITHOUT LIMITATION, SECTIONS 580a, 580b, 580d AND 726 OF THE CALIFORNIA CODE OF CIVIL PROCEDURE OR SECTION 2924 OF THE CALIFORNIA CIVIL CODE, IF APPLICABLE) ADVERSELY AFFECT OR IMPAIR THE VALIDITY, PRIORITY OR ENFORCEABILITY OF THE LIENS GRANTED TO THE COLLATERAL AGENT PURSUANT TO THE SECURITY DOCUMENTS OR THE ENFORCEABILITY OF THE OBLIGATIONS UNDER THE OTHER FIRST LIEN DOCUMENTS, THEN SUCH ACTION MAY BE TAKEN OR COMMENCED SO LONG AS THE RESPECTIVE SECURED PARTY PROVIDES AT LEAST FIVE BUSINESS DAYS’ ADVANCE WRITTEN NOTICE THEREOF TO THE COLLATERAL AGENT (TOGETHER WITH A COPY OF THE RESPECTIVE OPINION OF CALIFORNIA COUNSEL). ANY ATTEMPTED EXERCISE BY ANY SECURED PARTY OF ANY SUCH RIGHT IN CONTRAVENTION OF THE FOREGOING PROVISIONS SHALL BE NULL AND VOID. THIS SUBSECTION (b) SHALL BE SOLELY FOR THE BENEFIT OF EACH OF THE SECURED PARTIES AND THE COLLATERAL AGENT, AND MAY BE AMENDED BY AN “ACT OF REQUIRED DEBT HOLDERS”.

8.7 Counterparts . This Agreement may be executed by one or more of the parties to this Agreement on any number of separate counterparts (including by electronic transmission or telecopy), and all of said counterparts taken together shall be deemed to constitute one and the same instrument.

8.8 Severability . Any provision of this Agreement which is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such

prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

8.9 Section Headings . The Section headings used in this Agreement are for convenience of reference only and are not to affect the construction hereof or be taken into consideration in the interpretation hereof.

8.10 Integration . This Agreement, the Intercreditor Agreement and the other First Lien Documents represent the entire agreement of the Grantors, the Collateral Agent and the Secured Parties with respect to the subject matter hereof and thereof, and there are no promises, undertakings, representations or warranties by the Collateral Agent or any Secured Party relative to subject matter hereof and thereof not expressly set forth or referred to herein, in the Intercreditor Agreement or in the other First Lien Documents.

8.11 GOVERNING LAW . THIS AGREEMENT SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK.

8.12 Submission To Jurisdiction; Waivers . Each Grantor hereby irrevocably and unconditionally:

(a) submits for itself and its property in any legal action or proceeding relating to this Agreement, the Intercreditor Agreement and the other First Lien Documents to which it is a party, or for recognition and enforcement of any judgment in respect thereof, to the non exclusive general jurisdiction of the courts of the State of New York, the courts of the United States of America for the Southern District of New York, and appellate courts from any thereof;

(b) consents that any such action or proceeding may be brought in such courts and waives any objection that it may now or hereafter have to the venue of any such action or proceeding in any such court or that such action or proceeding was brought in an inconvenient court and agrees not to plead or claim the same;

(c) agrees that service of process in any such action or proceeding may be effected by mailing a copy thereof by registered or certified mail (or any substantially similar form of mail), postage prepaid, to such Grantor at its address referred to in Section 8.2 or at such other address of which the Collateral Agent shall have been notified pursuant thereto;

(d) agrees that nothing herein shall affect the right to effect service of process in any other manner permitted by law or shall limit the right to sue in any other jurisdiction;

(e) waives, to the maximum extent not prohibited by law, any right it may have to claim or recover in any legal action or proceeding referred to in this Section any special, exemplary, punitive or consequential damages;

(f) acknowledges and affirms that it understands that to the extent the Obligations are secured by real property located in the State of California, such Grantor shall be liable for the full amount of the liability hereunder notwithstanding foreclosure on such real property by trustee sale or any other reason impairing such Grantor’s or any Secured Parties’ right to proceed against the Borrower or any other Grantor;

(g) waives (to the fullest extent permitted by applicable law) all rights and defenses under Section 580a, 580b, 580d and 726 of the California Code of Civil Procedure;

(h) waives (to the fullest extent permitted by applicable law), without limiting the generality of the foregoing or any other provision hereof, all rights and defenses which might otherwise be available to such Grantor under Sections 2809, 2810, 2815, 2819, 2821, 2839, 2845, 2848, 2849, 2850, 2899 and 3433 of the California Civil Code; and

(i) waives, until the Obligations have been paid in full in cash, its rights of subrogation and reimbursement and any other rights and defenses, in each case available to such Grantor by reason of Sections 2787 to 2855, inclusive, of the California Civil Code because the Obligations are secured by real property, including, without limitation, (1) any defenses such Grantor may have to the guarantee provided under this Agreement by reason of an election of remedies by the Secured Parties and (2) any rights or defenses such Grantor may have by reason of protection afforded to the Borrower or any other Grantor pursuant to the antideficiency or other laws of California limiting or discharging the Borrower’s or such Grantor’s indebtedness, including, without limitation, Section 580a, 580b, 580d or 726 of the California Code of Civil Procedure. In furtherance of such provisions, each Grantor hereby waives all rights and defenses arising out of an election of remedies by the Secured Parties, even though that election of remedies, such as a nonjudicial foreclosure, destroys such Grantor’s rights of subrogation and reimbursement against the Borrower or any other Grantor by the operation of Section 580d of the California Code of Civil Procedure or otherwise.

8.13 Acknowledgements . Each Grantor hereby acknowledges that:

(a) it has been advised by counsel in the negotiation, execution and delivery of this Agreement, the Intercreditor Agreement and the other First Lien Documents to which it is a party;

(b) neither the Collateral Agent nor any Secured Party has any fiduciary relationship with or duty to any Grantor arising out of or in connection with this Agreement, the Intercreditor Agreement or any other First Lien Documents, and the relationship between the Grantors, on the one hand, and the Collateral Agent and the Secured Parties, on the other hand, in connection herewith or therewith is solely that of debtor and creditor; and

(c) no joint venture is created hereby, by the Intercreditor Agreement or the other First Lien Documents or otherwise exists by virtue of the transactions contemplated hereby among the Secured Parties or among the Grantors and the Secured Parties.

8.14 Additional Grantors; Release of Guarantors; Releases of Collateral ;. (a) Each Subsidiary of the Borrower that is required to become a party to this Agreement pursuant to the relevant provision of any First Lien Documents shall become a Grantor (and a Guarantor) for all purposes of this Agreement upon execution and delivery by such Subsidiary of an Assumption Agreement in the form of Annex 1 hereto.

(b) Non-Borrower Guarantors shall be released from this Agreement to the extent provided below, in each case at the request and expense of the Borrower:

(i) A Non-Borrower Guarantor shall be released from its obligations hereunder in the event that all the Capital Stock of such Non-Borrower Guarantor shall be sold, transferred or otherwise disposed of (in each case to a Person other than the Borrower or a Subsidiary) in a transaction permitted by all then effective First Lien Documents; provided that the Borrower shall have delivered to the Collateral Agent, at least three Business Days prior to the date of the proposed release, a written request for release identifying the relevant Non-Borrower Guarantor and the terms of the sale or other disposition in reasonable detail, including the price thereof and any expenses in connection therewith, together with a certification by the Borrower stating that such transaction is in compliance with all then effective First Lien Documents.

(ii) A Non-Borrower Guarantor shall be released from its obligations hereunder in the event that (1) the same is subsequently designated as a “Designated Project Subsidiary” under, and as defined in, the Existing Credit Agreement as originally in effect (including the related relevant provisions), as such provisions may be amended, modified, replaced or supplemented from time to time, but in the case of any amendment, modification, replacement or supplement to the terms originally applicable in the Existing Credit Agreement, the respective designation and release of the respective Non-Borrower Subsidiary as a Guarantor hereunder shall not violate the terms of any other First Lien Documents then in effect or (2) if the Existing Credit Agreement is no longer in effect, the same is subsequently designated as a “Designated Project Subsidiary” (and any defined term having a similar purpose in any other Credit Agreement) under, and as defined in, the Revolving Credit Agreement and any other Credit Agreement, as applicable, and, in the case of either clause (1) or (2), the Borrower has delivered an Officer’s Certificate to the Collateral Agent stating that the release is permitted pursuant to this clause (ii) and providing in reasonable detail the supporting calculations (if any) in determining that the respective Non-Borrower Guarantor may be designated as a Designated Project Subsidiary.

(iii) One or more Non-Borrower Guarantors may be released from their obligations hereunder at any time if (1) consent to release of such Non-Borrower Guarantors has been given by the requisite percentage or number of holders of each Series of First Lien Debt at the time outstanding as provided for in the applicable First Lien Documents, (2) each First Lien Representative for each Series of First Lien Debt

(which shall be identified in the Officer’s Certificate described in clause (3)) shall have notified the Collateral Agent that the consent for its respective Series of First Lien Debt has been obtained and (3) the Borrower has delivered an Officer’s Certificate to the Collateral Agent certifying as to the consents of the holders of each Series of First Lien Debt that are necessary for such release and that any such necessary consents have been obtained.

(iv) In connection with any release of any Non-Borrower Guarantor pursuant to this Section 8.14 , the Collateral Agent shall execute and deliver to the Borrower, at the Borrower’s expense, all documents that the Borrower shall reasonably request to evidence such release. Any execution and delivery of documents pursuant to this Section 8.14 shall be without recourse to or warranty by the Collateral Agent.

(c) Releases of Collateral shall be effected in accordance with the relevant provisions of Section 4.1 of the Intercreditor Agreement

8.15 WAIVER OF JURY TRIAL . EACH GRANTOR HEREBY IRREVOCABLY AND UNCONDITIONALLY WAIVES TRIAL BY JURY IN ANY LEGAL ACTION OR PROCEEDING RELATING TO THIS AGREEMENT, THE INTERCREDITOR AGREEMENT OR ANY OTHER FIRST LIEN DOCUMENT AND FOR ANY COUNTERCLAIM THEREIN.

8.16 Amendment and Restatement . It is the intention of each of the parties hereto that the Existing Guarantee and Collateral Agreement be amended and restated in its entirety pursuant to this Agreement so as to preserve the perfection and priority of all Liens securing the Obligations (as defined in the Existing Guarantee and Collateral Agreement) and that all such Obligations of the Borrower and the Guarantors shall be secured by the Liens evidenced under this Agreement and the other Security Documents and that this Agreement (and the amendment and restatement of the Existing Guarantee and Collateral Agreement contained herein) does not constitute a novation or termination of any of the Existing Guarantee and Collateral Agreement, the guaranty by each Guarantor or the grant of security interests by each Grantor provided for under the Existing Guarantee and Collateral Agreement, and/or the Obligations existing under the Existing Guarantee and Collateral Agreement. From and after the date hereof, all references to the “Guarantee and Collateral Agreement” contained in the Existing Credit Agreement, the Revolving Credit Agreement and each other Security Document shall be deemed to refer to this Agreement.

8.17 Reaffirmation and Grant of Security Interest . Each of the Borrower, each Guarantor and each Grantor, subject to the terms and limits contained herein and in the First Lien Security Documents reaffirms (i) its guaranty of the Guaranteed Obligations, on the terms set forth in the Existing Guarantee and Collateral Agreement, as amended and restated by this Agreement, and nothing in this Agreement shall be deemed to supersede, impair or otherwise limit the guaranty by such Guarantor contained in the Existing Guarantee and Collateral Agreement, and (ii) in the case of each Grantor, its grant of a security interest in favor of Collateral Agent on the Collateral to secure its Obligations, on the terms set forth in the Existing Guarantee and Collateral Agreement, as amended and restated by this Agreement, and nothing in this Agreement shall be deemed to supersede, impair or otherwise limit the assignment, transfer and grant by such Grantor contained in the Existing Guarantee and Collateral Agreement. Each

of the Borrower, each Guarantor and each Grantor hereby acknowledges that it has reviewed the terms and provisions of this Agreement and consents to the amendment and restatement of the Existing Guarantee and Collateral Agreement effected pursuant to this Agreement. Each of the Borrower, each Guarantor and each Grantor hereby confirms that each First Lien Security Document which it is a party or is otherwise bound continues to be in full force and effect, and all Collateral encumbered thereby will continue to guarantee or secure, as the case may be, to the fullest extent possible in accordance with the First Lien Documents, the payment and performance of the Guaranteed Obligations and the Obligations, as applicable, and all of its obligations thereunder shall be valid and enforceable and shall not be impaired or limited by the execution or effectiveness of the amendment and restatement of the Existing Guarantee and Collateral Agreement.

[remainder of page intentionally left blank]

IN WITNESS WHEREOF, each of the undersigned has caused this Amended and Restated Guarantee and Collateral Agreement to be duly executed and delivered as of the date first above written.

	CALPINE CORPORATION



	By:	/s/ ZAMIR RAUF
		Name: Zamir Rauf Title: Chief Financial Officer

	CPN ENERGY SERVICES GP, INC., AS THE
	GENERAL PARTNER OF CALPINE
	PRODUCER SERVICES, L.P.


	By:	/s/ ZAMIR RAUF
		Name: Zamir Rauf Title: Chief Financial Officer

	CALPINE HIDALGO, INC., AS THE
	GENERAL PARTNER OF CALPINE
	HIDALGO ENERGY CENTER, L.P.


	By:	/s/ ZAMIR RAUF
		Name: Zamir Rauf Title: Chief Financial Officer

	CALPINE POWER MANAGEMENT, INC.,
	AS THE GENERAL PARTNER OF CALPINE
	POWER MANAGEMENT, LP


	By:	/s/ ZAMIR RAUF
		Name: Zamir Rauf Title: Chief Financial Officer

	CALPINE POWERAMERICA, INC., AS THE
	GENERAL PARTNER OF CALPINE
	POWERAMERICA, LP


	By:	/s/ ZAMIR RAUF
		Name: Zamir Rauf Title: Chief Financial Officer

	CPN CLEAR LAKE, INC., AS THE
	GENERAL PARTNER OF CLEAR LAKE
	COGENERATION LIMITED PARTNERSHIP


	By:	/s/ ZAMIR RAUF
		Name: Zamir Rauf Title: Chief Financial Officer

	CALPINE FREESTONE, LLC, AS THE
	GENERAL PARTNER OF FREESTONE
	POWER GENERATION, LP


	By:	/s/ ZAMIR RAUF
		Name: Zamir Rauf Title: Chief Financial Officer

	TEXAS COGENERATION ONE COMPANY,
	AS THE GENERAL PARTNER OF TEXAS
	CITY COGENERATION, L.P.


	By:	/s/ ZAMIR RAUF
		Name: Zamir Rauf Title: Chief Financial Officer

	THE GUARANTORS SET FORTH ON
	ANNEX I TO THIS SIGNATURE PAGE:


	By:	/s/ ZAMIR RAUF
		Name: Zamir Rauf Title: Chief Financial Officer

	THE GUARANTORS SET FORTH ON
	ANNEX II TO THIS SIGNATURE PAGE:


	By:	/s/ HETHER BENJAMIN-BROWN
		Name: Hether Benjamin-Brown Title: Vice President

Accepted and Agreed to:

	GOLDMAN SACHS CREDIT PARTNERS
	L.P., as Collateral Agent


	By:	/s/ DOUGLAS TANSEY
		Name: Douglas Tansey Title: Authorized Signatory

ANNEX I

Name of Guarantor

Anacapa Land Company, LLC

Anderson Springs Energy Company

Auburndale Peaker Energy Center, LLC

Aviation Funding Corp.

Baytown Energy Center, LP

Bellingham Cogen, Inc.

Bethpage Fuel Management Inc.

CalGen Expansion Company, LLC

CalGen Finance Corp.

CalGen Project Equipment Finance Company One, LLC

CalGen Project Equipment Finance Company Three, LLC

CalGen Project Equipment Finance Company Two, LLC

Calpine Administrative Services Company, Inc.

Calpine Auburndale Holdings, LLC

Calpine Baytown Energy Center GP, LLC

Calpine Baytown Energy Center LP, LLC

Calpine c*Power, Inc.

Calpine CalGen Holdings, Inc.

Calpine California Holdings, Inc.

Calpine Calistoga Holdings, LLC

Calpine CCFC Holdings, Inc.

Calpine Central Texas GP, Inc.

Calpine Central, Inc.

Calpine Central, L.P.

Calpine Central-Texas, Inc.

Calpine Channel Energy Center GP, LLC

Calpine Channel Energy Center LP, LLC

Calpine Cogeneration Corporation

Calpine Eastern Corporation

Calpine Edinburg, Inc.

Name of Guarantor

Calpine Energy Management, L.P.

Calpine Energy Services Holdings, Inc.

Calpine Energy Services, L.P.

Calpine Freestone, LLC

Calpine Fuels Corporation

Calpine Generating Company, LLC

Calpine Geysers Company, L.P.

Calpine Gilroy 1, Inc.

Calpine Gilroy 2, Inc.

Calpine Global Services Company, Inc.

Calpine Hidalgo Holdings, Inc.

Calpine Hidalgo, Inc.

Calpine Jupiter, LLC

Calpine Kennedy Airport, Inc.

Calpine Kennedy Operators, Inc.

Calpine KIA, Inc.

Calpine King City, Inc.

Calpine King City, LLC

Calpine Leasing Inc.

Calpine Long Island, Inc.

Calpine Magic Valley Pipeline, Inc.

Calpine MVP, Inc.

Calpine Newark, LLC

Calpine Northbrook Corporation of Maine, Inc.

Calpine Northbrook Holdings Corporation

Calpine Northbrook Investors, LLC

Calpine Northbrook Project Holdings, LLC

Calpine Northbrook Southcoast Investors, LLC

Calpine Oneta Power I, LLC

Calpine Oneta Power II, LLC

Calpine Oneta Power, L.P.

Name of Guarantor

Calpine Operations Management Company, Inc.

Calpine Power Company

Calpine Power Management, Inc.

Calpine Power, Inc.

Calpine PowerAmerica, Inc.

Calpine PowerAmerica - CA, LLC

Calpine PowerAmerica-CT, LLC

Calpine PowerAmerica - MA, LLC

Calpine PowerAmerica - ME, LLC

Calpine PowerAmerica-NH, LLC

Calpine PowerAmerica-NY, LLC

Calpine PowerAmerica - OR, LLC

Calpine PowerAmerica - PA, LLC

Calpine PowerAmerica-RI, LLC

Calpine Project Holdings, Inc.

Calpine Pryor, Inc.

Calpine Rumford I, Inc.

Calpine Rumford, Inc.

Calpine Schuylkill, Inc.

Calpine Sonoran Pipeline, LLC

Calpine Stony Brook Operators, Inc.

Calpine Stony Brook, Inc.

Calpine Sumas, Inc.

Calpine TCCL Holdings, Inc.

Calpine Texas Pipeline GP, Inc.

Calpine Texas Pipeline LP, Inc.

Calpine Texas Pipeline, L.P.

Calpine Tiverton I, Inc.

Calpine Tiverton, Inc.

Calpine University Power, Inc.

Carville Energy LLC

Name of Guarantor

CCFC Development Company, LLC

CCFC Project Equipment Finance Company One, LLC

CES Marketing IX, LLC

CES Marketing V, L.P.

CES Marketing X, LLC

Channel Energy Center, LP

Columbia Energy LLC

Corpus Christi Cogeneration LP

CPN 3 rd Turbine, Inc.

CPN Acadia, Inc.

CPN Cascade, Inc.

CPN Clear Lake, Inc.

CPN Decatur Pipeline, Inc.

CPN East Fuels, LLC

CPN Energy Services GP, Inc.

CPN Energy Services LP, Inc.

CPN Freestone, LLC

CPN Funding, Inc.

CPN Morris, Inc.

CPN Pipeline Company

CPN Pryor Funding Corporation

CPN Telephone Flat, Inc.

Decatur Energy Center, LLC

Delta Energy Center, LLC

East Altamont Energy Center, LLC

Fontana Energy Center, LLC

GEC Bethpage Inc.

Geysers Power Company, LLC

Geysers Power I Company

Hillabee Energy Center, LLC

Idlewild Fuel Management Corp.

Name of Guarantor

JMC Bethpage, Inc.

Lone Oak Energy Center, LLC

Los Medanos Energy Center LLC

Magic Valley Pipeline, L.P.

Moapa Energy Center, LLC

Mobile Energy L L C

Modoc Power, Inc.

Morgan Energy Center, LLC

Northwest Cogeneration, Inc.

NTC Five, Inc.

Nueces Bay Energy LLC

Pastoria Energy Center, LLC

Pastoria Energy Facility L.L.C.

Pine Bluff Energy, LLC

RockGen Energy LLC

Rumford Power Associates Limited Partnership

San Joaquin Valley Energy Center, LLC

Santa Rosa Energy Center, LLC

Stony Brook Cogeneration Inc.

Stony Brook Fuel Management Corp.

Sutter Dryers, Inc.

Texas Cogeneration Five, Inc.

Texas Cogeneration One Company

Thermal Power Company

Tiverton Power Associates Limited Partnership

Wawayanda Energy Center, LLC

Whatcom Cogeneration Partners, L.P.

Zion Energy LLC

ANNEX II

Name of Guarantor

Calpine Construction Management Company, Inc.

Calpine Power Services, Inc.

Thomassen Turbine Systems America, Inc.

Calpine Operating Services Company, Inc.

SCHEDULE 1

NOTICE ADDRESSES OF GUARANTORS

Notices to all Guarantors shall be mailed to the following address:
	Calpine Corporation 717 Texas Avenue Suite 1000 Houston, TX 77002 Attention: Chief Legal Officer Telecopier No.: 832-325-4508
with copies (which shall not constitute notice) to:
	717 Texas Avenue Suite 1000 Houston, TX 77002 Attention: Associate General Counsel Telecopier No.: 713-830-8751

SCHEDULE 2

DESCRIPTION OF INVESTMENT PROPERTY

Pledged Stock:

Grantor	Issuer	Class of Stock	Stock Certificate No.	No. of Shares
Anderson Springs Energy Company	Thermal Power Company	Common Stock	6	4,787,586
Aviation Funding Corp	KIAC Partners	Partnership Interest	No Certificate Issued [n]	50%
Bellingham Cogen, Inc.	Whatcom Cogeneration Partners, L.P.	Limited Partnership Interest	No Certificate Issued [n]	25%
CalGen Expansion Company, LLC	CalGen Project Equipment Finance Company One, LLC	LLC Membership Interest	3 [y]	100%
CalGen Expansion Company, LLC	CalGen Project Equipment Finance Company Two, LLC	LLC Membership Interest	2 [y]	100%
CalGen Expansion Company, LLC	CalGen Project Equipment Finance Company Three, LLC	LLC Membership Interest	3 [y]	100%
CalGen Expansion Company, LLC	Calpine Baytown Energy Center GP, LLC	LLC Membership Interest	1 [y]	100%
CalGen Expansion Company, LLC	Calpine Baytown Energy Center LP, LLC	LLC Membership Interest	2 [y]	100%
CalGen Expansion Company, LLC	Calpine Channel Energy Center GP, LLC	LLC Membership Interest	2 [y]	100%
CalGen Expansion Company, LLC	Calpine Channel Energy Center LP, LLC	LLC Membership Interest	2 [y]	100%
CalGen Expansion Company, LLC	Calpine Freestone, LLC	LLC Membership Interest	1 [y]	100%
CalGen Expansion Company, LLC	Calpine Northbrook Southcoast Investors, LLC	LLC Membership Interest	1 [y]	100%
CalGen Expansion Company, LLC	Calpine Oneta Power I, LLC	LLC Membership Interest	2 [y]	100%

CalGen Expansion Company, LLC	Calpine Oneta Power II, LLC	LLC Membership Interest	2 [y]	100%
CalGen Expansion Company, LLC	Carville Energy LLC	LLC Membership Interest	2 [y]	100%
CalGen Expansion Company, LLC	Columbia Energy LLC	LLC Membership Interest	1 [y]	100%
CalGen Expansion Company, LLC	CPN Freestone, LLC	LLC Membership Interest	1 [y]	100%
CalGen Expansion Company, LLC	Decatur Energy Center, LLC	LLC Membership Interest	2 [y]	100%
CalGen Expansion Company, LLC	Delta Energy Center, LLC	LLC Membership Interest	5 [y]	100%
CalGen Expansion Company, LLC	Los Medanos Energy Center LLC	LLC Membership Interest	2 [y]	100%
CalGen Expansion Company, LLC	Morgan Energy Center, LLC	LLC Membership Interest	2 [y]	100%
CalGen Expansion Company, LLC	Nueces Bay Energy LLC	LLC Membership Interest	1 [y]	100%
CalGen Expansion Company, LLC	Zion Energy LLC	LLC Membership Interest	1 [y]	100%
Calpine Administrative Services Company, Inc.	Calpine c*Power, Inc.	Common Stock	2	1,000
Calpine Auburndale Holdings, LLC	Auburndale Peaker Energy Center, LLC	LLC Membership Interest	3 y	100%
Calpine Baytown Energy Center GP, LLC	Baytown Energy Center, LP	Limited Partnership Interest	2 [y]	1%
Calpine CalGen Holdings, Inc.	Calpine Generating Company, LLC	LLC Membership Interest	2 [y]	100% 1

1 Subject to prior pledge to Wilmington Trust Company, as Collateral Agent, under the Membership Interest Pledge Agreement, dated March 23, 2004, between Calpine CalGen Holdings, Inc., Calpine Generating Company, LLC and Wilmington Trust Company.

Calpine California Holdings, Inc.	Calpine Peaker Holdings, LLC	LLC Membership Interest	No Certificate Issued [ n ]	50.6%
Calpine CCFC Holdings, Inc.	CCFC Preferred Holdings, LLC	LLC Membership Interest	3 [y]	99.8%
Calpine Power Company	CCFC Preferred Holdings, LLC	LLC Membership Interest	2 [y]	0.2%
Calpine Central Texas GP, Inc.	Calpine Central, L.P.	Limited Partnership Interest	No Certificate Issued [n]	1%
Calpine Central, Inc.	Calpine Central Texas GP, Inc.	Common Stock	1	1,000
Calpine Central, Inc.	Calpine Central-Texas, Inc.	Common Stock	No Certificate Issued	1,000
Calpine Central, Inc.	Calpine Hidalgo Holdings, Inc.	Common Stock	1	1,000
Calpine Central, Inc.	Calpine TCCL Holdings, Inc.	Common Stock	1	1,000
Calpine Central-Texas, Inc.	Calpine Central, L.P.	Limited Partnership Interest	No Certificate Issued [n]	99%
Calpine Channel Energy Center GP, LLC	Channel Energy Center, LP	Limited Partnership Interest	1 [y]	1%
Calpine Cogeneration Corporation	Calpine Newark, LLC	LLC Membership Interest	1 [y]	100%
Calpine Cogeneration Corporation	Calpine Philadelphia, Inc.	Common Stock	1	1,000
Calpine Cogeneration Corporation	Calpine Pryor, Inc.	Common Stock	3	100
Calpine Cogeneration Corporation	Calpine Schuylkill, Inc.	Common Stock	3	100
Calpine Cogeneration Corporation	CPN Funding, Inc.	Common Stock	1	1,000
Calpine Cogeneration Corporation	Philadelphia Biogas Supply, Inc.	Common Stock	3	1,000

Calpine Corporation	Calpine Administrative Services Company, Inc.	Common Stock	2	1,000
Calpine Corporation	Calpine Energy Services Holdings, Inc.	Common Stock	2	100
Calpine Corporation	Calpine Fuels Corporation	Common Stock	1	1,000
Calpine Corporation	Calpine Greenleaf Holdings, Inc.	Common Stock	1	1,000
Calpine Corporation	Calpine International Holdings, Inc.	Common Stock	2	1,000
Calpine Corporation	Calpine Monterey Cogeneration, Inc.	Common Stock	N/A	1,000 2
Calpine Corporation	Calpine Northbrook Corporation of Maine, Inc.	Common Stock	1	1,000
Calpine Corporation	Calpine Operations Management Company, Inc.	Common Stock	2	1,000
Calpine Corporation	Calpine Power Company	Common Stock	1	1,000
Calpine Eastern Corporation	Aviation Funding Corp.	Common Stock	3	42
Calpine Eastern Corporation	Bethpage Fuel Management Inc.	Common Stock	2	10
Calpine Eastern Corporation	Calpine Power, Inc.	Common Stock	3	1,000
Calpine Eastern Corporation	CPN 3rd Turbine, Inc.	Common Stock	1	1,000
Calpine Eastern Corporation	CPN Bethpage 3rd Turbine, Inc.	Common Stock	1	1,000
Calpine Eastern Corporation	GEC Bethpage Inc.	Common Stock	1	100
Calpine Eastern Corporation	Idlewild Fuel Management Corp.	Common Stock	2	100
Calpine Eastern Corporation	JMC Bethpage, Inc.	Common Stock	2	10
Calpine Eastern Corporation	Stony Brook Cogeneration Inc.	Common Stock	1	100

2 Subject to prior pledge to State Street Bank and Trust Company of California, N.A. under the Stock Pledge Agreement, dated June 22, 1995.

Calpine Eastern Corporation	Stony Brook Fuel Management Corp.	Common Stock	1	100
Calpine Eastern Corporation	TBG Cogen Partners	Partnership Interest	No Certificate Issued [n]	45%
Calpine Energy Services Holdings, Inc.	Calpine Power Management, Inc.	Common Stock	1	1,000
Calpine Energy Services Holdings, Inc.	Calpine PowerAmerica, Inc.	Common Stock	2	1,000
Calpine Energy Services Holdings, Inc.	CPN Energy Services GP, Inc.	Common Stock	4	1,000
Calpine Energy Services Holdings, Inc.	CPN Energy Services LP, Inc.	Common Stock	1	1,000
Calpine Freestone, LLC	Freestone Power Generation LP	Limited Partnership Interest	3 [y]	1%
Calpine Fuels Corporation	Calpine Magic Valley Pipeline, Inc.	Common Stock	1	1,000
Calpine Fuels Corporation	Calpine MVP, Inc.	Common Stock	4	1,000
Calpine Fuels Corporation	Calpine Sonoran Pipeline, LLC	LLC Membership Interest	2 [y]	100%
Calpine Fuels Corporation	Calpine Texas Pipeline GP, Inc.	Common Stock	1	1,000
Calpine Fuels Corporation	Calpine Texas Pipeline LP, Inc.	Common Stock	1	1,000
Calpine Fuels Corporation	CPN Decatur Pipeline, Inc.	Common Stock	1	1,000
Calpine Fuels Corporation	CPN Pipeline Company	Common Stock	2	1,000
CPN Funding, Inc.	CPN Morris, Inc.	Common Stock	2	1,000
Calpine Generating Company, LLC	CalGen Expansion Company, LLC	LLC Membership Interest	2 [y]	100% 3

3 Subject to prior pledge to Wilmington Trust Company under the Membership Interest Pledge Agreement, dated March 23, 2004, by and among Calpine Generating Company, LLC, CalGen Expansion Company, LLC and Wilmington Trust Company.

Calpine Generating Company, LLC	CalGen Finance Corp.	Common Stock	2	1,000
Calpine Gilroy 1, Inc.	Calpine Gilroy Cogen, L.P.	Limited Partnership Interest	No Certificate Issued [n]	1%
Calpine Gilroy 2, Inc.	Calpine Gilroy Cogen, L.P.	Limited Partnership Interest	No Certificate Issued [n]	99%
Calpine Hidalgo Holdings, Inc.	Calpine Edinburg, Inc.	Common Stock	1	1,000
Calpine Hidalgo Holdings, Inc.	Calpine Hidalgo, Inc.	Common Stock	1	1,000
Calpine Hidalgo, Inc.	Calpine Hidalgo Energy Center, L.P.	Limited Partnership Interest	No Certificate Issued [n]	1%
Calpine Kennedy Airport, Inc.	Calpine Kennedy Operators, Inc.	Common Stock	3	10
Calpine King City, Inc.	Calpine King City, LLC	LLC Membership Interest	2	100%
Calpine King City, LLC	King City Holdings, LLC	LLC Membership Interest	No Certificate Issued [n]	100%
Calpine KIA, Inc.	KIAC Partners	Partnership Interest	No Certificate Issued [n]	50%
Calpine Long Island, Inc.	Calpine Kennedy Airport, Inc.	Common Stock	2	10
Calpine Long Island, Inc.	Calpine University Power, Inc.	Common Stock	2	10
Calpine Magic Valley Pipeline, Inc.	Magic Valley Pipeline, L.P.	General Partnership Interest	1 [y]	1%
Calpine MVP, Inc.	Magic Valley Pipeline, L.P.	Limited Partnership Interest	3	99%
Calpine Northbrook Holdings Corporation	Calpine Northbrook Investors, LLC	LLC Membership Interest	3 [y]	100%
Calpine Northbrook Investors, LLC	Pine Bluff Energy, LLC	LLC Membership Interest	1 [y]	100%
Calpine Northbrook Project Holdings, LLC	RockGen Energy LLC	LLC Membership Interest	1—25% 2—25% 3—25% 4—25% [y]	100%

Calpine Oneta Power I, LLC	Calpine Oneta Power, L.P.	Limited Partnership Interest	3 [y]	1%
Calpine Oneta Power II, LLC	Calpine Oneta Power, L.P.	Limited Partnership Interest	4 [y]	99%
Calpine Operations Management Company, Inc.	Calpine Construction Management Company, Inc.	Common Stock	1	1,000
Calpine Operations Management Company, Inc.	Calpine Global Services Company, Inc.	Common Stock	3	1,000
Calpine Operations Management Company, Inc.	Calpine Operating Services Company, Inc.	Common Stock	1	1,000
Calpine Operations Management Company, Inc.	Calpine Power Services, Inc.	Common Stock	1	1,000
Calpine Operations Management Company, Inc.	Thomassen Turbine Systems America, Inc.	Common Stock	1	1,000
Calpine Operations Management Company, Inc.	Calpine Jupiter, LLC	LLC Membership Interest	1 [y]	100%
Calpine Power Company	Anacapa Land Company, LLC	LLC Membership Interest	2 [y]	100%
Calpine Power Company	Anderson Springs Energy Company	Common Stock	2	1,000
Calpine Power Company	Bellingham Cogen, Inc.	Common Stock	3	1,000
Calpine Power Company	Calpine Agnews, Inc.	Common Stock	8	3,000
Calpine Power Company	Calpine Auburndale Holdings, LLC	LLC Membership Interest	2 [y]	100%
Calpine Power Company	Calpine CalGen Holdings, Inc.	Common Stock	3	1,000
Calpine Power Company	Calpine California Holdings, Inc.	Common Stock	3	1,000

Calpine Power Company	Calpine Calistoga Holdings, LLC	LLC Membership Interest	3 [y]	100%
Calpine Power Company	Calpine CCFC Holdings, Inc.	Common Stock	1	1,000
Calpine Power Company	Calpine Central, Inc.	Common Stock	2	1,000
Calpine Power Company	Calpine Cogeneration Corporation	Common Stock	4	5,000
Calpine Power Company	Calpine BRSP, LLC	LLC Membership Interest	1 [y]	100%
Calpine Power Company	Calpine Development Holdings, Inc.	Common Stock	1	1,000
Calpine Power Company	Calpine Eastern Corporation	Common Stock	2	1,000
Calpine Power Company	Calpine King City, Inc.	Common Stock	1	1,000
Calpine Power Company	Calpine Leasing Inc.	Common Stock	1	1,000
Calpine Power Company	Calpine Northbrook Holdings Corporation	Common Stock	1	1,000
Calpine Power Company	Calpine Pittsburg, LLC	LLC Membership Interest	2 [y]	100%
Calpine Power Company	Calpine Project Holdings, Inc.	Common Stock	1	1,000
Calpine Power Company	Calpine Rumford I, Inc.	Common Stock	2	1,000
Calpine Power Company	Calpine Rumford, Inc.	Common Stock	3 (100 shares) 4 (100 shares)	200
Calpine Power Company	Calpine Sumas, Inc.	Common Stock	2	1,000
Calpine Power Company	Calpine Tiverton I, Inc.	Common Stock	2 (100 shares)	100
Calpine Power Company	Calpine Tiverton, Inc.	Common Stock	2	100
Calpine Power Company	CPN Cascade, Inc.	Common Stock	4	1,000
Calpine Power Company	CPN East Fuels, LLC	LLC Membership Interest	2	100%

Calpine Power Company	CPN Telephone Flat, Inc.	Common Stock	3	100
Calpine Power Company	Modoc Power, Inc.	Common Stock	2	1,000
Calpine Power Company	Mount Hoffman Geothermal Company, L.P.	Limited Partnership Interest	No Certificate Issued [n]	99%
Calpine Power Company	Northwest Cogeneration, Inc.	Common Stock	3	1,000
Calpine Power Company	South Point Holdings, LLC	LLC Membership Interest	6 [y]	100%
Calpine Power Company	Sutter Dryers, Inc.	Common Stock	2	1,000
Calpine Power, Inc.	Calpine KIA, Inc.	Common Stock	6	1,000
Calpine Power, Inc.	Calpine Long Island, Inc.	Common Stock	3	1,000
Calpine Project Holdings, Inc.	Mobile Energy L L C	LLC Membership Interest	4 y	100%
Calpine Pryor, Inc.	CPN Pryor Funding Corporation	Common Stock	4	1,000
Calpine Rumford I, Inc.	Rumford Power Associates Limited Partnership	Limited Partnership Interest	No Certificate Issued [n]	98%
Calpine Rumford, Inc	Rumford Power Associates Limited Partnership	Limited Partnership Interest	No Certificate Issued [n]	2%
Calpine Stony Brook, Inc.	Nissequogue Cogen Partners	Partnership Interest	No Certificate Issued [n]	50%
Calpine Sumas, Inc.	Whatcom Cogeneration Partners, L.P.	Limited Partnership Interest	No Certificate Issued [n]	25%
Calpine TCCL Holdings, Inc.	CPN Clear Lake, Inc.	Common Stock	No Certificate Issued [n]	100%
Calpine TCCL Holdings, Inc.	NTC Five, Inc.	Common Stock	No Certificate Issued [n]	100%
Calpine TCCL Holdings, Inc.	Texas Cogeneration Five, Inc.	Common Stock	No Certificate Issued [n]	100%

Calpine TCCL Holdings, Inc.	Texas Cogeneration One Company	Common Stock	No Certificate Issued [n]	100%
Calpine Texas Pipeline GP, Inc.	Calpine Texas Pipeline, L.P.	Limited Partnership Interest	4 [y]	1%
Calpine Texas Pipeline LP, Inc.	Calpine Texas Pipeline, L.P.	Limited Partnership Interest	3 [y]	99%
Calpine Tiverton I, Inc.	Tiverton Power Associates Limited Partnership	Limited Partnership Interest	No Certificate Issued [n]	98%
Calpine Tiverton, Inc.	Tiverton Power Associates Limited Partnership	Limited Partnership Interest	No Certificate Issued [n]	2%
Calpine University Power, Inc.	Calpine Stony Brook Operators, Inc.	Common Stock	3	10
Calpine University Power, Inc.	Calpine Stony Brook, Inc.	Common Stock	3	10
CCFC Development Company, LLC	Lone Oak Energy Center, LLC	LLC Membership Interest	1 [y]	100%
CPN Clear Lake, Inc.	Clear Lake Cogeneration Limited Partnership	Limited Partnership Interest	No Certificate Issued [n]	2%
CPN Funding, Inc	CPN Morris, Inc.	Common Stock	2	1,000
GEC Bethpage Inc.	TBG Cogen Partners	Partnership Interest	No Certificate Issued [n]	45%
Geysers Power I Company	Geysers Power Company, LLC	LLC Membership Interest	1 [y]	65.14303%
JMC Bethpage, Inc.	TBG Cogen Partners	Partnership Interest	No Certificate Issued [n]	10%
Modoc Power, Inc.	Calpine Siskiyou Geothermal Partners, L.P.	Limited Partnership Interest	No Certificate Issued [n]	44.34%
Modoc Power, Inc.	Mount Hoffman Geothermal Company, L.P.	Limited Partnership Interest	No Certificate Issued [n]	1%
Northwest Cogeneration, Inc.	Whatcom Cogeneration Partners, L.P.	Limited Partnership Interest	No Certificate Issued [n]	50%

Nueces Bay Energy LLC	Corpus Christi Cogeneration LP	Limited Partnership Interest	2 [y]	1%
Stony Brook Cogeneration Inc.	Nissequogue Cogen Partners	Partnership Interest	No Certificate Issued [n]	50%
Texas Cogeneration One Company	Texas City Cogeneration, L.P.	Limited Partnership Interest	No Certificate Issued [n]	0.10%
Thermal Power Company	Geysers Power I Company	Common Stock	2	100
Thermal Power Company	Geysers Power Company, LLC	LLC Membership Interest	3 [y]	34.85697%

Pledged Note:

Issuer	Payee		Principal Amount
Russell City Energy Company, LLC	Calpine Corporation		$	970,000.00

Pledged Notes:

SCHEDULE 3

FILINGS AND OTHER ACTIONS

REQUIRED TO PERFECT SECURITY INTERESTS

Uniform Commercial Code Filings

To duly file the appropriate UCC financing statements with the respective filing offices as set forth on Schedule 3.18(a) of the Credit Agreement, which is incorporated herein by reference.

Patent and Trademark Filings

To file and record a grant of security interest in United States Trademarks in the United States Patent and Trademark Office and to pay all filing and recordation fees associated therewith.

Actions with respect to Pledged Stock

To deliver the possession of the relevant certificates representing the Pledged Stock, the Pledged Note and the corresponding endorsement to the Collateral Agent (unless previously delivered to the Collateral Agent).

Other Actions

None.

SCHEDULE 4

LOCATION OF JURISDICTION OF ORGANIZATION

AND CHIEF EXECUTIVE OFFICE

Grantor	Jurisdiction of Organization	Location of Chief Executive Office
Calpine Corporation	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Anacapa Land Company, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Anderson Springs Energy Company	California	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Auburndale Peaker Energy Center, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Aviation Funding Corp.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Baytown Energy Center, LP	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Bellingham Cogen, Inc.	California	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Bethpage Fuel Management Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
CalGen Expansion Company, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
CalGen Finance Corp.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
CalGen Project Equipment Finance Company One, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
CalGen Project Equipment Finance Company Three, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
CalGen Project Equipment Finance Company Two, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Administrative Services Company, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002

Calpine Auburndale Holdings, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Baytown Energy Center GP, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Baytown Energy Center LP, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine c*Power, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine CalGen Holdings, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine California Holdings, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Calistoga Holdings, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine CCFC Holdings, Inc.	Delaware	717 Texas Avenue, Suite 13.063B Houston, Texas 77002
Calpine Central Texas GP, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Central, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Central, L.P.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Central-Texas, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Channel Energy Center GP, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Channel Energy Center LP, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Cogeneration Corporation	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Construction Management Company, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Eastern Corporation	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002

Calpine Edinburg, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Energy Services Holdings, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Freestone, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Fuels Corporation	California	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Generating Company, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Geysers Company, L.P.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Gilroy 1, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Gilroy 2, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Global Services Company, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Hidalgo Energy Center, L.P.	Texas	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Hidalgo Holdings, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Hidalgo, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Jupiter, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Kennedy Airport, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Kennedy Operators, Inc.	New York	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine KIA, Inc.	New York	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine King City, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002

Calpine King City, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Leasing Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Long Island, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Magic Valley Pipeline, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine MVP, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Newark, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Northbrook Corporation of Maine, Inc.	Illinois	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Northbrook Holdings Corporation	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Northbrook Investors, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Northbrook Project Holdings, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Northbrook Southcoast Investors, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Oneta Power I, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Oneta Power II, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Oneta Power, L.P.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Operating Services Company, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Operations Management Company, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Power Company	California	717 Texas Avenue, Suite 1000 Houston, Texas 77002

Calpine Power Services, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Power, Inc.	Virginia	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Project Holdings, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Pryor, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Rumford I, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Rumford, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Schuylkill, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Sonoran Pipeline, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Stony Brook Operators, Inc.	New York	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Stony Brook, Inc.	New York	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Sumas, Inc.	California	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine TCCL Holdings, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Texas Pipeline GP, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Texas Pipeline LP, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Texas Pipeline, L.P.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Tiverton I, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Calpine Tiverton, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002

Calpine University Power, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Carville Energy LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
CCFC Development Company, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
CCFC Project Equipment Finance Company One, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Channel Energy Center, LP	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Clear Lake Cogeneration Limited Partnership	Texas	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Columbia Energy LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Corpus Christi Cogeneration LP	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
CPN 3 rd Turbine, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
CPN Acadia, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
CPN Cascade, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
CPN Clear Lake, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
CPN Decatur Pipeline, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
CPN East Fuels, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
CPN Freestone, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
CPN Funding, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
CPN Morris, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002

CPN Pipeline Company	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
CPN Pryor Funding Corporation	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
CPN Telephone Flat, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Decatur Energy Center, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Delta Energy Center, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
East Altamont Energy Center, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Fontana Energy Center, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Freestone Power Generation LP	Texas	717 Texas Avenue, Suite 1000 Houston, Texas 77002
GEC Bethpage Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Geysers Power Company, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Geysers Power I Company	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Hillabee Energy Center, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Idlewild Fuel Management Corp.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
JMC Bethpage, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Lone Oak Energy Center, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Los Medanos Energy Center LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Magic Valley Pipeline, L.P.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002

Moapa Energy Center, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Mobile Energy L L C	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Modoc Power, Inc.	California	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Morgan Energy Center, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Northwest Cogeneration, Inc.	California	717 Texas Avenue, Suite 1000 Houston, Texas 77002
NTC Five, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Nueces Bay Energy LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Pastoria Energy Center, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Pastoria Energy Facility L.L.C.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Pine Bluff Energy, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
RockGen Energy LLC	Wisconsin	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Rumford Power Associates Limited Partnership	Maine	717 Texas Avenue, Suite 1000 Houston, Texas 77002
San Joaquin Valley Energy Center, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Santa Rosa Energy Center, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Stony Brook Cogeneration Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Stony Brook Fuel Management Corp.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Sutter Dryers, Inc.	California	717 Texas Avenue, Suite 1000 Houston, Texas 77002

Texas City Cogeneration, L.P.	Texas	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Texas Cogeneration Five, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Texas Cogeneration One Company	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Thermal Power Company	California	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Thomassen Turbine Systems America, Inc.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Tiverton Power Associates Limited Partnership	Rhode Island	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Wawayanda Energy Center, LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Whatcom Cogeneration Partners, L.P.	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002
Zion Energy LLC	Delaware	717 Texas Avenue, Suite 1000 Houston, Texas 77002

SCHEDULE 5

COPYRIGHTS AND COPYRIGHT LICENSES

None

PATENTS AND PATENT LICENSES

None

TRADEMARKS AND TRADEMARK LICENSES

Trademark	Jurisdiction	Application Number and Application Date	Registration Number and Registration Date	Owner
C and Design	Canada	1107005 19-Jun-2001	615304 20-Jul-2004	Calpine Corporation
C and Design	Canada	1107002 19-Jun-2001	608168 21-Apr-2004	Calpine Corporation
C and Design	European Community	002379311 17-Sep-2001	002379311 02-May-2003	Calpine Corporation
C and Design	Mexico	525716 19-Dec-2001	738363 19-Mar-2002	Calpine Corporation
C and Design	Mexico	525714 19-Dec-2001	737411 28-Feb-2002	Calpine Corporation
C and Design	Mexico	525712 19-Dec-2001	767957 11-Nov-2002	Calpine Corporation

C and Design	Mexico	525711 19-Dec-2001	826858 29-Mar-2004	Calpine Corporation
C and Design	Mexico	525713 19-Dec-2001	739096 25-Mar-2002	Calpine Corporation
C and Design	United States of America	76/195598 18-Jan-2001	2781097 11-Nov-2003	Calpine Corporation
CALPINE	Canada	1107004 19-Jun-2001	614674 12-Jul-2004	Calpine Corporation
CALPINE	Canada	1107003 19-Jun-2001	588644 02-Sep-2003	Calpine Corporation
CALPINE	European Community	002379360 17-Sep-2001	002379360 24-Apr-2003	Calpine Corporation
CALPINE	Mexico	525708 19-Dec-2001	800055 22-Jul-2003	Calpine Corporation
CALPINE	Mexico	525715 19-Dec-2001	744732 30-Apr-2002	Calpine Corporation
CALPINE	Mexico	525707 19-Dec-2001	744731 30-Apr-2002	Calpine Corporation
CALPINE	Mexico	525709 19-Dec-2001	737409 28-Feb-2002	Calpine Corporation
CALPINE	Mexico	525710 19-Dec-2001	737410 28-Feb-2002	Calpine Corporation
CALPINE	United States of America	76/195597 18-Jan-2001	2751748 19-Aug-2003	Calpine Corporation

REPOWERING AMERICA

United States of America

76/195596

18-Jan-2001

3098433

30-May-2006

Calpine Corporation

ACKNOWLEDGEMENT AND CONSENT

The undersigned hereby acknowledges receipt of a copy of the Amended and Restated Guarantee and Collateral Agreement dated as of January 31, 2008 and amended and restated as of December 10, 2010 (the “ Agreement ”), made by the Grantors parties thereto for the benefit of Goldman Sachs Credit Partners L.P., as Collateral Agent. The undersigned agrees for the benefit of the Collateral Agent and the Lenders as follows:

1. The undersigned will be bound by the terms of the Agreement and will comply with such terms insofar as such terms are applicable to the undersigned.

2. The undersigned will notify the Collateral Agent promptly in writing of the occurrence of any of the events described in Section 5.5(a) of the Agreement.

3. The terms of Sections 6.3(c) and 6.7 of the Agreement shall apply to it, mutatis mutandis , with respect to all actions that may be required of it pursuant to Section 6.3(c) or 6.7 of the Agreement.

	[NAME OF ISSUER]


	By:
		Name: Title:

	Address for Notices:



	Fax:

ANNEX 1 to

Guarantee and Collateral Agreement

ASSUMPTION AGREEMENT, dated as of ________________, 200_, made by ______________________________ (the “ Additional Grantor ”), in favor of Goldman Sachs Credit Partners L.P., as Collateral Agent (in such capacity, the “ Collateral Agent ”) for the Secured Parties referred to below. All capitalized terms not defined herein shall have the meaning ascribed to them in the Guarantee and Collateral Agreement referred to below.

W I T N E S S E T H :

WHEREAS, Calpine Corporation (the “ Borrower ”), the Existing Lenders and the Collateral Agent have entered into a Credit Agreement, dated as of January 31, 2008 (as amended, supplemented or otherwise modified from time to time, the “ Existing Credit Agreement ”);

WHEREAS, the Borrower, the Permitted Revolving Lenders and the Collateral Agent have entered into a Credit Agreement, dated as of December 10, 2010 (as amended, supplemented or otherwise modified from time to time, the “ Revolving Credit Agreement ”);

WHEREAS, in connection with the Existing Credit Agreement and the Revolving Credit Agreement, the Borrower and certain of its Affiliates (other than the Additional Grantor) have entered into the Amended and Restated Guarantee and Collateral Agreement, dated as of January 31, 2008 and amended and restated as of December 10, 2010, which amends and restates the Guarantee and Collateral Agreement dated as of January 31, 2008 (as amended, supplemented or otherwise modified from time to time, the “ Guarantee and Collateral Agreement ”) in favor of the Collateral Agent for the ratable benefit of the Secured Parties (as defined therein);

WHEREAS, one or more First Lien Documents requires the Additional Grantor to become a party to the Guarantee and Collateral Agreement; and

WHEREAS, the Additional Grantor has agreed to execute and deliver this Assumption Agreement in order to become a party to the Guarantee and Collateral Agreement;

NOW, THEREFORE, IT IS AGREED:

1. Guarantee and Collateral Agreement . By executing and delivering this Assumption Agreement, the Additional Grantor, as provided in Section 8.14 of the Guarantee and Collateral Agreement, hereby becomes a party to the Guarantee and Collateral Agreement as a Grantor and as a Guarantor thereunder with the same force and effect as if originally named therein as a Grantor and a Guarantor and, without limiting the generality of the foregoing, hereby expressly assumes all obligations and liabilities of a Grantor and a Guarantor thereunder and transfers and assigns to the Collateral Agent, and hereby grants to the Collateral Agent, for the ratable benefit of the Secured Parties, a security interest in, and a Lien on, its Collateral as collateral security for the prompt and complete payment and performance when due (whether at stated maturity, by acceleration or otherwise) of such Grantor’s Obligations. The information set forth in Annex 1-A hereto is hereby added to the information set forth in the Schedules to the

Guarantee and Collateral Agreement. The Additional Grantor hereby represents and warrants that each of the representations and warranties contained in Section 4 of the Guarantee and Collateral Agreement is true and correct on and as the date hereof (after giving effect to this Assumption Agreement) as if made on and as of such date.

2. GOVERNING LAW . THIS ASSUMPTION AGREEMENT SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK.

[remainder of page intentionally left blank]

IN WITNESS WHEREOF, the undersigned has caused this Assumption Agreement to be duly executed and delivered as of the date first above written.

	[ADDITIONAL GRANTOR]


	By:
		Name: Title:

ANNEX 1-A to

Assumption Agreement

Supplement to Schedule 1

Supplement to Schedule 2

Supplement to Schedule 3

Supplement to Schedule 4

Supplement to Schedule 5

EXHIBIT 31.1

CERTIFICATIONS

I, Jack A. Fusco, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Calpine Corporation (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: July 28, 2011

	/s/ JACK A. FUSCO
	Jack A. Fusco
	President, Chief Executive Officer
	and Director
	Calpine Corporation

EXHIBIT 31.2

CERTIFICATIONS

I, Zamir Rauf, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Calpine Corporation (the “registrant”);

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: July 28, 2011

	/s/ ZAMIR RAUF
	Zamir Rauf
	Executive Vice President and
	Chief Financial Officer
	Calpine Corporation

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Calpine Corporation (the “Company”) on Form 10-Q for the period ending June 30, 2011, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned does hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge, based upon a review of the Report:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operation of the Company.

	/s/ JACK A. FUSCO		/s/ ZAMIR RAUF
	Jack A. Fusco		Zamir Rauf
	President, Chief Executive Officer		Executive Vice President and
	And Director		Chief Financial Officer
	Calpine Corporation		Calpine Corporation

Dated: July 28, 2011

A signed original of this written statement required by Section 906 has been provided to Calpine Corporation and will be retained by Calpine Corporation and furnished to the Securities and Exchange Commission or its staff upon request.