UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_______________

Form 10-Q

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

For the quarterly period ended September 30, 2010
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:  444,530,340 shares of Common Stock, par value $.001 per share, outstanding on October 26, 2010.

CALPINE CORPORATION AND SUBSIDIARIES

REPORT ON FORM 10-Q

For the Quarter Ended September 30, 2010

INDEX
	Page
Definitions	iii
Forward-Looking Statements	viii
Where You Can Find Other Information	viii
PART I — FINANCIAL INFORMATION
Item 1.  Financial Statements
Consolidated Condensed Statements of Operations for the Three and Nine Months Ended September 30, 2010 and 2009	1
Consolidated Condensed Balance Sheets at September 30, 2010, and December 31, 2009	2
Consolidated Condensed Statements of Cash Flows for the Nine Months Ended September 30, 2010 and 2009	3
Notes to Consolidated Condensed Financial Statements	4
Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
Introduction and Overview	34
Results of Operations	38
Commodity Margin and Adjusted EBITDA	45
Liquidity and Capital Resources	52
Risk Management and Commodity Accounting	58
New Accounting Standards and Disclosure Requirements	63
Item 3.  Quantitative and Qualitative Disclosures About Market Risk	64
Item 4.  Controls and Procedures	64
PART II — OTHER INFORMATION
Item 1.  Legal Proceedings	65
Item 1A.  Risk Factors	65
Item 6.  Exhibits	66
Signatures	67

ii

ABBREVIATION	DEFINITION
2009 Form 10-K	Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on February 25, 2010
2017 First Lien Notes	$1.2 billion aggregate principal amount of 7 1/4% 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	$400 million aggregate principal amount of 8% senior secured notes due 2019, issued May 25, 2010
2020 First Lien Notes	$1.1 billion aggregate principal amount of 7.875% senior secured notes due 2020, issued July 23, 2010
2021 First Lien Notes	$2.0 billion aggregate principal amount of 7.50% senior secured notes due 2021, issued October 22, 2010
AB 32	The California Global Warming Solutions Act of 2006, Assembly Bill 32, Chapter 488, Statutes of 2006, as codified in the Health and Safety Code section 38500 et seq
Adjusted EBITDA	EBITDA as adjusted for the effects of (a) impairment charges, (b) reorganization items, (c) major maintenance expense, (d) operating lease expense, (e) any unrealized gains or losses on commodity derivative mark-to-market activity, (f) adjustments to reflect only the Adjusted EBITDA from our unconsolidated investments, (g) stock-based compensation expense, (h) non-cash gains or losses on sales, dispositions or impairments of assets, (i) non-cash gains and losses from intercompany foreign currency translations, (j) any gains or losses on the repurchase or extinguishment of debt, (k) Conectiv acquisition-related costs, (l) Adjusted EBITDA from our discontinued operations and (m) any 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	The average capacity factor, excluding peakers, is 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
BACT	Best available control technology
BLM	Bureau of Land Management of the U.S. Department of the Interior
Blue Spruce	Blue Spruce Energy Center, LLC, an indirect, wholly owned subsidiary that owns Blue Spruce Energy Center, a 310 MW natural gas-fired peaker power plant located in Aurora, Colorado
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
CAISO	California Independent System Operator
CalGen	Calpine Generating Company, LLC, an indirect, wholly owned subsidiary

iii

ABBREVIATION	DEFINITION
CalGen Third Lien Debt	Together, the $680,000,000 Third Priority Secured Floating Rate Notes Due 2011, issued by CalGen and CalGen Finance Corp.; and the $150,000,000 11 1/2% Third Priority Secured Notes Due 2011, issued by CalGen and CalGen Finance Corp., in each case repaid on March 29, 2007
Calpine BRSP	Calpine BRSP, LLC
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
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.
CCFC Old Notes	The $415 million total aggregate principal amount of Second Priority Senior Secured Floating Rate Notes Due 2011 issued by CCFC and CCFC Finance Corp., comprising $365 million aggregate principal amount issued August 14, 2003, and $50 million aggregate principal amount issued September 25, 2003, and redeemed, in each case, on June 18, 2009
CCFC Term Loans	The $385 million First Priority Senior Secured Institutional Term Loans due 2009 borrowed by CCFC under the Credit and Guarantee Agreement, dated as of August 14, 2003, among CCFC, the guarantors party thereto, and Goldman Sachs Credit Partners L.P., as sole lead arranger, sole bookrunner, administrative agent and syndication agent, and repaid on May 19, 2009
CCFCP	CCFC Preferred Holdings, LLC
CCFCP Preferred Shares	The $300 million of six-year redeemable preferred shares due 2011 issued by CCFCP and redeemed on or before July 1, 2009
CEHC	Conectiv Energy Holding Company, a wholly owned subsidiary of Conectiv
Chapter 11	Chapter 11 of the U.S. Bankruptcy Code
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 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 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 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 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

iv

ABBREVIATION	DEFINITION
Conectiv	Conectiv Energy, a wholly owned subsidiary of PHI
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 include 18 operating power plants and one plant under construction, with approximately 4,490 MW of capacity (including completion of the York Energy Center, formerly known as the Delta Project, under construction and scheduled upgrades)
Conectiv Purchase Agreement	Purchase Agreement by and among PHI, Conectiv, LLC, CEHC and NDH dated as of April 20, 2010
Confirmation Order	The order of the U.S. Bankruptcy Court entitled “Findings of Fact, Conclusions of Law, and Order Confirming Sixth Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the U.S. Bankruptcy Code,” entered December 19, 2007, confirming the Plan of Reorganization pursuant to section 1129 of the U.S. Bankruptcy Code
CPUC	California Public Utilities Commission
Director Plan	The Amended and Restated Calpine Corporation 2008 Director Incentive Plan
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 and the 2021 First Lien Notes
Freestone	Freestone Energy Center, a 994 MW natural gas-fired, combined-cycle power plant located near Fairfield, Texas
Geysers Assets	Our geothermal power plant assets, including our steam extraction and gathering assets, located in northern California consisting of 15 operating power plants and one plant not in operation
GHG(s)	Greenhouse gas(es), primarily carbon dioxide (CO2), and including methane (CH4), nitrous oxide (N2O), sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs) and perfluorocarbons (PFCs)
Greenfield LP	Greenfield Energy Centre LP, a 50% partnership interest between certain of our subsidiaries and a third party which operates the Greenfield Energy Centre, a 1,030 MW natural gas-fired, combined-cycle power plant in Ontario, Canada

v

ABBREVIATION	DEFINITION
Heat Rate(s)	A measure of the amount of fuel required to produce a unit of power
ISRA	Industrial Site Recovery Act
kWh	Kilowatt-hour(s), a measure of power produced
LIBOR	London Inter-Bank Offered Rate
Market Capitalization	As of any date, Calpine Corporation’s then market capitalization calculated using the rolling 30-day weighted average trading price of Calpine Corporation’s common stock, as defined in and calculated in accordance with the Calpine Corporation amended and restated certificate of incorporation
Market Heat Rate(s)	The regional power price divided by the corresponding regional natural gas price
MMBtu	Million Btu
MW	Megawatt(s), a measure of plant capacity
MWh	Megawatt hour(s), a measure of power produced
NDH	New Development Holdings, LLC, an indirect, wholly owned subsidiary of Calpine Corporation
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
NJDEP	New Jersey Department of Environmental Protection
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
PCF	Power Contract Financing, L.L.C.
PCF III	Power Contract Financing III, LLC
PG&E	Pacific Gas & Electric Company
PHI	Pepco Holdings, Inc.
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

vi

ABBREVIATION	DEFINITION
PSCo	Public Service Company of Colorado, a wholly owned subsidiary of Xcel Energy Inc.
PSD	Prevention of significant deterioration
REC	Renewable Energy Credit
RGGI	Regional Greenhouse Gas Initiative
Rocky Mountain	Rocky Mountain Energy Center, LLC, an indirect, wholly owned subsidiary that owns Rocky Mountain Energy Center, a 621 MW combined-cycle, natural gas-fired power plant located in Keenesburg, Colorado
SDG&E	San Diego Gas & Electric Company
SEC	U.S. Securities and Exchange Commission
SO2	Sulfur dioxide
South Point	South Point Energy Center, a 530 MW natural gas-fired combined-cycle power plant located in Mohave Valley, Arizona
Spark spread(s)	The difference between the sales price of power per MWh and the cost of fuel to produce it
Steam Adjusted Heat Rate	The adjusted Heat Rate for our natural gas-fired power plants, excluding peakers, calculated by dividing (a) the fuel consumed in Btu reduced by the net equivalent Btu in steam exported to a third party by (b) the kWh generated. Steam Adjusted Heat Rate is a measure of fuel efficiency, so the lower our Steam Adjusted Heat Rate, the lower our cost of generation
U.S. Bankruptcy Court	U.S. Bankruptcy Court for the Southern District of New York
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 MW natural gas-fired, cogeneration power plant in Ontario, Canada (50% equity interest held by our Canadian subsidiaries)
York Energy Center	565 MW dual fuel, combined-cycle generation power plant (formerly known as the Delta Project) under construction located in Peach Bottom Township, Pennsylvania, included in the Conectiv Acquisition

vii

Forward-Looking Statements

In addition to historical information, this Quarterly Report on Form 10-Q (this “Report”) contains “forward-looking statements” within the meaning of Section 27A of the U.S. Securities Act of 1933, as amended, and Section 21E of the Exchange Act. 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:

• The uncertain length and severity of the current general financial and economic downturn, the timing and strength of an economic recovery, if any, and their impacts on our business including demand for our power and steam products, the ability of customers, suppliers, service providers and other contractual counterparties to perform under their contracts with us and the cost and availability of capital and credit;

• 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;

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

• Our ability to manage our significant liquidity needs and to comply with covenants under our existing financing obligations, including our First Lien Credit Facility, First Lien Notes and NDH Project Debt;

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

• 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 GHG emissions and derivative transactions;

• 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;

• Seasonal fluctuations of our results and exposure to variations in weather patterns;

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

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

• Our ability to implement our business plan and strategy;

• 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;

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

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

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

• Our planned sale of Blue Spruce and Rocky Mountain may not close as planned;

• Future PJM capacity revenues expected from the Conectiv Acquisition may not occur at expected levels; and

• Other risks identified in this Report and our 2009 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

viii

with the SEC at the SEC’s public reference room at 100 F Street, NE, Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the SEC’s public reference facilities by calling the SEC at 1-800-SEC-0330. You may request copies of these documents, upon payment of a duplicating fee, by writing to the SEC at its principal office at 100 F Street, NE, Room 1580, Washington, D.C. 20549.

ix

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
	(in millions, except share and per share amounts)
Operating revenues	$	2,130		$	1,822		$	5,074		$	4,919
Cost of revenue:
Fuel and purchased energy expense		1,143			1,030			3,016			2,967
Plant operating expense		199			189			630			638
Depreciation and amortization expense		149			104			414			317
Other cost of revenue		20			19			65			62
Total cost of revenue		1,511			1,342			4,125			3,984
Gross profit		619			480			949			935
Sales, general and other administrative expense		44			38			122			131
(Income) loss from unconsolidated investments in power plants		(1	)		13			(14	)		(27	)
Other operating expense		22			6			29			15
Income from operations		554			423			812			816
Interest expense		314			195			722			604
Interest (income)		(2	)		(3	)		(8	)		(13	)
Debt extinguishment costs		20			16			27			49
Other (income) expense, net		3			4			9			6
Income before reorganization items, income taxes and discontinued operations		219			211			62			170
Reorganization items		—			(8	)		—			(2	)
Income before income taxes and discontinued operations		219			219			62			172
Income tax expense (benefit)		21			(7	)		38			17
Income before discontinued operations		198			226			24			155
Discontinued operations, net of tax expense		19			11			31			34
Net income		217			237			55			189
Net loss attributable to the noncontrolling interest		—			1			—			3
Net income attributable to Calpine	$	217		$	238		$	55		$	192
Basic earnings per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands)		486,088			485,736			486,023			485,619
Income before discontinued operations attributable to Calpine	$	0.41		$	0.47		$	0.05		$	0.33
Discontinued operations, net of tax expense, attributable to Calpine		0.04			0.02			0.06			0.07
Net income per common share – basic	$	0.45		$	0.49		$	0.11		$	0.40
Diluted earnings per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands)		487,443			486,585			487,199			486,171
Income before discontinued operations attributable to Calpine	$	0.41		$	0.47		$	0.05		$	0.32
Discontinued operations, net of tax expense, attributable to Calpine		0.04			0.02			0.06			0.07
Net income per common share – diluted	$	0.45		$	0.49		$	0.11		$	0.39

The accompanying notes are an integral part of these

Consolidated Condensed Financial Statements.

1

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited)

	September 30,			December 31,
	2010			2009
	(in millions, except
	share and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents ($437 and $242 attributable to VIEs. See Note 1)	$	914		$	989
Accounts receivable, net of allowance of $3 and $14		718			750
Margin deposits and other prepaid expense		253			490
Restricted cash, current ($265 and $322 attributable to VIEs. See Note 1)		296			508
Derivative assets, current		1,321			1,119
Assets held for sale ($545 attributable to VIEs. See Note 1)		545			—
Inventory and other current assets		295			243
Total current assets		4,342			4,099
Property, plant and equipment, net ($6,744 and $5,319 attributable to VIEs. See Note 1)		12,915			11,583
Restricted cash, net of current portion ($40 and $45 attributable to VIEs. See Note 1)		45			54
Investments		69			214
Long-term derivative assets		318			127
Other assets		693			573
Total assets	$	18,382		$	16,650
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	523		$	578
Accrued interest payable		132			54
Debt, current portion ($552 and $106 attributable to VIEs. See Note 1)		574			463
Derivative liabilities, current		1,247			1,360
Liabilities held for sale ($11 attributable to VIEs. See Note 1)		11			—
Other current liabilities		299			294
Total current liabilities		2,786			2,749
Debt, net of current portion ($4,027 and $3,042 attributable to VIEs. See Note 1)		10,043			8,996
Deferred income taxes, net of current portion		159			54
Long-term derivative liabilities		499			197
Other long-term liabilities		275			208
Total liabilities		13,762			12,204
Commitments and contingencies (see Note 14)
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; 444,949,620 and 443,325,827 shares issued, respectively, and 444,501,702 and 442,998,255 shares outstanding, respectively		1			1
Treasury stock, at cost, 447,918 and 327,572 shares, respectively		(5	)		(3	)
Additional paid-in capital		12,275			12,256
Accumulated deficit		(7,485	)		(7,540	)
Accumulated other comprehensive loss		(166	)		(266	)
Total Calpine stockholders’ equity		4,620			4,448
Noncontrolling interest		—			(2	)
Total stockholders’ equity		4,620			4,446
Total liabilities and stockholders’ equity	$	18,382		$	16,650

The accompanying notes are an integral part of these

Consolidated Condensed Financial Statements.

2

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited) 

		Nine Months Ended September 30,
		2010			2009
		(in millions)
Cash flows from operating activities:
Net income		$	55		$	189
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense (1)			464			399
Debt extinguishment costs			27			9
Deferred income taxes			40			15
Impairment loss			19			—
Loss on disposal of assets			11			29
Unrealized mark-to-market activity, net			(97	)		(67	)
Income from unconsolidated investments in power plants			(14	)		(27	)
Return on investment in unconsolidated subsidiaries			11			2
Stock-based compensation expense			18			30
Other			1			(3	)
Change in operating assets and liabilities:
Accounts receivable			34			(23	)
Derivative instruments, net			(42	)		(239	)
Other assets			241			387
Accounts payable and accrued expenses			(1	)		13
Other liabilities			16			(177	)
Net cash provided by operating activities			783			537
Cash flows from investing activities:
Purchases of property, plant and equipment			(191	)		(140	)
Purchase of Conectiv assets			(1,634	)		—
Cash acquired due to consolidation of OMEC			8			—
Contributions to unconsolidated investments			—			(19	)
(Increase) decrease in restricted cash			228			(2	)
Other			4			(3	)
Net cash used in investing activities			(1,585	)		(164	)
Cash flows from financing activities:
Repayments of project financing, notes payable and other			(472	)		(1,339	)
Borrowings from project financing, notes payable and other			1,272			1,028
Issuance of First Lien Notes			1,491			—
Repayments on First Lien Credit Facility			(1,507	)		(770	)
Financing costs			(67	)		(34	)
Refund of financing costs			10			—
Other			—			(2	)
Net cash provided by (used in) financing activities			727			(1,117	)
Net decrease in cash and cash equivalents			(75	)		(744	)
Cash and cash equivalents, beginning of period			989			1,657
Cash and cash equivalents, end of period		$	914		$	913
Cash paid during the period for:
Interest, net of amounts capitalized	$		488		$	563
Income taxes	$		11		$	6
Reorganization items included in operating activities, net	$		—		$	5
Supplemental disclosure of non-cash investing and financing activities:
Settlement of commodity contract with project financing	$		—		$	79
Change in capital expenditures included in accounts payable	$		(5	)	$	3
Purchase of Conectiv assets included in accounts payable	$		6		$	—

__________

(1) Includes depreciation and amortization that is also recorded in sales, general and other administrative expense and interest expense on our Consolidated Condensed Statements of Operations.

The accompanying notes are an integral part of these

Consolidated Condensed Financial Statements.

3

CALPINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

September 30, 2010

(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 primarily of natural gas-fired and geothermal power plants in North America. We have a significant presence in the major competitive power markets in the U.S., including CAISO, ERCOT and Eastern PJM. 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 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, 2009, included in our 2009 Form 10-K. The results for interim periods are not necessarily indicative of the results for the entire year primarily due to 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.

Consolidation of OMEC — We were required by U.S. GAAP to adopt new accounting standards for VIEs which became effective January 1, 2010 and required us to perform an analysis to determine whether we should consolidate any of our previously unconsolidated VIEs or deconsolidate any of our previously consolidated VIEs. We completed our required analysis and determined that we are the primary beneficiary of OMEC. Accordingly, as required by U.S. GAAP, we consolidated OMEC effective January 1, 2010. The consolidation of OMEC on January 1, 2010 was accounted for using historical cost and resulted in the addition to our Consolidated Condensed Balance Sheet of approximately $8 million in cash and cash equivalents, $535 million in property, plant and equipment, net, $26 million in other current and non-current assets, $375 million in project debt and $50 million in other current and non-current liabilities, and the removal of $144 million representing our investment balance in OMEC. Our Consolidated Condensed Financial Statements as of and for the three and nine months ended September 30, 2010, include the consolidated balances of OMEC. We presented our investment in OMEC’s net assets, revenues and expenses under the equity method of accounting as of December 31, 2009, and for the three and nine months ended September 30, 2009. We made no other changes to our group of subsidiaries that we consolidate as a result of the adoption of these new standards. See Note 4 for further discussion of accounting for our VIEs.

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.

Fair Value of Financial Instruments and Derivatives — The carrying values of cash equivalents (including amounts in restricted cash), accounts receivable, accounts payable and other receivables and payables approximate their respective fair values due to their short-term maturities. See Note 6 for disclosures regarding the fair value of our debt instruments and Notes 7 and 8 for disclosures regarding the fair values of our derivative instruments.

Concentrations of Credit Risk — Financial instruments that potentially subject us to credit risk consist of cash and cash equivalents, restricted cash, accounts and notes receivable and derivative assets. Certain of our cash and cash equivalents, as well as our restricted cash balances, exceed FDIC insured limits or are invested in money market accounts with investment banks that are not FDIC insured. We place our cash and cash equivalents and restricted cash in what we believe are 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. Additionally, we actively

4

monitor the credit risk of our receivable and derivative counterparties. Our accounts and notes receivable are concentrated within entities engaged in the energy industry, mainly within the U.S. We generally have not collected collateral for accounts receivable from utilities and end-user customers; however, we may require collateral in the future. For financial and commodity counterparties, we evaluate the net accounts receivable, accounts payable and fair value of commodity contracts and may require security deposits, cash margin or letters of credit to be posted if our exposure reaches a certain level or their credit rating declines.

Cash and Cash Equivalents — We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts which have been pledged as security in favor of the lenders under such project finance facilities, and the use of certain cash balances on deposit in such accounts is limited, at least temporarily, to the operations of the respective projects. At September 30, 2010, and December 31, 2009, we had cash and cash equivalents of $304 million and $264 million, respectively, that were subject to such project finance facilities and lease agreements. Cash and cash equivalent balances that can only be used to settle the obligations of our consolidated VIEs have been disclosed on the face of our Consolidated Condensed Balance Sheets as required under the new accounting standards for VIEs. See Note 4 for a further discussion of accounting for our VIEs.

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 are restricted. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent, major maintenance and debt repurchases or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Condensed Balance Sheets and Statements of Cash Flows. The table below represents the components of our restricted cash as of September 30, 2010, and December 31, 2009 (in millions):

	September 30, 2010						December 31, 2009
	Current		Non-Current		Total		Current		Non-Current		Total
Debt service	$	48	$	24	$	72	$	193	$	25	$	218
Rent reserve		23		5		28		34		—		34
Construction/major maintenance		89		9		98		87		22		109
Security/project/insurance		120		—		120		146		—		146
Other		16		7		23		48		7		55
Total	$	296	$	45	$	341	$	508	$	54	$	562

Inventory — At September 30, 2010, and December 31, 2009, we had inventory of $260 million and $209 million, respectively. Inventory primarily consists of spare parts, stored natural gas and other fuel, emission reduction credits and natural gas exchange imbalances. Inventory, other than spare parts, is stated primarily at the lower of cost or market value under the weighted average cost method. Spare parts inventory is valued at weighted average cost and are expensed to plant operating expense or capitalized to property, plant and equipment as the parts are utilized and consumed.

Investments — We use the equity method of accounting to record our net interest in Greenfield LP, a 50% partnership interest and Whitby, a 50% equity interest where we exercise significant influence over operating and financial policies. As discussed above, we presented our investment in OMEC’s net assets, revenues and expenses under the equity method of accounting as of December 31, 2009, and for the three and nine months ended September 30, 2009. Our share of net income (loss) is calculated according to our equity ownership or according to the terms of the applicable partnership agreement. See Note 4 for further discussion of our VIEs and unconsolidated investments.

New Accounting Standards and Disclosure Requirements

Consolidation of VIEs and Additional VIE Disclosures — Effective for interim and annual periods beginning after November 15, 2009, the Financial Accounting Standards Board amended the accounting standards for determining which enterprise is the primary beneficiary of a VIE, added additional VIE disclosure requirements and amended guidance for determining whether an entity is a VIE. The new standards generally replace the quantitative-based risks and rewards calculation for determining which enterprise, if any, is the primary beneficiary of a VIE to a more qualitative assessment with an approach focused on identifying which enterprise has the power to direct the activities of a VIE that most significantly

5

impacts the VIE’s economic performance and also has the obligation to absorb losses or receive benefits from the VIE. We completed our analysis during the first quarter of 2010, and determined that the consolidation of OMEC was required. See Note 4 for further discussion of implementation of these new accounting standards.

The new standards and disclosure requirements also added:

• A requirement to perform ongoing reassessments each reporting period of whether we are the primary beneficiary of our VIEs, which could require us to consolidate our VIEs that are currently not consolidated or deconsolidate our VIEs that are currently consolidated based upon our reassessments in future periods. No further changes to our determinations of whether we are the primary beneficiary of our VIEs were required during the third quarter of 2010.

• Disclosure provisions to present separately on the face of the statement of financial position the significant assets of a consolidated VIE that can be used only to settle obligations of the consolidated VIE and the significant liabilities of a consolidated VIE for which creditors (or beneficial interest holders) do not have recourse to the general credit of the primary beneficiary. Our Consolidated Condensed Balance Sheets include these required disclosures. The new standards also reduce required disclosures for consolidated VIEs without such restrictions if we are the equity holder and primary beneficiary.

• An additional reconsideration event for determining whether an entity is a VIE if 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.

Fair Value Measurements and Disclosures — In January 2010, the Financial Accounting Standards Board issued Accounting Standards Update 2010-06, “Fair Value Measurements and Disclosures” to enhance disclosure requirements relating to different levels of assets and liabilities measured at fair value and to clarify certain existing disclosures. The update requires disclosure of significant transfers in and out of levels 1 and 2 and gross presentation of purchases, sales, issuances and settlements in the level 3 reconciliation of beginning and ending balances. The new disclosure requirements relating to level 3 activity are effective for interim and annual periods beginning after December 15, 2010, and all the other requirements are effective for interim and annual periods beginning after December 15, 2009. We adopted all of the disclosure requirements related to this update for the three and nine months ended September 30, 2010 and 2009. Since this update only required additional disclosures, adoption of this standard did not have a material impact on our results of operations, cash flows or financial condition. See Note 7 for disclosure of our fair value measurements in accordance with these disclosure requirements.

2.   Acquisitions and Planned Divestitures

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 one plant under construction, with approximately 4,490 MW of capacity (including completion of the York Energy Center under construction and 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 128 union employees acquired in the Conectiv Acquisition of less than $10 million on the acquisition date. Our purchase price was approximately $1.64 billion. The net proceeds of $1.3 billion received from the NDH Project Debt were used, together with available 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. See Note 6 for further discussion of the NDH Project Debt.

The Conectiv Acquisition provided us with a significant presence in the Eastern PJM market, one of the most robust competitive power markets in the U.S., and positioned us with three scale markets instead of two (CAISO and ERCOT) 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 three and nine months ended September 30, 2010, we expensed transaction and acquisition-related costs

6

of approximately $6 million and approximately $25 million, respectively, of which, $5 million and $24 million, respectively, were included in sales, general and other administrative expense, and $1 million was included in plant operating expense on our Consolidated Condensed Statements of Operations.

The following table summarizes the consideration transferred for the Conectiv Acquisition and the preliminary values we assigned to the net assets acquired (in millions). The amounts below include revisions to the unrecorded and preliminary appraised values as presented in our June 30, 2010 Form 10-Q. Our preliminary values assigned below are still subject to finalization of working capital and other adjustments to the purchase price and finalization of the pension liability analysis and environmental site investigation/remediation reports. Our depreciation expense included for the three and nine months ended September 30, 2010, on the assets we obtained in the Conectiv Acquisition is based upon the preliminary values assigned below and represents our best estimate. Future changes, if any, to the values assigned could change our estimates of our depreciation expense in future periods; however, such changes, if any, are not expected to be material. We do not anticipate any significant goodwill will be recognized as a result of this acquisition.

Consideration	$	1,640
Preliminary values of identifiable assets acquired and liabilities assumed:
Assets:
Current assets	$	80
Property, plant and equipment, net		1,577
Other long-term assets		75
Total assets acquired		1,732
Liabilities:
Current liabilities		45
Long-term liabilities		47
Total liabilities assumed		92
Net assets acquired	$	1,640

During the three months ended September 30, 2010, the Conectiv Acquisition contributed $274 million in operating revenues and $91 million net income attributable to Calpine included in our Consolidated Condensed Statement of Operations.

The following table summarizes the pro forma operating revenues and net income (loss) attributable to Calpine for the periods presented as if the Conectiv Acquisition had occurred on January 1, 2009. The pro forma information has been prepared by adding the preliminary, unaudited historical results of Conectiv, as adjusted for depreciation expense (utilizing the preliminary values assigned to the net assets acquired from Conectiv disclosed above), interest expense from our NDH Project Debt and income taxes to our historical results for the periods indicated below (in millions, except per share amounts).

	Three Months
	Ended		Nine Months Ended September 30,
	September 30, 2009		2010			2009
Operating revenues	$	2,403	$	6,460		$	6,544
Net income (loss) attributable to Calpine	$	250	$	(59	)	$	132
Basic earnings (loss) per common share attributable to Calpine	$	0.51	$	(0.12	)	$	0.27
Diluted earnings (loss) per common share attributable to Calpine	$	0.51	$	(0.12	)	$	0.27

Acquisition of Broad River and South Point

On September 23, 2010, we, through our wholly owned, indirect subsidiary, Calpine BRSP, entered into a purchase agreement with CIT Capital USA Inc., to purchase the equity interests related to our Broad River and South Point power plants for $320 million. We currently operate the Broad River power plant under a lease which did not qualify as a sale-leaseback transaction under U.S. GAAP, and the lease obligation is accounted for as debt in our project financing, notes payable and other debt balance, and we operate the South Point power plant under an operating lease, both with CIT Capital USA Inc. The purchase price consists of cash of approximately $38 million and assumed debt of approximately $282 million. However, the purchase of the equity interests is expected to only add an incremental $72 million in consolidated debt as the transaction will eliminate approximately $210 million in debt owed to CIT Capital USA Inc. by our Broad River power plant. This transaction requires FERC approval and is expected to close in the fourth quarter of 2010.

7

Sale of Blue Spruce and Rocky Mountain

On April 2, 2010, we, through our wholly owned subsidiaries Riverside Energy Center, LLC and Calpine Development Holdings, Inc., entered into an agreement with PSCo to sell 100% of our ownership interests in Blue Spruce and Rocky Mountain for approximately $739 million, subject to certain working capital adjustments at closing. Both power plants currently provide power and capacity to PSCo under PPAs, which materially expire in 2013 and 2014. Under the agreement, Riverside Energy Center, LLC and Calpine Development Holdings, Inc. will use commercially reasonable efforts to cause Blue Spruce and Rocky Mountain to continue to operate and maintain the power plants in the ordinary course of business through the closing of the transaction. As of the filing of this Report, we have received all of the required approvals and we expect the sale to close in December 2010. The transaction is expected to remove the restrictions on approximately $86 million in restricted cash at closing. We expect to use the sales proceeds received and the approximately $86 million in restricted cash described above to repay project debt of approximately $418 million, for general corporate purposes and to focus more resources on our core markets. We expect to record a pre-tax gain of approximately $220 million upon closing this transaction.

The assets and liabilities of Blue Spruce and Rocky Mountain are reported as assets and liabilities held for sale on our Consolidated Condensed Balance Sheet at September 30, 2010. The results of operations of Blue Spruce and Rocky Mountain are reported as discontinued operations on our Consolidated Condensed Statements of Operations for the three and nine months ended September 30, 2010 and 2009.

The tables below present the components of assets and liabilities held for sale at September 30, 2010, and discontinued operations for the periods indicated (in millions):

	September 30, 2010
Assets:
Current assets	$	14
Property, plant and equipment, net		513
Other long-term assets		18
Total assets held for sale	$	545
Liabilities:
Total liabilities held for sale, current	$	11

	Three Months Ended September 30,					Nine Months Ended September 30,
	2010			2009		2010		2009
Operating revenues	$	25		$	25	$	74	$	76
Income from discontinued operations before income taxes	$	17		$	11	$	37	$	34
Income tax expense (benefit)		(2	)		—		6		—
Discontinued operations, net of tax expense	$	19		$	11	$	31	$	34

Sale of Partial Interest in Freestone

On October 27, 2010, we entered into an asset purchase and sale agreement to sell a 25% undivided interest in the assets of our Freestone power plant for approximately $215 million in cash at closing and will receive annual operating and energy management fees going forward. The sale is expected to close in the fourth quarter of 2010, but no later than the first quarter of 2011. We will continue to operate Freestone after the sale.

8

3.  Property, Plant and Equipment, Net

As of September 30, 2010, and December 31, 2009, the components of property, plant and equipment were stated at cost less accumulated depreciation as follows (in millions):

	September 30, 2010		December 31, 2009
Buildings, machinery and equipment	$	14,636	$	13,373
Geothermal properties		1,089		1,050
Other		247		232
		15,972		14,655
Less: Accumulated depreciation		3,590		3,322
		12,382		11,333
Land		103		74
Construction in progress		430		176
Property, plant and equipment, net	$	12,915	$	11,583

Change in Depreciation Methods, Useful Lives and Salvage Values

As discussed in our 2009 Form 10-K and as described below, effective October 1, 2009, we made two changes to our methods of depreciation including (i) changing from composite depreciation to component depreciation for our rotable parts utilized in our natural gas-fired power plants and (ii) changing from the units of production method to the straight line method for our Geysers Assets. In addition, we completed a life study for each of our natural gas-fired power plants and our Geysers Assets, and changed our estimate of the remaining useful lives of our power plants and the useful lives and salvage values of our rotable parts utilized in our natural gas-fired power plants.

Component Depreciation for Rotable Parts at our Natural Gas-Fired Power Plants — During the three and nine months ended September 30, 2009, we used the composite depreciation method for all of our natural gas-fired power plant assets. Under this method, all assets comprising each power plant were combined into one group and depreciated under a composite depreciation rate. Effective October 1, 2009, we componentized our rotable parts for our natural gas-fired power plant assets for purposes of calculating depreciation. The change in the method of depreciation for rotable parts was considered a change in accounting estimate inseparable from a change in accounting principle, and resulted in changes to our depreciation expense prospectively. The change to component depreciation for our rotable parts utilized in our natural gas-fired power plants also resulted in changes to the useful lives of our rotable parts which are now generally estimated to range from 3 to 18 years. Furthermore, we reduced our estimate of salvage value for our rotable parts to 0.15% of original cost to reflect our expectation with these separable parts. Prior to this change, our composite useful lives for our natural gas-fired power plant assets, including our rotable parts, were 35 years and 40 years for our combined-cycle and our simple-cycle power plant assets, respectively. We also revised the estimated useful lives of our remaining composite pools to 37 years and 47 years for our combined-cycle and simple-cycle power plant assets, respectively, based in part on the results of our separate useful life study. Our change in useful lives is considered a change in accounting estimate and resulted in changes to our depreciation expense prospectively.

Straight Line Method for our Geysers Assets — During the three and nine months ended September 30, 2009, our Geysers Assets used the units of production method for depreciation. Our units of production depreciation rate was calculated using a depreciable base of the net book value of the Geysers Assets plus the expected future capital expenditures over the economic life of the geothermal reserves. The rate of depreciation per MWh was determined by dividing the depreciable base by total expected future generation. As a result of our change from the units of production method to the straight line method for our Geysers Assets, and based in part on the results of our separate useful life study, we revised our estimates of the remaining composite useful lives of our Geysers Assets effective October 1, 2009 to 59 years and 13 years for our Geysers steam extraction and gathering assets and our Geysers power plant assets, respectively. Our change in the method of depreciation for our Geysers Assets is considered a change in accounting estimate inseparable from a change in accounting principle, and resulted in changes to depreciation expense prospectively.

9

Impairment of Development Costs

During the three months ended September 30, 2010, we impaired development costs of approximately $19 million associated with a development project that originated prior to our Chapter 11 bankruptcy proceedings. We continued to market the project after our Effective Date; however, during the third quarter of 2010, we learned the project would not receive a PPA that would support its continued development and made the determination that continued development was unlikely. The expense is included in other operating expense on our Consolidated Condensed Statement of Operations and reflected in our Southeast segment.

4.  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:

VIEs with a Purchase Option — We have six subsidiaries with PPAs or other agreements that provide third parties the option to purchase power plant assets, an equity interest, or a portion of the future cash flows generated from an asset. The purchase options are exercisable only within a specified period of time upon expiration of the PPA or other agreements which expire at various dates occurring from 2011 – 2032.

Subsidiaries with Project Debt — Certain of our subsidiaries have project debt that contains provisions which we have determined create variability. 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 6 for further information regarding our project debt and Note 1 for information regarding our restricted cash balances.

Subsidiaries with PPAs — Certain of our wholly owned subsidiaries have PPAs that are deemed to be a form of subordinated financial support and thus constitute a VIE.

Other VIEs — Our other consolidated VIEs as of December 31, 2009, primarily consisted of monetized assets secured by financing for our PCF and PCF III subsidiaries. These financings were fully repaid during the first quarter of 2010 and are no longer VIEs.

New Accounting Standards and Disclosure Requirements for VIEs

Implementation — As further discussed in Note 1, new accounting standards became effective January 1, 2010 related to accounting for and consolidation of VIEs, which required us to perform an analysis upon implementation and ongoing reassessments each reporting period of whether we are the primary beneficiary of our VIEs. The new standards generally replaced the quantitative-based risks and rewards calculation for determining which enterprise, if any, is the primary beneficiary of a VIE to a more qualitative assessment with an approach focused on identifying which enterprise has 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.

As required, we performed an analysis of all of our VIEs effective January 1, 2010 and, with the exception of OMEC, our determination of the primary beneficiary did not change. No further changes to our determinations of whether we are the primary beneficiary of our VIEs were required during the third quarter of 2010. We concluded 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 analysis to determine the primary beneficiary focused on determining which variable interest holder has the power to direct the most significant activities of the VIE (the primary beneficiary). Our analysis included 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, 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 was based on powers held as of the balance sheet date. Contractual terms that will apply in future periods, such as a purchase or sale option, were not considered in our analysis. Based on our analysis, we determined that we hold the power and rights to direct the most significant activities of all our wholly owned VIEs.

OMEC — During the second quarter of 2007, we determined that SDG&E had a greater variability of risk compared to us based upon the prior consolidation accounting standards, which focused on which party held the greater variability in

10

the obligation to absorb the losses or the right to receive benefits from the VIE or both. We determined that SDG&E held the greater variability as a result of a put option held by OMEC to sell the Otay Mesa Energy Center for $280 million to SDG&E, and a call option held by SDG&E to purchase the Otay Mesa Energy Center for $377 million in 2019. Accordingly, we were not the primary beneficiary, consolidation was not appropriate and we accounted for our investment in OMEC under the equity method of accounting through December 31, 2009.

The transfer of ownership in conjunction with the exercise of the put/call option, which was the driving factor in the quantitative determination of the primary beneficiary under the previous accounting standards, would not occur until 2019. Neither we, nor SDG&E, hold any powers under the combination put/call option as of January 1, 2010. Accordingly, we did not include the benefits and obligations of the put/call option in the new determination of the primary beneficiary under the current accounting standards. Based upon our analysis, we believe the significant activity that has the most impact on the financial performance of OMEC is operations and maintenance which is controlled by us. As a result, we changed our determination of the primary beneficiary from SDG&E to us effective January 1, 2010.

New Disclosures — Implementation of the new accounting standards also required separate disclosure on the face of our Consolidated Condensed Balance Sheet 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 separately.

In determining which assets of our VIEs met the separate disclosure criteria, we reviewed all of our VIEs and determined this separate disclosure requirement was met where Calpine Corporation was substantially limited or prohibited from access to assets (primarily cash and cash equivalents, restricted cash and property, plant and equipment), where the VIE was not a guarantor or grantor under our primary debt facilities (our First Lien Credit Facility and First Lien Notes) and where there were prohibitions of the VIE under agreements that prohibited guaranteeing the debt of Calpine Corporation or its other subsidiaries and where the amounts were material to our financial statements. 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, where Calpine Corporation has not provided a corporate guarantee and where the amounts were material to our financial statements.

The VIEs meeting the above disclosure criteria are wholly owned subsidiaries of Calpine Corporation and include natural gas-fired power plants with an aggregate capacity of approximately 15,331 MW. 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. During the three and nine months ended September 30, 2010, Calpine Corporation provided $540 million to NDH, an indirect, wholly owned subsidiary, to fund the Conectiv Acquisition, including $110 million to complete the construction of the York Energy Center. Additionally, Calpine Corporation provided support to our other VIEs in the form of other cash contributions other than amounts contractually required of approximately $8 million and $10 million during the three and nine months ended September 30, 2010, respectively.

Unconsolidated VIEs and Investments

We have a 50% partnership interest in Greenfield LP and a 50% equity interest in Whitby where we do not have the power to direct the most significant activities of these entities and therefore do not consolidate them. Greenfield LP and Whitby are also VIEs. 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 as we exercise significant influence over their operating and financial policies. During 2009, we were not the primary beneficiary of OMEC and did not consolidate OMEC. Our equity interest in the net income (loss) from OMEC for the three and nine months ended September 30, 2009, and both Greenfield LP and Whitby for the three and nine months ended September 30, 2010 and 2009, are recorded in income from unconsolidated investments in power plants.

11

At September 30, 2010, and December 31, 2009, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):

	Ownership Interest as of September 30, 2010		September 30, 2010		Our Maximum Exposure to Loss at September 30, 2010(2)		December 31, 2009
OMEC(1)		100%	$	—	$	—	$	144
Greenfield LP		50%		68		68		70
Whitby		50%		1		1		—
Total investments			$	69	$	69	$	214

_________

(1) OMEC was consolidated effective January 1, 2010. See Note 1.

(2) 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. As of September 30, 2010, and December 31, 2009, equity method investee debt was approximately $484 million and $873 million, respectively, and based on our pro rata share of each of the investments, our share of such debt would be approximately $242 million and $624 million as of September 30, 2010 and December 31, 2009, respectively.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
OMEC(1)	$	—		$	13		$	—		$	(13	)
Greenfield LP		—			(1	)		(7	)		(11	)
Whitby		(1	)		1			(7	)		(3	)
Total	$	(1	)	$	13		$	(14	)	$	(27	)

__________

(1) OMEC was consolidated effective January 1, 2010. See Note 1. During the three and nine months ended September 30, 2009, we contributed $11 million and $19 million, respectively, as an additional investment in OMEC.

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 1,030 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%. We received $6 million in distributions from Greenfield LP during the three and nine months ended September 30, 2010.

Whitby — Represents our 50% equity interest in Whitby held by our Canadian subsidiaries. We received $3 million and $5 million during the three and nine months ended September 30, 2010, respectively, and $2 million during the nine months ended September 30, 2009, in distributions from Whitby. We did not receive any distributions from Whitby during the three months ended September 30, 2009.

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 began commercial operations on May 3, 2010) from General Electric International, Inc. that may be exercised between years 7 and 14 after the start of commercial operation. General Electric International, Inc. 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 General Electric International, Inc. directs the most significant activities of the power plant including operations and maintenance.

12

5.  Comprehensive Income (Loss)

Comprehensive income (loss) includes our net income, 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 8 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 income (loss) for the periods indicated (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Net income	$	217		$	237		$	55		$	189
Other comprehensive income (loss):
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income		65			(154	)		95			156
Reclassification adjustment for cash flow hedges realized in net income		(12	)		(108	)		10			(293	)
Foreign currency translation gain		—			2			—			3
Income tax benefit (expense)(1)		4			15			(5	)		42
Comprehensive income (loss)		274			(8	)		155			97
Add:  Comprehensive loss attributable to the noncontrolling interest		—			1			—			3
Comprehensive income (loss) attributable to Calpine	$	274		$	(7	)	$	155		$	100

__________

(1) Primarily due to intraperiod tax allocations.

6.  Debt

Our debt at September 30, 2010, and December 31, 2009, was as follows (in millions):

	September 30, 2010		December 31, 2009
First Lien Credit Facility(1)	$	3,153	$	4,661
First Lien Notes		2,691		1,200
NDH Project Debt		1,270		—
Commodity Collateral Revolver(2)		—		100
Project financing, notes payable and other		2,290		2,289
CCFC Notes		964		959
Capital lease obligations		249		250
Total debt		10,617		9,459
Less: Current maturities		574		463
Debt, net of current portion	$	10,043	$	8,996

__________

(1) On October 22, 2010, we issued $2.0 billion of 2021 First Lien Notes and repaid approximately $2.0 billion of the First Lien Credit Facility term loans.

(2) The Commodity Collateral Revolver was repaid on July 8, 2010.

First Lien Credit Facility — Our First Lien Credit Facility includes an original $6.0 billion of senior secured term loans, a $1.0 billion senior secured revolving facility and, subject to market conditions, the ability to raise up to $2.0 billion of incremental term loans under an “accordion” provision available on a senior secured basis in order to refinance secured debt of subsidiaries. As of September 30, 2010, under our First Lien Credit Facility, we had approximately $3.2 billion outstanding under the term loans and $260 million of letters of credit issued against the revolver. Balances repaid under the senior secured term loans may not be reborrowed. Borrowings of term loans under our First Lien Credit Facility bear interest at a floating rate, at our option, of LIBOR plus 2.875% per annum or base rate plus 1.875% per annum. First Lien Credit Facility term loans require quarterly payments of principal equal to 0.25% of the original principal amount of First Lien Credit Facility term loans subject to adjustments as a result of the First Lien Note offerings and repayments from excess cash

13

flows. The First Lien Credit Facility matures on March 29, 2014. During 2010 we made significant repayments of our First Lien Credit Facility term loans through proceeds received from the issuances of the First Lien Notes of the following amounts:

• In May 2010, we repaid approximately $394 million from the issuance of the 2019 First Lien Notes.

• In July 2010, we repaid approximately $1.1 billion from the issuance of the 2020 First Lien Notes.

• In October 2010, we repaid approximately $2.0 billion from the issuance of the 2021 First Lien Notes.

The obligations under our First Lien Credit Facility are unconditionally guaranteed by certain of our direct and indirect domestic subsidiaries and are secured by a security interest in substantially all of the tangible and intangible assets of Calpine Corporation and certain of the guarantors. The obligations under our First Lien Credit Facility are also secured by a pledge of the equity interests of the direct subsidiaries of certain of the guarantors, subject to certain exceptions, including exceptions for equity interests in foreign subsidiaries, existing contractual prohibitions and prohibitions under other legal requirements. Our First Lien Credit Facility also requires compliance with financial covenants that include a maximum ratio of total net debt to Consolidated EBITDA (as defined in the First Lien Credit Facility), a minimum ratio of Consolidated EBITDA to cash interest expense, and a maximum ratio of total senior net debt to Consolidated EBITDA.

First Lien Notes — Our First Lien Notes are secured equally and ratably with indebtedness incurred under our First Lien Credit Facility and certain other indebtedness that is permitted to be secured by such assets by a first-priority lien, 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. During 2010, we issued three tranches of First Lien Notes as further discussed below. We recorded deferred financing costs of approximately $26 million on our Consolidated Condensed Balance Sheet at September 30, 2010 and we recorded approximately $20 million and approximately $27 million in debt extinguishment costs for the three and nine months ended September 30, 2010, respectively, from the write-off of unamortized deferred financing costs related to the issuances of the First Lien Notes and the repayment of the First Lien Credit Facility term loans.

Issuance of 2019 First Lien Notes — On May 25, 2010, we issued $400 million in aggregate principal amount of 8% senior secured notes due 2019 in a private placement. The 2019 First Lien Notes were issued under an amended and restated indenture, dated as of May 25, 2010, among Calpine, the guarantors who are a party thereto and Wilmington Trust Company, as trustee. The 2019 First Lien Notes bear interest at 8% payable semi-annually on February 15 and August 15 of each year beginning on August 15, 2010. Interest is due to the holders of record on February 1 and August 1 immediately preceding the applicable interest payment date. The 2019 First Lien Notes will mature on August 15, 2019. Proceeds received from the issuance of the 2019 First Lien Notes were used to repay approximately $394 million of the First Lien Credit Facility term loans on May 25, 2010.

Issuance of 2020 First Lien Notes — On July 23, 2010, we issued $1.1 billion in aggregate principal amount of 7.875% senior secured notes due 2020 in a private placement. The 2020 First Lien Notes were issued under an indenture, dated as of July 23, 2010, among Calpine, the guarantors who are a party thereto and Wilmington Trust Company, as trustee. The 2020 First Lien Notes bear interest at 7.875% payable semi-annually on January 31 and July 31 of each year beginning on January 31, 2011. Interest is due to the holders of record on January 15 and July 15 immediately preceding the applicable interest payment date. The 2020 First Lien Notes will mature on July 31, 2020. Proceeds received from the issuance of the 2020 First Lien Notes were used to repay approximately $1.1 billion of the First Lien Credit Facility term loans on July 23, 2010.

Issuance of 2021 First Lien Notes — On October 22, 2010, we issued $2.0 billion in aggregate principal amount of 7.50% senior secured notes due 2021 in a private placement. The 2021 First Lien Notes were issued under an indenture, dated as of October 22, 2010, among Calpine, the guarantors who are a party thereto and Wilmington Trust Company, as trustee. The 2021 First Lien Notes bear interest at 7.50% payable semi-annually on February 15 and August 15 of each year beginning on February 15, 2011. Interest is due to the holders of record on February 1 and August 1 immediately preceding the applicable interest payment date. The 2021 First Lien Notes will mature on February 15, 2021. Proceeds received from the issuance of the 2021 First Lien Notes were used to repay approximately $2.0 billion of the First Lien Credit Facility term loans on October 22, 2010, and pay fees and expenses in connection with the offering of the 2021 First Lien Notes and such repayment. Additionally, we expect to record additional deferred financing costs of approximately $33 million and approximately $34 million in debt extinguishment costs from the write-off of unamortized deferred financing costs related to the issuance of the 2021 First Lien Notes during the fourth quarter of 2010.

14

NDH Project Debt — On June 8, 2010, NDH entered into a credit agreement, and we received net proceeds of $1.3 billion on July 1, 2010, which were used, together with available 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. Our NDH Project Debt includes a $1.3 billion seven-year senior secured term facility and a $100 million three-year senior secured revolving credit facility, of which up to $50 million will be available through a subfacility in the form of letters of credit. On July 1, 2010, the term facility was funded in the amount of $1.3 billion. The NDH Project Debt was issued with an original issue discount of $28 million, and we recorded deferred financing costs of approximately $40 million, which we recorded on our Consolidated Condensed Balance Sheet. Our NDH Project Debt bears interest at a floating rate, at our option, at a rate per annum equal to the alternate base rate or the adjusted LIBOR (subject to a minimum of 1.5%), plus, in each case, the applicable margin, which varies for the revolving credit facility (as defined in our NDH Project Debt agreement). An amount equal to 0.25% of the aggregate principal amount of the senior secured term facility outstanding on July 1, 2010, which was $1.3 billion, will be payable at the end of each quarter commencing with the first full quarter after July 1, 2010, with the remaining balance payable on July 1, 2017. Additional repayments of principal will be required from excess cash flows (as defined in our NDH Project Debt agreement). No amortization will be required with respect to the revolving credit facility. The NDH Project Debt also required that we enter into interest rate swap agreements to fix the variable LIBOR portion of our interest rate for a minimum of 50% of our debt. We executed three interest rate swap transactions in August 2010 with an initial aggregate notional amount of $715 million at a fixed LIBOR rate of 1.8275%.

NDH’s obligations under the NDH Project Debt are unconditionally guaranteed by each existing and subsequently acquired or organized domestic, wholly owned subsidiary of NDH (including the entities acquired) and will be secured by a first-priority lien on substantially all of NDH’s and the guarantors’ existing and future assets, in each case subject to certain exceptions and permitted liens. NDH and its subsidiaries (subject to certain exceptions) have made certain representations and warranties and are required to comply with various affirmative and negative covenants including, among others, certain limitations and prohibitions relating to additional indebtedness, liens, restricted payments, mergers and asset sales and certain financial covenants relating to limitations on capital expenditures, minimum interest coverage and maximum leverage. The NDH Project Debt 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. Neither Calpine Corporation nor any of its subsidiaries, other than NDH and its subsidiaries (subject to certain exceptions), are guarantors under the NDH Project Debt.

As part of the Conectiv Acquisition and NDH Project Debt, we entered into various intercompany agreements with our NDH subsidiaries for the related sales and purchases of power, natural gas and the operation and maintenance of our NDH power plants, which will not materially impact our results of operations, financial condition or cash flows on a consolidated basis. While there is no direct recourse by holders of the NDH Project Debt to Calpine Corporation, a substantial portion of the commodity price risk related to NDH’s power generation is absorbed by Calpine Energy Services, L.P., an indirect, wholly owned subsidiary of Calpine Corporation, which purchases the power generated by NDH under an intercompany tolling agreement, which is guaranteed by Calpine Corporation.

OMEC Debt — As further discussed in Note 1, we added approximately $375 million in project debt to our Consolidated Condensed Balance Sheet when we consolidated OMEC effective January 1, 2010. As of September 30, 2010, OMEC had approximately $367 million in project debt outstanding, which is included in the balance under the caption “Project financing, notes payable and other” in the table above. OMEC has a $377 million non-recourse project term loan which matures in April 2019. The term loan bears interest at LIBOR plus 1.25%.

Calpine BRSP Debt — As further discussed in Note 2, we expect to assume debt of approximately $282 million upon closing the purchase of the equity interests of our Broad River and South Point power plants. However, the purchase of the equity interests is expected to only add an incremental $72 million in consolidated debt as the transaction will eliminate approximately $210 million in debt owed to CIT Capital USA Inc. by our Broad River power plant. This transaction is expected to close in the fourth quarter of 2010.

15

Letter of Credit Facilities — The table below represents amounts issued under our letter of credit facilities as of September 30, 2010, and December 31, 2009 (in millions):

	September 30, 2010		December 31, 2009
First Lien Credit Facility	$	260	$	206
Calpine Development Holdings, Inc.(1)		160		116
NDH Credit Facility		35		—
Various project financing facilities		109		90
Total	$	564	$	412

__________

(1) Availability under the Calpine Development Holdings, Inc. letter of credit was increased by $50 million to $200 million on June 30, 2010.

Fair Value of Debt

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 record our debt instruments based on contractual terms, net of any applicable premium or discount. We measured the fair value of our debt instruments as of September 30, 2010, and December 31, 2009, 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 as of September 30, 2010, and December 31, 2009 (in millions):

	September 30, 2010				December 31, 2009
	Fair Value		Carrying Value		Fair Value		Carrying Value
First Lien Credit Facility	$	3,079	$	3,153	$	4,402	$	4,661
First Lien Notes		2,776		2,691		1,138		1,200
NDH Project Debt		1,316		1,270		—		—
Commodity Collateral Revolver(1)		—		—		94		100
Project financing, notes payable and other(2)		1,812		1,866		1,808		1,840
CCFC Notes		1,067		964		1,030		959
Total	$	10,050	$	9,944	$	8,472	$	8,760

 _________

(1) The Commodity Collateral Revolver was repaid on July 8, 2010.

(2) 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.

Interest Expense

During the three and nine months ended September 30, 2010, $70 million in unrealized losses was reclassified out of AOCI and into our net income as interest expense for interest rate swaps that no longer qualified as cash flow hedges as the variable rate debt they were hedging was repaid with the proceeds received from the issuance of the 2020 First Lien Notes. Additionally, we expect an additional $130 million to $140 million in unrealized losses recorded in AOCI as of September 30, 2010, will be reclassified out of AOCI and into our net income as interest expense during the fourth quarter of 2010. These interest rate swaps were hedging the variable interest rates on approximately $2.0 billion of First Lien Credit Facility term loans that were repaid with the proceeds received from the issuance of the 2021 First Lien Notes on October 22, 2010, and will no longer qualify for cash flow hedges. Prospective changes in the fair value of these interest rate swaps will also be recorded in our net income as interest expense instead of AOCI and may create variability in our interest expense in future periods.

16

7.  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 commodity derivative instruments at any point in time are the volume of open derivative positions (MMBtu and MWh); market price levels, principally for power and natural gas; our credit standing and that of our counterparties; and prevailing interest rates. 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 are 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 the credit standing of our counterparties and the impact of credit enhancements, if any. We have included an estimate of nonperformance risk 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 and swaps for which market-based pricing inputs are observable. Generally, we obtain our level 2 pricing inputs from markets and pricing services 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 such 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.

17

The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2010, and December 31, 2009, by level within the fair value hierarchy. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect our estimate of the fair value of our assets and liabilities and their placement within the fair value hierarchy levels.

	Assets and Liabilities with Recurring Fair Value Measures as of September 30, 2010
	Level 1		Level 2		Level 3		Total
	(in millions)
Assets:
Cash equivalents(1)	$	989	$	—	$	—	$	989
Margin deposits		178		—		—		178
Commodity instruments:
Commodity futures contracts		1,142		—		—		1,142
Commodity forward contracts(2)		—		415		81		496
Interest rate swaps		—		1		—		1
Total assets	$	2,309	$	416	$	81	$	2,806
Liabilities:
Margin deposits held by us posted by our counterparties	$	62	$	—	$	—	$	62
Commodity instruments:
Commodity futures contracts		1,097		—		—		1,097
Commodity forward contracts(2)		—		174		17		191
Interest rate swaps		—		458		—		458
Total liabilities	$	1,159	$	632	$	17	$	1,808

	Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2009
	Level 1		Level 2		Level 3		Total
	(in millions)
Assets:
Cash equivalents(1)	$	1,306	$	—	$	—	$	1,306
Margin deposits		413		—		—		413
Commodity instruments:
Commodity futures contracts		953		—		—		953
Commodity forward contracts(2)		—		204		71		275
Interest rate swaps		—		18		—		18
Total assets	$	2,672	$	222	$	71	$	2,965
Liabilities:
Margin deposits held by us posted by our counterparties	$	9	$	—	$	—	$	9
Commodity instruments:
Commodity futures contracts		1,096		—		—		1,096
Commodity forward contracts(2)		—		91		33		124
Interest rate swaps		—		337		—		337
Total liabilities	$	1,105	$	428	$	33	$	1,566

__________

(1) As of September 30, 2010, and December 31, 2009, we had cash equivalents of $695 million and $770 million included in cash and cash equivalents and $294 million and $536 million included in restricted cash, respectively.

(2) Includes OTC swaps and options.

18

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Balance, beginning of period	$	43		$	91		$	38		$	105
Realized and unrealized gains (losses):
Included in net income:
Included in operating revenues(1)		12			(4	)		31			(1	)
Included in fuel and purchased energy expense(2)		2			(1	)		(1	)		6
Included in OCI		4			1			6			13
Purchases, issuances, sales and settlements:
Settlements		(2	)		(8	)		(13	)		(34	)
Transfers into and/or out of level 3(3):
Transfers into level 3(4)		1			—			—			(5	)
Transfers out of level 3(5)		4			(18	)		3			(23	)
Balance, end of period	$	64		$	61		$	64		$	61
Change in unrealized gains and (losses) relating to instruments still held at end of period	$	14		$	(5	)	$	30		$	5

__________

(1) For power contracts and Heat Rate swaps and options, as shown on our Consolidated Condensed Statements of Operations.

(2) For natural gas contracts, swaps and options, as shown 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 during the three and nine months ended September 30, 2010 and 2009.

(4) We had $1 million in gains transferred into level 3 out of level 2 for the three months ended September 30, 2010, due to changes in market liquidity in various power markets. There were no significant transfers into level 3 out of level 2 for the three months ended September 30, 2009, and the nine months ended September 30, 2010. We had $5 million in losses transferred into level 3 out of level 2 for the nine months ended September 30, 2009, due to changes in market liquidity in various power markets.

(5) We had $4 million in losses and $18 million in gains transferred out of level 3 into level 2 for the three months ended September 30, 2010 and 2009, respectively. We had $3 million in losses and $23 million in gains transferred out of level 3 into level 2 for the nine months ended September 30, 2010 and 2009, respectively. Transfers out of level 3 into level 2 were due to changes in market liquidity in various power markets.

8.  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 enter into a variety of derivative instruments, including 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 attempt to economically hedge a portion of the commodity price risk associated with our assets and thus maximize risk-adjusted returns. 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 significant portion of our debt is indexed to base rates, primarily LIBOR. We use interest rate swaps to adjust the mix between fixed and variable rate debt to hedge our interest rate risk for potential adverse changes in interest rates. These transactions primarily act as economic hedges for our interest cash flow.

19

As of September 30, 2010, the maximum length of our PPAs extends approximately 22 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 16 years, respectively.

As of September 30, 2010, and December 31, 2009, 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
Derivative Instruments		September 30, 2010		December 31, 2009
Power (MWh)		(43	)			(52	)
Natural gas (MMBtu)		5				78
Interest rate swaps	$	6,579			$	7,324

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 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 as of September 30, 2010, was $9 million for which we have posted collateral of $2 million by posting margin deposits or granted additional first priority liens on the assets currently subject to first priority liens under our First Lien Credit Facility.

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 settlement dates. Revenues and fuel costs derived from instruments that qualify for hedge accounting 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 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 Heat Rate swaps and options), fuel and purchased energy expense (for natural gas contracts, swaps and options) and interest expense (for interest rate swaps). 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 OCI until such time as the forecasted transaction impacts earnings, or until it is determined that the forecasted transaction is probable of not occurring.

Derivatives Not Designated as Hedging Instruments — 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).

20

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 September 30, 2010, and December 31, 2009 (in millions):

	September 30, 2010
						Total
Balance Sheet Presentation	Interest Rate			Commodity		Derivative
	Swaps			Instruments		Instruments
Current derivative assets	$	—		$	1,321	$	1,321
Long-term derivative assets		1			317		318
Total derivative assets	$	1		$	1,638	$	1,639
Current derivative liabilities	$	201		$	1,046	$	1,247
Long-term derivative liabilities		257			242		499
Total derivative liabilities	$	458		$	1,288	$	1,746
Net derivative assets (liabilities)	$	(457	)	$	350	$	(107	)

	December 31, 2009
						Total
Balance Sheet Presentation	Interest Rate			Commodity		Derivative
	Swaps			Instruments		Instruments
Current derivative assets	$	—		$	1,119	$	1,119
Long-term derivative assets		18			109		127
Total derivative assets	$	18		$	1,228	$	1,246
Current derivative liabilities	$	202		$	1,158	$	1,360
Long-term derivative liabilities		135			62		197
Total derivative liabilities	$	337		$	1,220	$	1,557
Net derivative assets (liabilities)	$	(319	)	$	8	$	(311	)

	September 30, 2010
	Fair Value		Fair Value
	of Derivative		of Derivative
	Assets		Liabilities
Derivatives designated as cash flow hedging instruments:
Interest rate swaps	$	1	$	311
Commodity instruments		305		81
Total derivatives designated as cash flow hedging instruments	$	306	$	392
Derivatives not designated as hedging instruments:
Interest rate swaps	$	—	$	147
Commodity instruments		1,333		1,207
Total derivatives not designated as hedging instruments	$	1,333	$	1,354
Total derivatives	$	1,639	$	1,746

	December 31, 2009
	Fair Value		Fair Value
	of Derivative		of Derivative
	Assets		Liabilities
Derivatives designated as cash flow hedging instruments:
Interest rate swaps	$	18	$	324
Commodity instruments		213		80
Total derivatives designated as cash flow hedging instruments	$	231	$	404
Derivatives not designated as hedging instruments:
Interest rate swaps	$	—	$	13
Commodity instruments		1,015		1,140
Total derivatives not designated as hedging instruments	$	1,015	$	1,153
Total derivatives	$	1,246	$	1,557

21

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 September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Realized gain (loss)
Interest rate swaps	$	(14	)	$	(3	)	$	(26	)	$	(12	)
Commodity instruments		41			1			93			(13	)
Total realized gain (loss)	$	27		$	(2	)	$	67		$	(25	)
Unrealized gain (loss) (1)
Interest rate swaps	$	(96	)	$	1		$	(115	)	$	5
Commodity instruments		131			43			212			60
Total unrealized gain	$	35		$	44		$	97		$	65
Total mark-to-market activity	$	62		$	42		$	164		$	40

__________

(1) Changes in unrealized gains and losses include hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Realized and unrealized gain (loss)
Power contracts included in operating revenues	$	22		$	17		$	34		$	8
Natural gas contracts included in fuel and purchased energy expense		150			27			271			39
Interest rate swaps included in interest expense		(110	)		(2	)		(141	)		(7	)
Total mark-to-market activity	$	62		$	42		$	164		$	40

Derivatives Included in 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 September 30,
	2010		2009			2010			2009			2010			2009
	Gain (Loss) Recognized in					Gain (Loss) Reclassified from AOCI						Gain (Loss) Reclassified from AOCI
	OCI (Effective Portion)					into Income (Effective Portion)						into Income (Ineffective Portion)
Interest rate swaps	$	45	$	(17	)	$	(50	)(1)	$	(60	)(1)	$	—	(1)	$	—
Commodity instruments		8		(245	)		62	(2)		168	(2)		(1	)(2)		—
Total	$	53	$	(262	)	$	12		$	108		$	(1	)	$	—

22

	Nine Months Ended September 30,
	2010		2009			2010			2009			2010			2009
	Gain (Loss) Recognized in					Gain (Loss) Reclassified from AOCI						Gain (Loss) Reclassified from AOCI
	OCI (Effective Portion)					into Income (Effective Portion)						into Income (Ineffective Portion)
Interest rate swaps	$	18	$	70		$	(172	)(1)	$	(152	)(1)	$	—	(1)	$	—
Commodity instruments		87		(207	)		162	(2)		445	(2)		—	(2)		—
Total	$	105	$	(137	)	$	(10	)	$	293		$	—		$	—

__________

(1) Included in interest expense on our Consolidated Condensed Statements of Operations. During the three months ended September 30, 2010, an additional $70 million in unrealized losses was reclassified out of AOCI for interest rate swaps that no longer qualified as cash flow hedges as the variable rate debt it was hedging was repaid with the proceeds received from the issuance of the 2020 First Lien Notes. The corresponding amounts were reclassified into our net income as additional interest expense.

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

Assuming constant September 30, 2010, power and natural gas prices and interest rates, we estimate that pre-tax net gains of $33 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. Additionally, as of September 30, 2010, approximately $130 million to $140 million in unrealized losses were recorded in AOCI for interest rate swaps that were hedging the variable interest rates on approximately $2.0 billion of First Lien Credit Facility term loans, which were repaid (see Note 6 for further discussion of our issuance of the 2021 First Lien Notes). These interest rate swaps will no longer qualify as cash flow hedges and the corresponding amounts will be reclassified into our net income during the fourth quarter of 2010 as additional interest expense. Additionally, prospective changes in the fair value of these interest rate swaps will also be recorded in our net income as interest expense.

9.  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 First Lien Credit Facility as collateral under certain of our power and natural gas agreements that qualify as “eligible commodity hedge agreements” under our First Lien Credit 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 ratably with the lenders under our First Lien Credit Facility.

23

The table below summarizes the balances outstanding under margin deposits, natural gas and power prepayments, and exposure under letters of credit and first priority liens for commodity procurement and risk management activities as of September 30, 2010, and December 31, 2009 (in millions):

	September 30, 2010		December 31, 2009
Margin deposits(1)	$	178	$	413
Natural gas and power prepayments		32		34
Total margin deposits and natural gas and power prepayments with our counterparties(2)	$	210	$	447
Letters of credit issued	$	455	$	353
First priority liens under power and natural gas agreements(3)		—		—
First priority liens under interest rate swap agreements		428		333
Total letters of credit and first priority liens with our counterparties	$	883	$	686
Margin deposits held by us posted by our counterparties(1)(4)	$	62	$	9
Letters of credit posted with us by our counterparties		111		70
Total margin deposits and letters of credit posted with us by our counterparties	$	173	$	79

__________

(1) Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated Condensed Balance Sheets. We do not offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation.

(2) At September 30, 2010, and December 31, 2009, $187 million and $426 million were included in margin deposits and other prepaid expense, respectively, and $23 million and $21 million were included in other assets at September 30, 2010 and December 31, 2009, respectively, on our Consolidated Condensed Balance Sheets.

(3) At September 30, 2010, and December 31, 2009, the fair value of our commodity derivative instruments collateralized by first priority liens included assets of $275 million and $123 million, respectively; therefore, there was no collateral exposure at September 30, 2010, or December 31, 2009.

(4) 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.

10.  Income Taxes

For federal income tax reporting purposes, our consolidated U.S. GAAP financial reporting group is comprised primarily of two separate tax reporting groups, CCFC and its subsidiaries, which we refer to as the CCFC group, and Calpine Corporation and its subsidiaries other than CCFC, which we refer to as the Calpine group. In 2005, CCFCP issued the CCFCP Preferred Shares, which resulted in the deconsolidation of the CCFC group for income tax purposes. On July 1, 2009, the CCFCP Preferred Shares were redeemed; however, CCFCP continues to be a partnership and therefore, the CCFC group remains deconsolidated from Calpine Corporation for federal income tax reporting purposes. As of September 30, 2010, the CCFC group did not have a valuation allowance recorded against its deferred tax assets, whereas the Calpine group continued to have a valuation allowance. For the three and nine months ended September 30, 2010 and 2009, we used the effective rate method to determine both the CCFC and Calpine groups’ tax provision; however, our income tax rates did not bear a customary relationship to statutory income tax rates primarily as a result of the impact of state income taxes, changes in unrecognized tax benefits, the Calpine group valuation allowance and intraperiod tax allocations.

24

The table below shows our consolidated income tax expense (benefit) from continuing operations (excluding non-controlling interest), and our imputed tax rates, as well as intraperiod tax allocations, with partially offsetting tax expense (benefit) allocated between discontinued operations or OCI, for the periods indicated (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Income tax expense (benefit)	$	21		$	(7	)	$	38	(1)	$	17
Imputed tax rate		10	%		(3	)%		61	%		10	%
Intraperiod tax allocation expense (benefit)	$	43		$	15		$	(27	)(1)	$	42

__________

(1) Includes approximately $13 million in tax expense related to a prior period.

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. In prior periods, we provided a valuation allowance on certain federal, state and foreign tax jurisdiction deferred tax assets of the Calpine group to reduce the gross amount of these assets to the extent necessary to result in an amount that is more likely than not of being realized. Projected future income from reversals of existing taxable temporary differences and tax planning strategies allowed a larger portion of the deferred tax assets to be offset against deferred tax liabilities resulting in a significant release of previously recorded valuation allowance in prior periods; however, we have not released any additional previously recorded valuation allowance in 2010.

Income Tax Audits — In September 2009, we received notice from the Canadian Revenue Authority (“CRA”) of their intent to conduct a limited scope income tax audit on four of our Canadian subsidiaries for the tax years ending 2005 through 2008. We have timely responded to their request for information and received notice from the CRA that they have completed their audit of transactions within Canada and no changes were proposed. The CRA international audit division continues to review cross border transactions within the audit period. At this time, we are unable to determine the likelihood of a material adverse assessment.

We remain subject to other various audits and reviews by state 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 2006 and forward would likely result in a reduction of deferred tax assets rather than a cash payment of income taxes.

Unrecognized Tax Benefits and Liabilities — As of September 30, 2010, we had unrecognized tax benefits of $87 million. If recognized, $41 million of our unrecognized tax benefits could impact the annual effective tax rate and $46 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 $19 million for income tax matters as of September 30, 2010. The amount of unrecognized tax benefits decreased by $11 million for the nine months ended September 30, 2010, primarily as a result of $9 million related to a hedging position terminated for CCFC group and $2 million related to depreciation taken on a position for a capitalized asset. The decrease is related to temporary differences in tax reporting and did not impact the annual effective tax rate. We believe it is reasonably possible that a decrease of approximately $1 million in unrecognized tax benefits could occur within the next 12 months primarily related to state tax liabilities and state 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. If a subsequent ownership change were to occur as a result of future transactions in our 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. The Calpine group and the CCFC group adjusted their NOLs for prior periods through December 31, 2009, increasing it by approximately $150 million. These adjustments consisted of $49 million to reduce the NOL for excluded cancellation of debt

25

income, a $230 million increase in prior period NOLs for development costs and construction in progress relating to abandoned projects, a $33 million decrease for return to provision adjustments and other increases of $2 million; however, because of the Calpine group's valuation allowance on its NOL, there is no impact on our income tax expense.

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, neither circumstance was met. While we do not believe an ownership change of 25 percentage points has occurred, the change in ownership is only slightly less than 25%. 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 were 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.

11.  Earnings 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, are unresolved. To the extent that any of the reserved shares remain undistributed upon resolution of the 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. Therefore, pursuant to our Plan of Reorganization, all 485 million shares ultimately will be distributed. 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.

Reconciliations of the amounts used in the basic and diluted earnings per common share computations for the three and nine months ended September 30, 2010 and 2009, are:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
	(shares in thousands)
Diluted weighted average shares calculation:
Weighted average shares outstanding (basic)		486,088		485,736		486,023		485,619
Share-based awards		1,355		849		1,176		552
Weighted average shares outstanding (diluted)		487,443		486,585		487,199		486,171

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 September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
	(shares in thousands)
Share-based awards		14,625		13,203		14,193		13,115

26

12.  Stock-Based Compensation

The Calpine Equity Incentive Plans were approved as part of our Plan of Reorganization. These plans are administered by the Compensation Committee of our Board of Directors and 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.

On May 19, 2010, our shareholders, upon the recommendation of our Board of Directors, approved the amendment to the Director Plan to increase the aggregate number of shares of common stock authorized for issuance under the Director Plan by 400,000 shares and to extend the term of the Director Plan to January 31, 2018, and approved the amendment to the Equity Plan to increase the aggregate number of shares of common stock authorized for issuance under the Equity Plan by 12,700,000 shares. Subsequent to the amendments of the Director Plan and Equity Plan, there are 567,000 and 27,533,000 shares, respectively, of our common stock authorized for issuance to participants.

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 seven and ten years and are subject to forfeiture provisions under certain circumstances, including termination of employment prior to vesting. Employment inducement options to purchase a total of 4,636,734 shares were granted outside of the Calpine Equity Incentive Plans in connection with the hiring of our Chief Executive Officer and our Chief Legal Officer in August 2008, and our Chief Commercial Officer in September 2008; however, no grants of options or shares of restricted stock were made outside of the Calpine Equity Incentive Plans during the nine months ended September 30, 2010 and 2009.

On August 11, 2010, we awarded stock options to purchase an aggregate of 3,260,000 shares of our common stock to certain executive officers under the Equity Plan. These stock options provide a generally competitive compensation opportunity for the current or a similar economic environment, but contain a market condition to reduce in number as, and if, our common stock prices return to historical pricing levels. Specifically, if on the date of exercise of the stock options, the closing price of our common stock exceeds the exercise price plus 25% ($15.80), then the number of shares underlying the stock options that may be exercised on that date of exercise shall be reduced, on a straight-line basis, beginning when the closing price on the date of exercise exceeds $15.80 and ending when such closing price equals or exceeds $27.50 per share at which price the number of shares underlying the stock options shall be reduced to zero shares. The stock options contain a cliff vesting term of approximately three years and expiration coincides with the expiration of each executive officer’s respective employment inducement options, or expires upon a termination of employment. Due to the market condition contained in the option agreements (described above), these options are valued using the Monte Carlo simulation model.

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 $6 million and $8 million for the three months ended September 30, 2010 and 2009, respectively, and $18 million and $30 million for the nine months ended September 30, 2010 and 2009, respectively. We did not record any 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 nine months ended September 30, 2010 and 2009. At September 30, 2010, there was unrecognized compensation cost of $22 million related to options, $15 million related to restricted stock and nil related to restricted stock units, which is expected to be recognized over a weighted average period of 2.1 years for options, 1.9 years for restricted stock and 0.6 years

27

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 nine months ended September 30, 2010, is as follows:

				Weighted
				Average
		Weighted		Remaining	Aggregate
	Number of	Average		Term	Intrinsic Value
	Options	Exercise Price		(in years)	(in millions)
Outstanding – December 31, 2009	13,232,519	$	19.09	6.6	$	2
Granted	4,311,791	$	12.31
Exercised	810	$	8.84
Forfeited	290,209	$	12.36
Expired	255,010	$	17.43
Outstanding – September 30, 2010	16,998,281	$	17.51	5.8	$	4
Exercisable – September 30, 2010	6,247,624	$	19.28	6.0	$	—
Vested and expected to vest – September 30, 2010	16,663,135	$	17.63	5.7	$	4

The total intrinsic value and the cash proceeds received from our employee stock options exercised were not significant for the nine months ended September 30, 2010. There were no employee stock options exercised during the nine months ended September 30, 2009.

The fair value of options granted during the nine months ended September 30, 2010 and 2009, was determined on the grant date using the Black-Scholes pricing model or the Monte Carlo simulation model, as appropriate. Certain assumptions were used in order to estimate fair value for options as noted in the following table.

	2010			2009
Expected term (in years)(1)		4.0 – 6.5			6.0 – 6.5
Risk-free interest rate(2)		1.3 – 3.3	%		2.3 – 2.9	%
Expected volatility(3)		34.1 – 37.6	%		60.1 – 73.0	%
Dividend yield(4)		—			—
Weighted average grant-date fair value (per option)	$	1.80		$	5.66

__________

(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 are currently prohibited under our First Lien Credit Facility and certain of our other debt agreements from paying any cash dividends on our common stock.

No restricted stock or restricted stock units have been granted other than under the Calpine Equity Incentive Plans. A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the nine months ended September 30, 2010, is as follows:

		Weighted
	Number of	Average
	Restricted	Grant-Date
	Stock Awards	Fair Value
Nonvested – December 31, 2009	2,046,599	$	11.95
Granted	1,474,410	$	11.31
Forfeited	294,314	$	10.87
Vested	438,534	$	15.49
Nonvested – September 30, 2010	2,788,161	$	11.18

28

The total fair value of our restricted stock and restricted stock units that vested during the nine months ended September 30, 2010 and 2009, was $4 million and $8 million, respectively.

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 September 30, 2010, our reportable segments were West (including geothermal), Texas, North (including Canada) and Southeast. We continue to evaluate the optimal manner in which we assess our performance including our segments and future changes may result.

Commodity Margin includes our power and steam revenues, sales of purchased power and 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 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 West segment has been recast for all periods presented to exclude results for Blue Spruce and Rocky Mountain, which have been reported as discontinued operations. Our North segment information for the three and nine months ended September 30, 2010, also includes the financial results of the assets we acquired from Conectiv beginning on the acquisition date of July 1, 2010, with no similar revenues and expenses included for the three and nine months ended September 30, 2009. See Note 2 for further discussion of our discontinued operations and our Conectiv Acquisition.

	Three Months Ended September 30, 2010
									Consolidation
									and
	West		Texas		North		Southeast		Elimination			Total
Revenues from external customers	$	716	$	670	$	468	$	276	$	—		$	2,130
Intersegment revenues		2		6		2		53		(63	)		—
Total operating revenues	$	718	$	676	$	470	$	329	$	(63	)	$	2,130
Commodity Margin	$	338	$	165	$	259	$	90	$	—		$	852
Add: Mark-to-market commodity activity, net and other revenue(1)		42		62		18		18		(6	)		134
Less:
Plant operating expense		86		55		38		28		(8	)		199
Depreciation and amortization expense		50		36		37		28		(2	)		149
Other cost of revenue(2)		12		—		5		—		2			19
Gross profit		232		136		197		52		2			619
Other operating expenses		14		14		12		24		1			65
Income from operations		218		122		185		28		1			554
Interest expense, net of interest income													312
Debt extinguishment costs and other (income) expense, net													23
Income before income taxes and discontinued operations												$	219

29

	Three Months Ended September 30, 2009
										Consolidation
										and
	West		Texas		North		Southeast			Elimination			Total
Revenues from external customers	$	887	$	530	$	167	$	238		$	—		$	1,822
Intersegment revenues		5		6		—		24			(35	)		—
Total operating revenues	$	892	$	536	$	167	$	262		$	(35	)	$	1,822
Commodity Margin	$	368	$	187	$	96	$	92		$	—		$	743
Add: Mark-to-market commodity activity, net and other revenue(1)		41		2		21		(4	)		(12	)		48
Less:
Plant operating expense		92		35		18		27			17			189
Depreciation and amortization expense		45		27		16		17			(1	)		104
Other cost of revenue(2)		17		6		10		3			(18	)		18
Gross profit		255		121		73		41			(10	)		480
Other operating expenses		32		14		3		8			—			57
Income from operations		223		107		70		33			(10	)		423
Interest expense, net of interest income														192
Debt extinguishment costs and other (income) expense, net														20
Income before reorganization items, income taxes and discontinued operations														211
Reorganization items														(8	)
Income before income taxes and discontinued operations													$	219

	Nine Months Ended September 30, 2010
									Consolidation
									and
	West		Texas		North		Southeast		Elimination			Total
Revenues from external customers	$	1,906	$	1,749	$	725	$	694	$	—		$	5,074
Intersegment revenues		7		16		4		97		(124	)		—
Total operating revenues	$	1,913	$	1,765	$	729	$	791	$	(124	)	$	5,074
Commodity Margin	$	809	$	400	$	390	$	216	$	—		$	1,815
Add: Mark-to-market commodity activity, net and other revenue(1)		60		148		18		31		(20	)		237
Less:
Plant operating expense		264		217		83		87		(21	)		630
Depreciation and amortization expense		151		110		75		83		(5	)		414
Other cost of revenue(2)		37		1		19		2		—			59
Gross profit		417		220		231		75		6			949
Other operating expenses		46		33		26		31		1			137
Income from operations		371		187		205		44		5			812
Interest expense, net of interest income													714
Debt extinguishment costs and other (income) expense, net													36
Income before income taxes and discontinued operations												$	62

30

	Nine Months Ended September 30, 2009
										Consolidation
										and
	West		Texas			North		Southeast		Elimination			Total
Revenues from external customers	$	2,513	$	1,386		$	431	$	589	$	—		$	4,919
Intersegment revenues		22		59			13		79		(173	)		—
Total operating revenues	$	2,535	$	1,445		$	444	$	668	$	(173	)	$	4,919
Commodity Margin	$	918	$	505		$	215	$	233	$	—		$	1,871
Add: Mark-to-market commodity activity, net and other revenue(1)		120		(48	)		37		2		(35	)		76
Less:
Plant operating expense		310		163			61		94		10			638
Depreciation and amortization expense		137		88			47		50		(5	)		317
Other cost of revenue(2)		44		11			23		7		(28	)		57
Gross profit		547		195			121		84		(12	)		935
Other operating expenses		45		51			—		23		—			119
Income from operations		502		144			121		61		(12	)		816
Interest expense, net of interest income														591
Debt extinguishment costs and other (income) expense, net														55
Income before reorganization items, income taxes and discontinued operations														170
Reorganization items														(2	)
Income before income taxes and discontinued operations													$	172

__________

(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 $1 million of RGGI compliance and other environmental costs for both the three months ended September 30, 2010 and 2009, and $6 million and $5 million for the nine months ended September 30, 2010 and 2009, respectively, which are included as a component of Commodity Margin.

14.  Commitments and Contingencies

Litigation

We are party to various litigation matters, including regulatory and administrative proceedings arising out of the normal course of business, the more significant of which are summarized below. The ultimate outcome of each of these matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated presently for every case. The liability we may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued with respect to such matters and, as a result of these matters, may potentially be material to our financial position or results of operations. 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 have determined an unfavorable outcome is probable and is reasonably estimable, we have accrued for potential litigation losses. 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. In particular, certain pending actions against us are anticipated to proceed as described below. In addition to the matters described below, we are involved in various other claims and legal actions, including regulatory and administrative proceedings arising out of the normal course of our business. We do not expect that the outcome of such other claims and legal actions will have a material adverse effect on our financial position or results of operations.

31

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 (“District Court”), seeking to enjoin further exploration, construction and development of the Calpine Fourmile Hill Project in the Glass Mountain and Medicine Lake geothermal areas. Its 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 (“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. The Ninth Circuit remanded the matter back to the District Court to implement its decision. On December 22, 2008 the District Court in turn remanded this matter back to federal agencies for curative action, including whether the leases may be extended. Before the agencies could reconsider, the Pit River Tribe appealed the District Court’s decision on the basis the original Ninth Circuit decision purportedly invalidated the leases, and therefore, the Pit River Tribe argues, the Ninth Circuit did not give the District Court latitude to grant an extension of the leases. Oral argument on the Tribe’s appeal was held in the Ninth Circuit on March 10, 2010. On August 2, 2010, the Ninth Circuit ruled in favor of BLM and us, concluding that the BLM may properly reconsider its decision to extend the term of our two Four-Mile Hill leases. We understand that the Pit River Tribe has until November 1, 2010, to file a writ of certiorari to the U.S. Supreme Court.

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 related cases continue to be subject to the discharge injunction as described in the Confirmation Order. Similar to above, we are now in communication with the U.S. Department of Justice regarding these two cases, but the 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.

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 of our power plants. A summary of our larger environmental matters is 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 approximately $6 million in liabilities as of September 30, 2010, and could incur expenditures related thereto of up to $10 million. Pursuant to the Conectiv Purchase Agreement, PHI is responsible for any amounts that exceed $10 million. Until our acquisition accounting is finalized for the Conectiv Acquisition, any future changes to our environmental remediation liabilities, if any, would not impact future earnings, but would be reflected in our allocation of the Conectiv Acquisition purchase price. See Note 2 for disclosures related to our Conectiv Acquisition. We have engaged a licensed site remediation professional who has evaluated the recognized environmental conditions and is conducting site investigations in accordance with ISRA requirements as a precursor to developing the ultimate cleanup plan.

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 without emissions monitoring equipment to limit emissions of pollutants that are not subject to measurement by continuous emissions monitoring systems. Appeals were filed in 2007, and a status hearing has been set for later this year. The appeals assert that the NJDEP does not have the authority to limit heat input in Title V air permits. We plan to continue to work with the NJDEP to ensure that our New Jersey assets may operate at full load. Currently, these restrictions require one of our peaker power plants (Deepwater Unit 1) to operate at approximately 8 MW less than its full capacity of 86 MW. We are preparing an application to modify the Deepwater Unit 1 air permit to reclaim the 8 MW limitation, but there can be no assurance that our application will be successful.

32

Other Contingencies

Distribution of Calpine Common Stock under our Plan of Reorganization — Through the filing of this Report, approximately 441 million shares have been distributed to holders of allowed unsecured claims and approximately 44 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. However, certain disputed claims, including prepayment premium and default interest claims asserted by the holders of CalGen Third Lien Debt, may be required to be settled with available cash and cash equivalents to the extent reorganized Calpine Corporation common stock held in reserve pursuant to our Plan of Reorganization for such claims is insufficient in value to satisfy such claims in full. We consider such an outcome to be unlikely. To the extent that holders of the CalGen Third Lien Debt have claims that remain unsettled or outstanding, they assert that they continue 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. We dispute such allegations and contend that all liens were released when the CalGen secured claims were paid in full under the terms of applicable court orders and our Plan of Reorganization as confirmed. Recently the district court in the above litigation issued a decision that the holders of the CalGen Third Lien Debt were not entitled, as a matter of law, to a prepayment premium or to attorney’s fees associated with the payoff of the underlying obligations. Further, the district court determined that the holders of the CalGen Third Lien Debt were only entitled to interest as specified in the supporting debt agreements, but did not rule on the issue of this entitlement to default interest on their claims. We believe the holders of the CalGen Third Lien Debt will file an appeal of the judgment entered by the district court. We continue to engage in settlement discussions with the various constituencies in this dispute.

33

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

Forward-Looking Information

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

Introduction and Overview

We are the largest independent wholesale power 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 the major competitive CAISO, ERCOT and Eastern PJM power markets in 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 purchase natural gas 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-related commodity and derivative transactions to financially 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 reside. We seek to achieve sustainable growth through financially disciplined power plant development, construction, operations and ownership.

The Conectiv Acquisition on July 1, 2010, provided us with a significant presence in the Eastern PJM market, one of the most robust competitive power markets in the U.S., and positioned us with three scale markets instead of two (CAISO and ERCOT) giving us greater geographical diversity. We added 18 operating power plants and one plant under construction, with approximately 4,490 MW of capacity (including completion of the York Energy Center under construction and scheduled upgrades). Approximately 340 MW of the plants acquired have conventional steam turbine technology where coal has historically been used as the primary fuel source. However, these power plants have flexibility as to fuel source and are also capable of burning natural gas or fuel oil to generate power. These plants have ceased burning coal and we will not burn coal to generate power from these plants in the future. Instead, we expect to generate power from these plants using natural gas or fuel oil and plan to modernize these sites in the longer term to natural gas-fired combustion turbines.

We have continued to effectively manage our capital structure, strengthen our balance sheet, reduce the longer term risk of our debt maturities and focus our development and growth opportunities in our core markets with the following additional transactions:

• We entered into an agreement to sell our interests in Blue Spruce and Rocky Mountain for approximately $739 million, and we have entered into an agreement to sell an undivided 25% interest in the assets of our Freestone power plant for approximately $215 million. Both transactions are expected to close in the fourth quarter of 2010. We believe the proceeds from these sales will enable us to continue to strengthen our balance sheet, repay approximately $418 million in project level debt and fund future development and growth opportunities in our core markets.

• We entered into a purchase agreement with CIT Capital USA Inc., to purchase the equity interests related to our Broad River and South Point power plants for cash of approximately $38 million and assumed debt of approximately $282 million. The purchase will eliminate approximately $210 million in project debt. See also Note 6 of the Notes to Consolidated Condensed Financial Statements.

• We have continued to extend the maturity of our First Lien Credit Facility term loans with issuances of our First Lien Notes in a series of First Lien Note offerings during the months of May, July and October of 2010. We repaid approximately $3.5 billion with proceeds from the issuance of the 2019, 2020 and 2021 First Lien Notes and effectively extended an equal amount our 2014 debt maturities.

• On July 8, 2010, we repaid $100 million under the Commodity Collateral Revolver in accordance with its terms.

34

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

With the expected sale of Blue Spruce and Rocky Mountain, our portfolio, including partnership interests, will include 91 operating power plants with an aggregate generation capacity of nearly 28,000 MW and 1,087 MW under construction and advanced development. Our generation capacity will include approximately 3,801 MW of baseload capacity from our Geysers Assets and cogeneration power plants, 17,537 MW of intermediate load capacity from our combined-cycle combustion turbines and 6,400 MW of peaking capacity from our simple-cycle combustion turbines and duct-fired capability. Our segments will have an aggregate generation capacity of 6,886 MW with an additional 522 MW under advanced development in the West, 7,433 MW in Texas, 7,336 MW with an additional 565 MW under construction 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. We also have approximately 4 MW of capacity from solar power generation technology in the North.

On September 28, 2010, we announced with great regret the death of William J. Patterson, our non-executive Chairman of the Board of Directors, who passed away on September 24, 2010. Mr. Patterson also served on our Board’s Nominating and Governance Committee. As a result of Mr. Patterson’s death, the Board will act in due course to appoint a new Chairman and will consider the addition of another director to fill Mr. Patterson’s vacancy until the next annual meeting of shareholders, at which time, shareholders will vote on the election of all members of the Company’s Board of Directors.

We remain focused on increasing our earnings and generating cash flows sufficient to maintain adequate levels of liquidity in order to service our debt, meet our collateral needs and fund our operations and growth. 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.

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 2009 Form 10-K.

Tailoring Rule — As previously disclosed in “— Governmental and Regulatory Matters” of our 2009 Form 10-K, the EPA is moving forward to regulate GHG emissions pursuant to its existing authority under the Federal Clean Air Act. The EPA announced a proposal (the “Tailoring Rule”) to require sources emitting over 25,000 tons per year of GHG emissions to undergo major new source review (“NSR”) when such sources make modifications that would increase their GHG emissions by an additional 10,000 to 25,000 tons. Such modifications, or new construction, would be subject to the EPA’s PSD rules and subject to BACT for GHG, as well as public review and notice. The EPA finalized the Tailoring Rule on May 13, 2010, and increased the threshold of applicability from sources emitting over 25,000 tons per year to sources emitting over 100,000 tons per year of GHG. The EPA also increased the threshold for modifications from 10,000 to 25,000 tons to greater than 75,000 tons per year. Beginning in January 2011, new sources or modifications of existing sources that trigger major NSR for other criteria pollutants will also be subject to major NSR for GHG if emissions exceed these thresholds. Beginning in July 2011, sources exceeding the GHG PSD thresholds will be subject to major NSR, regardless of whether they trigger PSD review for other criteria pollutants. The EPA is expected to issue guidance to permitting authorities on the implementation of GHG BACT that is widely expected to focus on energy efficiency measures. We believe that the impact of the final Tailoring Rule will be neutral to us because we expect that our efficient power plants already achieve BACT for GHGs.

EPA Transport Rule — On July 6, 2010, the EPA proposed the Transport Rule, which would require 31 states and the District of Columbia to significantly improve air quality by reducing power plant emissions that contribute to ozone and fine particle pollution in other states. Beginning in 2012, emission reductions will be governed by this rule, instead of the

35

Clean Air Interstate Rule. The EPA estimates this rule, along with concurrent state and EPA actions, will reduce power plant SO2 emissions by 71% and NOX emissions by 52% over 2005 levels by year 2014. The Transport Rule establishes state specific emissions budgets and allows intrastate trading and limited interstate trading. All allowances will be distributed to existing and new sources with separate programs for annual emissions and ozone season emissions. Allowance budgets will be allocated to states for disbursement; however, the timing of the rule is such that states will likely defer to EPA as it relates to unit allocations and EPA’s proposed unit allocations will be based on historic emissions, an approach that we oppose.  We reviewed the proposed rules and submitted comments to the EPA.

New Jersey Air Regulations — New Jersey has enacted air regulations that will require future investment in controls to enable continued operation of certain of the generation assets we acquired in the Conectiv Acquisition which may result in additional control costs to us. Our 158 MW Deepwater power plant and certain of the New Jersey peaker power plants will need additional NOX controls to continue operating beyond 2015 under the regulations. The NJDEP is considering extending the compliance deadline for these power plants to 2017; however, a rule proposal has not yet been issued. The costs of such future controls is uncertain at this time, but is not expected to adversely impact our future financial position or results of operations.

Ballot Initiative to Suspend Implementation of AB 32 — In November 2010, California voters will vote on a ballot initiative that would suspend AB 32 until unemployment in California reaches 5.5%. Since unemployment levels have only reached that arbitrary mark three times in the past decade, their proposition, if passed, is an effective repeal of AB 32. We are actively opposing the ballot initiative.

Hazardous Air Pollutants — 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 maximum achievable control technology emissions standards 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. The consent decree requires the EPA to promulgate final maximum achievable control technology standards by November 2011 that will likely require mercury and acid gas control retrofits on marginal coal-fired power plants to be operational by 2014. Should coal-fired power plants in our regional markets be forced to retrofit or retire, the new standards could benefit our competitive position.

Derivatives Legislation — The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 (the "Dodd-Frank Act") was signed into law on July 21, 2010. Title VII of the Dodd-Frank Act addresses regulatory reform of the OTC derivatives market in the U.S. and significantly changes the regulatory framework of this market. Title VII will be effective 360 days from the enactment of the Dodd-Frank Act and the implementing regulation is to be completed by the same date. Until these regulations have been finalized, the extent to which the provisions of Title VII might affect our derivatives activities is unknown. A number of features of the legislation may impact our existing business. One of the most significant of these is the requirement for central clearing of many OTC derivatives transactions with clearing organizations. This requirement is subject to an end-user exception. Whereas our OTC transactions have traditionally been negotiated on a bilateral basis, including the collateral arrangements thereunder, they now will be subject to the collateral and margining procedures of the clearing organization. To the extent the end-user exception is available to us, we may elect not to clear certain transactions. In these instances, the collateral margining requirements for these uncleared transactions might be subject to the requirements prescribed by this regulation. It is not known at this time whether, and, if so, to what extent, we will be required to provide collateral (for both our cleared and uncleared transactions) in excess of what is currently provided under our existing hedging relationships. Further, it is not certain whether the new margin requirements will apply retroactively to existing OTC derivatives transactions. Other features of the Dodd-Frank Act which will have an impact on our derivatives activities include trade reporting, position limits and trade execution. The effect of the Dodd-Frank Act on traditional dealers and market-makers as well as the consequential effect on market liquidity and, hence, pricing is uncertain.

ERCOT Nodal Implementation — As disclosed in our 2009 Form 10-K, ERCOT intends to implement a nodal market at the end of 2010. ERCOT’s latest progress report on the nodal market indicates that it remains on schedule for a December 2010 implementation date. While we are unable to predict the business impact on us, it is possible that credit requirements for ERCOT from the nodal market could require us to post additional collateral in excess of amounts required in the current zonal market, and we are unable to rule out other impacts.

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

36

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 will likely impact FERC’s station power policies in all of the organized markets throughout the nation. Several parties have sought rehearing of FERC’s decision. If left unchanged, FERC’s remand order could result in our generation facilities paying more for station power, but we cannot reasonably estimate the impact the order could have on our fleet at this time .

37

Results of Operations for the Three Months Ended September 30, 2010 and 2009

Below are the results of operations for the three months ended September 30, 2010, as compared to the same period in 2009 (in millions, except for percentages and operating performance metrics). Our results of operations and operating performance metrics for the three months ended September 30, 2009 have been recast to exclude Blue Spruce and Rocky Mountain, which are reported in discontinued operations. Our 2010 results of operations and performance metrics also include our results from the assets we acquired from Conectiv since its acquisition on July 1, 2010, with no similar amounts included in our results of operations for the three months ended September 30, 2009. 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.

	2010			2009			$ Change			% Change
Operating revenues:
Commodity revenue	$	2,113		$	1,805		$	308			17	%
Mark-to-market activity(1)		14			12			2			17
Other revenue		3			5			(2	)		(40)
Operating revenues		2,130			1,822			308			17
Cost of revenue:
Fuel and purchased energy expense:
Commodity expense		1,260			1,061			(199	)		(19)
Mark-to-market activity(1)		(117	)		(31	)		86			#
Fuel and purchased energy expense		1,143			1,030			(113	)		(11)
Plant operating expense		199			189			(10	)		(5)
Depreciation and amortization expense		149			104			(45	)		(43)
Other cost of revenue(2)		20			19			(1	)		(5)
Total cost of revenue		1,511			1,342			(169	)		(13)
Gross profit		619			480			139			29
Sales, general and other administrative expense		44			38			(6	)		(16)
(Income) loss from unconsolidated investments in power plants		(1	)		13			14			#
Other operating expense		22			6			(16	)		#
Income from operations		554			423			131			31
Interest expense		314			195			(119	)		(61)
Interest (income)		(2	)		(3	)		(1	)		(33)
Debt extinguishment costs		20			16			(4	)		(25)
Other (income) expense, net		3			4			1			25
Income before reorganization items, income taxes and discontinued operations		219			211			8			4
Reorganization items		—			(8	)		(8	)		#
Income before income taxes and discontinued operations		219			219			—			—
Income tax (benefit) expense		21			(7	)		(28	)		#
Income before discontinued operations		198			226			(28	)		(12)
Discontinued operations, net of tax expense		19			11			8			73
Net income		217			237			(20	)		(8)
Net loss attributable to the noncontrolling interest		—			1			(1	)		#
Net income attributable to Calpine	$	217		$	238		$	(21	)		(9)
Operating Performance Metrics:		2010			2009		Change			% Change
MWh generated (in thousands)(3)		28,208			26,899			1,309			5	%
Average availability		95.9	%		97.0	%		(1.1	)		(1)
Average total MW in operation(3)		26,958			22,473			4,485			20
Average capacity factor, excluding peakers		54.3	%		60.5	%		(6.2	)		(10)
Steam Adjusted Heat Rate		7,415			7,286			(129	)		(2)

__________

# Variance of 100% or greater

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

(2) Includes $1 million of RGGI compliance and other environmental costs for both the three months ended September 30, 2010 and 2009, which are components of Commodity Margin.

(3) Represents generation and capacity from power plants that we both consolidate and operate and excludes Blue Spruce, Rocky Mountain, Greenfield LP, Whitby, Freeport Energy Center and 21.5% of Hidalgo Energy Center.

38

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 in “Commodity Margin and Adjusted EBITDA.”

Commodity revenue, net of commodity expense, increased $109 million for the three months ended September 30, 2010 compared to the same period in 2009, primarily due to:

• an increase of $163 million in the North due to the Conectiv Acquisition which closed on July 1, 2010 and stronger market conditions due to warmer weather;

• an increase of $13 million related to higher REC revenue from new contracts associated with our Geysers Assets in the third quarter of 2010 compared to the same period in 2009; and

• an increase of $16 million related to OMEC, which achieved commercial operation in October 2009 and was consolidated on January 1, 2010;

partially offset by:

• a decrease of $26 million related to the expiration of the PCF arrangement in the fourth quarter of 2009;

• lower average hedge margin on our hedge position resulting from relatively lower hedge prices in the third quarter of 2010 as compared to hedge prices for the same period in 2009; and

• lower realized spark spreads on open positions due to lower Market Heat Rates, primarily in California and Texas, due to weaker market conditions for the three months ended September 30, 2010 compared to 2009.

Our average total MW in operation increased by 4,485 MW, or 20%, primarily due to the Conectiv Acquisition and OMEC, which achieved commercial operations in October 2009 and was consolidated on January 1, 2010. Generation increased 5% due primarily to the Conectiv Acquisition and stronger market price conditions in the North partially offset by weaker market price conditions in California and Texas. Our average capacity factor, excluding peakers, decreased by 10% resulting from the power plants acquired in the Conectiv Acquisition having lower capacity factors than the other power plants in our fleet, as well as weaker market conditions in California and Texas in the third quarter of 2010 compared to 2009.

Expenses related to unrealized mark-to-market activity had a favorable variance of $86 million primarily due to unrealized gains in the third quarter of 2010 on short natural gas positions executed as economic hedges of forward spark spreads.

Plant operating expense increased $10 million for the three months ended September 30, 2010 compared to the same period in 2009, resulting from a $14 million increase related to the Conectiv Acquisition and a $5 million increase related to OMEC which achieved commercial operations in October 2009 and was consolidated on January 1, 2010. The increase was partially offset by a decrease of $10 million in costs from scrap parts related to outages.

Depreciation and amortization expense increased for the three months ended September 30, 2010 compared to the same period in 2009, primarily resulting from an increase of $22 million due to a revision in the estimated useful lives and salvage values of our power plants and related equipment and changing our Geysers Assets depreciation from the units of production method to the straight line method. See Note 3 of the Notes to Consolidated Condensed Financial Statements for further information regarding our change in useful lives and salvage values as well as our change from the units of production method to the straight line depreciation method for our Geysers Assets. Also contributing to the increase was $17 million in depreciation and amortization expense incurred related to the Conectiv Acquisition and $4 million related to OMEC which achieved commercial operation in October 2009 and was consolidated on January 1, 2010.

39

Sales, general and other administrative expense increased for the three months ended September 30, 2010 compared to the same period in 2009, due primarily to $5 million in Conectiv acquisition-related costs incurred during the third quarter of 2010.

(Income) loss from unconsolidated investments in power plants had a favorable change of $14 million for the three months ended September 30, 2010 compared to the same period in 2009, primarily due to the consolidation of OMEC on January 1, 2010. During the three months ended September 30, 2009, OMEC recorded a loss of $13 million which largely consisted of an $11 million loss related to mark-to-market activity from interest rate swap contracts. See Notes 1 and 4 of the Notes to Consolidated Condensed Financial Statements for further information regarding our consolidation of OMEC and unconsolidated investments, respectively.

Other operating expense increased for the three months ended September 30, 2010 compared to the same period in 2009 due to an impairment of $19 million in development costs related to a development project originated prior to our Chapter 11 bankruptcy proceedings. During the third quarter of 2010, we learned the project would not receive a PPA that would support its continued development and made the determination that continued development was unlikely. The impairment was partially offset by a decrease of $3 million in project development expense related to Russell City Energy Center which is under advanced stages of development.

Interest expense increased for the three months ended September 30, 2010 compared to the same period in 2009, primarily due to a $97 million unfavorable change in unrealized losses related to our interest rate swaps that do not qualify for hedge accounting, which included a $70 million unrealized loss previously recognized in AOCI and reclassified as a component of interest expense in the third quarter of 2010, as the interest rate swaps no longer qualified as cash flow hedges and unfavorable changes in fair value. Also contributing to the increase was $26 million in interest expense related to the NDH Project Debt incurred in the third quarter of 2010, as well as an increase in the annualized effective interest rates on our consolidated debt, excluding the impacts of capitalized interest and unrealized mark-to-market gains (losses) on interest rate swaps, after amortization of deferred financing costs and debt discounts, which increased to 8.3% for the three months ended September 30, 2010 from 7.7% for the three months ended September 30, 2009, due to the negative impact of realized activity on our interest rate swaps.

Debt extinguishment costs for the three months ended September 30, 2010 consisted of $20 million in debt extinguishment costs associated with the retirement of term loans under the First Lien Credit Facility in July 2010 in connection with the issuance of the 2020 First Lien Notes. Debt extinguishment costs for the three months ended September 30, 2009 consisted of $16 million in debt extinguishment costs associated with the CCFCP Preferred Shares that were redeemed in July 2009.

Reorganization items for the three months ended September 30, 2009 primarily consisted of a credit of approximately $6 million related to a favorable settlement during the third quarter of 2009 from a disputed claim on a PPA contract that was terminated in January 2006.

Income tax expense increased to $21 million for the three months ended September 30, 2010 compared to a tax (benefit) of $(7) million for the three months ended September 30, 2009. The increase in income tax expense resulted from an increase of $19 million for the CCFC group, a decrease in federal income tax of $1 million for the Calpine group and an increase of $29 million related to the application of intraperiod tax allocation for the three months ended September 30, 2010 compared to the same period in 2009. In addition, the overall increase in income tax tax expense was partially offset by a decrease in various state and foreign jurisdiction income taxes of $19 million for the three months ended September 30, 2010 compared to the three months ended September 30, 2009.

Income from discontinued operations increased for the three months ended September 30, 2010 compared to the same period in 2009 due largely to $5 million in depreciation expense recorded in the third quarter of 2009 while no such expense was recorded in the current period due to the cessation of depreciation of the property, plant and equipment for Rocky Mountain and Blue Spruce as the assets were classified as held for sale in April of 2010.

40

Results of Operations for the Nine Months Ended September 30, 2010 and 2009

Below are the results of operations for the nine months ended September 30, 2010, as compared to the same period in 2009 (in millions, except for percentages and operating performance metrics). Our results of operations and operating performance metrics for the nine months ended September 30, 2009 have been recast to exclude Blue Spruce and Rocky Mountain, which are reported in discontinued operations. Our 2010 results of operations and performance metrics also include our results from the assets we acquired from Conectiv since its acquisition on July 1, 2010, with no similar amounts included in our results of operations for the nine months ended September 30, 2009. 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.

	2010			2009			$ Change			% Change
Operating revenues:
Commodity revenue	$	5,042		$	4,806		$	236			5	%
Mark-to-market activity(1)		7			97			(90	)		(93)
Other revenue		25			16			9			56
Operating revenues		5,074			4,919			155			3
Cost of revenue:
Fuel and purchased energy expense:
Commodity expense		3,221			2,930			(291	)		(10)
Mark-to-market activity(1)		(205	)		37			242			#
Fuel and purchased energy expense		3,016			2,967			(49	)		(2)
Plant operating expense		630			638			8			1
Depreciation and amortization expense		414			317			(97	)		(31)
Other cost of revenue(2)		65			62			(3	)		(5)
Total cost of revenue		4,125			3,984			(141	)		(4)
Gross profit		949			935			14			1
Sales, general and other administrative expense		122			131			9			7
(Income) from unconsolidated investments in power plants		(14	)		(27	)		(13	)		(48)
Other operating expense		29			15			(14	)		(93)
Income from operations		812			816			(4	)		—
Interest expense		722			604			(118	)		(20)
Interest (income)		(8	)		(13	)		(5	)		(38)
Debt extinguishment costs		27			49			22			45
Other (income) expense, net		9			6			(3	)		(50)
Income before reorganization items, income taxes and discontinued operations		62			170			(108	)		(64)
Reorganization items		—			(2	)		(2	)		#
Income before income taxes and discontinued operations		62			172			(110	)		(64)
Income tax expense		38			17			(21	)		#
Income before discontinued operations		24			155			(131	)		(85)
Discontinued operations, net of tax expense		31			34			(3	)		(9)
Net income		55			189			(134	)		(71)
Net loss attributable to the noncontrolling interest		—			3			(3	)		#
Net income attributable to Calpine	$	55		$	192		$	(137	)		(71)
Operating Performance Metrics:		2010			2009		Change			% Change
MWh generated (in thousands)(3)		67,813			63,475			4,338			7	%
Average availability		91.5	%		92.7	%		(1.2	)		(1)
Average total MW in operation(3)		24,364			22,473			1,891			8
Average capacity factor, excluding peakers		47.9	%		48.4	%		(0.5	)		(1)
Steam Adjusted Heat Rate		7,328			7,259			(69	)		(1)

__________

# Variance of 100% or greater

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

(2) Includes $6 million and $5 million of RGGI compliance and other environmental costs for the nine months ended September 30, 2010 and 2009, respectively, which are components of Commodity Margin.

(3) Represents generation and capacity from power plants that we both consolidate and operate and excludes Blue Spruce, Rocky Mountain, Greenfield LP, Whitby, Freeport Energy Center and 21.5% of Hidalgo Energy Center.

41

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 in “Commodity Margin and Adjusted EBITDA.”

Commodity revenue, net of commodity expense, decreased $55 million for the nine months ended September 30, 2010 compared to the same period in 2009, primarily due to:

• a decrease of $77 million related to the expiration of the PCF arrangement in the fourth quarter of 2009;

• lower average hedge margin on our hedge position resulting from relatively lower hedge prices in the third quarter of 2010 as compared to hedge prices for the same period in 2009; and

• lower realized spark spreads on open positions due to lower Market Heat Rates, primarily in California and Texas, due to weaker market conditions, for the three months ended September 30, 2010 compared to 2009;

partially offset by:

• an increase of $175 million in the North due to the Conectiv Acquisition which closed on July 1, 2010, and stronger market conditions due to warmer weather;

• an increase of $39 million related to higher REC revenue from new contracts associated with our Geysers Assets for the nine months ended September 30, 2010 compared to the same period in 2009; and

• an increase of $56 million related to OMEC, which achieved commercial operation in October 2009 and was consolidated on January 1, 2010.

Our average total MW in operation increased by 1,891 MW, or 8%, primarily due to the Conectiv Acquisition and OMEC, which achieved commercial operations in October 2009 and was consolidated on January 1, 2010. Generation increased 7% due primarily to the Conectiv Acquisition and stronger market price conditions in the North partially offset by weaker market price conditions in California and Texas.

Revenues from unrealized mark-to-market activity decreased by $90 million primarily related to the settlement of short Heat Rate swap positions during the nine months ended September 30, 2010. Expenses from unrealized mark-to-market activity had a favorable variance of $242 million due to unrealized gains on short natural gas positions during the nine months ended September 30, 2010.

Other revenue increased for the nine months ended September 30, 2010 compared to the same period in 2009, due primarily to $18 million in revenue recognized in 2010 which included a $15 million adjustment related to prior periods on a major maintenance contract. This increase was partially offset by a decrease of $7 million related to an operations and maintenance contract that expired in March 2010.

Plant operating expense decreased $8 million during the nine months ended September 30, 2010 compared to the same period in 2009, resulting from a decrease of $22 million in costs from scrap parts related to outages. Also contributing to the favorable change was a decrease of $6 million in normal, recurring plant operating expenses, a decrease of $5 million in stock-based compensation expense related to plant personnel costs and a $10 million decrease in major maintenance resulting from our plant outage schedule. The decrease in plant operating expense was partially offset by an increase of $12 million related to OMEC, which achieved commercial operations in October 2009 and was consolidated on January 1, 2010, a $14 million increase related to the Conectiv Acquisition and a $9 million increase related to costs incurred for unscheduled outages predominantly in our Texas region.

Depreciation and amortization expense increased for the nine months ended September 30, 2010 compared to the same period in 2009, primarily resulting from an increase of $68 million due to a revision in the estimated useful lives and salvage values of our power plants and related equipment and changing our Geysers Assets depreciation from the units of production method to the straight line method. See Note 3 of the Notes to Consolidated Condensed Financial Statements for further information regarding our change in useful lives and salvage values as well as our change from the units of production

42

method to the straight line depreciation method for our Geysers Assets. Also contributing to the increase was $17 million in depreciation and amortization expense incurred related to the Conectiv Acquisition and $12 million related to OMEC which achieved commercial operation in October 2009 and was consolidated on January 1, 2010.

Sales, general and other administrative expense decreased for the nine months ended September 30, 2010 compared to the same period in 2009, due to a $12 million favorable change in our bad debt expense primarily related to a $10 million reversal of our 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, an $11 million decrease in personnel costs due largely to lower stock-based compensation expense and temporary labor costs, an $8 million decrease in consulting expense and a $4 million decrease in office expense. The decrease was partially offset by $24 million in Conectiv acquisition-related costs incurred during the nine months ended September 30, 2010.

Income from unconsolidated investments in power plants decreased by $13 million for the nine months ended September 30, 2010 compared to the same period in 2009, primarily due to the consolidation of OMEC on January 1, 2010. During the nine months ended September 30, 2009, OMEC recorded income of $13 million which largely consisted of a $20 million gain related to mark-to-market activity from interest rate swap contracts. See Notes 1 and 4 of the Notes to Consolidated Condensed Financial Statements for further information regarding our consolidation of OMEC and unconsolidated investments, respectively.

Other operating expense increased for the nine months ended September 30, 2010 compared to the same period in 2009 due to an impairment of $19 million in development costs related to a development project originated prior to our Chapter 11 bankruptcy proceedings. During the third quarter of 2010, we learned the project would not receive a PPA that would support its continued development and made the determination that continued development was unlikely. The impairment was partially offset by a decrease of $8 million in project development expense related to Russell City Energy Center, which is under advanced stages of development.

Interest expense increased for the nine months ended September 30, 2010 compared to the same period in 2009, primarily due to a $120 million unfavorable change in unrealized losses related to our interest rate swaps that do not qualify for hedge accounting, which included a $70 million loss previously recognized in AOCI and reclassified as a component of interest expense in the third quarter of 2010, as the interest rate swaps no longer qualified as cash flow hedges and unfavorable changes in fair value. Also contributing to the increase was $26 million in interest expense related to the NDH Project Debt incurred in the third quarter of 2010, a $19 million increase related to the consolidation of OMEC on January 1, 2010 and an increase in the annualized effective interest rates on our consolidated debt, excluding the impacts of capitalized interest and unrealized mark-to-market gains (losses) on interest rate swaps, after amortization of deferred financing costs and debt discounts, which increased to 8.4% for the nine months ended September 30, 2010 from 7.9% for the nine months ended September 30, 2009, due to the negative impact of realized activity on our interest rate swaps. The increase was partially offset by a decrease of $23 million resulting from the repayment in February 2010 of the notes related to PCF and PCF III, as well as a decrease of $17 million related to the refinancing of our CCFC Old Notes and CCFC Term Loans in May and June 2009, respectively, and the CCFCP Preferred Shares that were redeemed on or before July 1, 2009.

Debt extinguishment costs for the nine months ended September 30, 2010 consisted of $27 million in debt extinguishment costs associated with the retirement of term loans under the First Lien Credit Facility in May and July 2010 in connection with the issuance of the 2019 First Lien Notes and 2020 First Lien Notes. Debt extinguishment costs for the nine months ended September 30, 2009 consisted of $49 million in debt extinguishment costs associated with the refinancing of our CCFC Old Notes and CCFC Term Loans in May and June 2009, respectively, and the CCFCP Preferred Shares that were redeemed on or before July 1, 2009.

43

Income tax expense increased to $38 million for the nine months ended September 30, 2010 compared to $17 million for the nine months ended September 30, 2009. The increase in income tax expense resulted from an increase in federal income tax of $28 million for the CCFC group and $11 million for the Calpine group for the nine months ended September 30, 2010 compared to the same period in 2009. In addition, the overall increase in income tax expense was partially offset by a decrease of $15 million related to the application of intraperiod tax allocation and a decrease in various state and foreign jurisdiction income taxes of $3 million for the nine months ended September 30, 2010 compared to the same period in 2009.

44

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 a measure 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 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 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 gross profit (loss), 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 September 30, 2010 and 2009

The following tables show our Commodity Margin and related operating performance metrics by segment for the three months ended September 30, 2010 and 2009. Our Commodity Margin and related performance metrics for the three months ended September 30, 2009, in our West segment have been recast to exclude Blue Spruce and Rocky Mountain. In the comparative tables below, favorable variances are shown without brackets while unfavorable variances are shown with brackets.

West:	2010			2009			Change			% Change
Commodity Margin (in millions)	$	338		$	368		$	(30	)		(8)	%
Commodity Margin per MWh generated	$	41.76		$	39.59		$	2.17			5
MWh generated (in thousands)		8,093			9,295			(1,202	)		(13)
Average availability		92.9	%		94.5	%		(1.6	)		(2)
Average total MW in operation		6,886			6,371			515			8
Average capacity factor, excluding peakers		58.7	%		72.8	%		(14.1	)		(19)
Steam Adjusted Heat Rate		7,345			7,287			(58	)		(1)

West — Commodity Margin in our West segment decreased by $30 million, or 8%, for the three months ended September 30, 2010 compared to the same period in 2009, primarily resulting from a decrease of $26 million related to the expiration of the PCF arrangement in the fourth quarter of 2009, lower average hedge prices for the third quarter of 2010 compared to 2009, and lower realized spark spreads on our open positions due to lower Market Heat Rates caused by cooler weather in the third quarter of 2010 compared to the third quarter of 2009, plus an overall increase in installed generation capacity in California in 2010 compared to the same period in 2009. The decrease in Commodity Margin was partially offset by an increase of $13 million related to higher REC revenue from new contracts associated with our Geysers Assets and $16 million from OMEC that achieved commercial operation in October 2009 and was consolidated on January 1, 2010. Average total MW in operation increased 515 MW, or 8%, due primarily to OMEC which was partially offset by the retirement of our Pittsburg power plant in March 2010 and the expiration of the operating lease and subsequent retirement of our Watsonville (Monterey) cogeneration power plant in May 2010. Despite this increase in generation capacity, weaker market price conditions described above contributed to a 13% decrease in generation for the three months ended September 30, 2010 compared to the same period in 2009 and an unplanned outage at OMEC negatively impacted our average availability in the third quarter of 2010.

45

Texas:	2010			2009			Change			% Change
Commodity Margin (in millions)	$	165		$	187		$	(22	)		(12)	%
Commodity Margin per MWh generated	$	17.31		$	18.25		$	(0.94	)		(5)
MWh generated (in thousands)		9,533			10,246			(713	)		(7)
Average availability		96.5	%		97.5	%		(1.0	)		(1)
Average total MW in operation		7,197			7,146			51			1
Average capacity factor, excluding peakers		60.0	%		64.9	%		(4.9	)		(8)
Steam Adjusted Heat Rate		7,305			7,227			(78	)		(1)

Texas — Commodity Margin in our Texas segment decreased by $22 million, or 12%, for the three months ended September 30, 2010 compared to the same period in 2009, primarily resulting from lower average hedge prices and lower realized spark spreads on open positions due to lower Market Heat Rates caused primarily by an overall increase in installed generation capacity in ERCOT for the third quarter of 2010 compared to the same period in 2009. The weaker market price conditions also contributed to a 7% decrease in generation in the third quarter of 2010 as compared to the same quarter in 2009. Average total MW in operation increased 51 MW due to the completion of turbine upgrades at our Pasadena and Deer Park power plants in the first half of 2010.

North:	2010			2009			Change			% Change
Commodity Margin (in millions)	$	259		$	96		$	163			#	%
Commodity Margin per MWh generated	$	57.34		$	71.01		$	(13.67	)		(19)
MWh generated (in thousands)		4,517			1,352			3,165			#
Average availability		96.8	%		98.5	%		(1.7	)		(2)
Average total MW in operation		6,792			2,873			3,919			#
Average capacity factor, excluding peakers		43.7	%		30.6	%		13.1			43
Steam Adjusted Heat Rate		7,865			7,758			(107	)		(1)

North — Commodity Margin in our North segment increased by $163 million primarily due to the Conectiv Acquisition which closed on July 1, 2010, higher average hedge prices and higher realized spark spreads on open positions driven by much warmer weather for July and September 2010 compared to the same periods in 2009. The Conectiv Acquisition led to a 3,919 MW increase in our average total MW in operation as well as a 2,528 MWh increase in generation while stronger market pricing led to a 47% increase in generation among our existing power plants in the third quarter of 2010 compared to the same period in 2009.

Southeast:	2010			2009			Change			% Change
Commodity Margin (in millions)	$	90		$	92		$	(2	)		(2)	%
Commodity Margin per MWh generated	$	14.84		$	15.32		$	(0.48	)		(3)
MWh generated (in thousands)		6,065			6,006			59			1
Average availability		97.4	%		98.2	%		(0.8	)		(1)
Average total MW in operation		6,083			6,083			—			—
Average capacity factor, excluding peakers		49.3	%		51.2	%		(1.9	)		(4)
Steam Adjusted Heat Rate		7,366			7,187			(179	)		(2)

Southeast — Commodity Margin in our Southeast segment for the three months ended September 30, 2010 remains comparable to the same period in 2009. The marginal decrease resulted from higher natural gas generation displacement of coal generation in certain sub-markets in our Southeast segment in the third quarter of 2009 largely offset by higher realized spark spreads on open positions due to warmer weather for the three months ended September 30, 2010 compared to the same period in 2009.

Commodity Margin by Segment for the Nine Months Ended September 30, 2010 and 2009

The following tables show our Commodity Margin and related operating performance metrics by segment for the nine months ended September 30, 2010 and 2009. Our Commodity Margin and related performance metrics for the nine

46

months ended September 30, 2009, in our West segment have been recast to exclude Blue Spruce and Rocky Mountain. In the comparative tables below, favorable variances are shown without brackets while unfavorable variances are shown with brackets.

West:	2010			2009			Change			% Change
Commodity Margin (in millions)	$	809		$	918		$	(109	)		(12)	%
Commodity Margin per MWh generated	$	35.49		$	40.15		$	(4.66	)		(12)
MWh generated (in thousands)		22,795			22,866			(71	)		—
Average availability		91.5	%		91.4	%		0.1			—
Average total MW in operation		6,919			6,371			548			9
Average capacity factor, excluding peakers		55.7	%		60.9	%		(5.2	)		(9)
Steam Adjusted Heat Rate		7,315			7,318			3			—

West — Commodity Margin in our West segment decreased by $109 million, or 12%, for the nine months ended September 30, 2010 compared to the same period in 2009, primarily resulting from a decrease of $77 million related to the expiration of the PCF arrangement in the fourth quarter of 2009, lower average hedge prices in 2010 compared to 2009, lower realized spark spreads on our open positions due to lower Market Heat Rates caused primarily by cooler temperatures in 2010 compared to 2009 and an overall increase in installed generation capacity in California in 2010. Also contributing to the unfavorable period over period change was a decrease of $11 million for the sale of surplus emission allowances in the first quarter of 2009 which did not reoccur in the same period in 2010. The decrease in Commodity Margin was partially offset by an increase of $39 million related to higher REC revenue from new contracts associated with our Geysers Assets, $56 million from OMEC that achieved commercial operation in October 2009 and was consolidated on January 1, 2010 and a $12 million credit recognized in the second quarter of 2010 related to overcharges associated with a gas transportation contract. Average total MW in operation increased 548 MW, or 9%, due primarily to OMEC which was partially offset by the retirement of our Pittsburg power plant in March 2010 as well as the expiration of the operating lease and subsequent retirement of our Watsonville (Monterey) cogeneration power plant in May 2010.

Texas:	2010			2009			Change			% Change
Commodity Margin (in millions)	$	400		$	505		$	(105	)		(21)	%
Commodity Margin per MWh generated	$	16.38		$	21.90		$	(5.52	)		(25)
MWh generated (in thousands)		24,419			23,058			1,361			6
Average availability		89.1	%		92.1	%		(3.0	)		(3)
Average total MW in operation		7,183			7,146			37			1
Average capacity factor, excluding peakers		51.9	%		49.3	%		2.6			5
Steam Adjusted Heat Rate		7,222			7,149			(73	)		(1)

Texas — Commodity Margin in our Texas segment decreased by $105 million, or 21%, for the nine months ended September 30, 2010 compared to the same period in 2009, primarily resulting from lower average hedge prices and lower realized spark spreads on open positions due to lower Market Heat Rates, particularly with regard to June 2010, which did not benefit from the extreme heat, congestion-driven pricing and tighter reserve margin that occurred in June 2009, as well as an overall increase in installed generation capacity in ERCOT in 2010 compared to 2009. Generation increased 6% driven by higher spark spreads in April 2010, as well as colder weather in January and February 2010 compared to the same periods in 2009.

North:	2010			2009			Change			% Change
Commodity Margin (in millions)	$	390		$	215		$	175			81
Commodity Margin per MWh generated	$	56.63		$	57.97		$	(1.34	)		(2)
MWh generated (in thousands)		6,887			3,709			3,178			86
Average availability		93.1	%		95.5	%		(2.4	)		(3)
Average total MW in operation		4,179			2,873			1,306			45
Average capacity factor, excluding peakers		36.8	%		29.3	%		7.5			26
Steam Adjusted Heat Rate		7,773			7,693			(80	)		(1)

North — Commodity Margin in our North segment increased by $175 million primarily due to the Conectiv Acquisition which closed on July 1, 2010, higher average hedge prices and higher realized spark spreads on open positions

47

driven by much warmer weather in the second and third quarters of 2010 compared to the same periods in 2009. The Conectiv Acquisition led to a 1,306 MW increase in our average total MW in operation as well as a 2,528 MWh increase in generation while stronger market pricing led to an 18% increase in generation among our existing power plants for the nine months ended September 30, 2010 compared to the same period in 2009.

Southeast:	2010			2009			Change			% Change
Commodity Margin (in millions)	$	216		$	233		$	(17	)		(7)	%
Commodity Margin per MWh generated	$	15.75		$	16.83		$	(1.08	)		(6)
MWh generated (in thousands)		13,712			13,842			(130	)		(1)
Average availability		93.4	%		93.3	%		0.1			—
Average total MW in operation		6,083			6,083			—			—
Average capacity factor, excluding peakers		38.4	%		40.2	%		(1.8	)		(4)
Steam Adjusted Heat Rate		7,331			7,214			(117	)		(2)

Southeast — Commodity Margin in our Southeast segment decreased by $17 million, or 7%, for the nine months ended September 30, 2010 compared to the same period in 2009 primarily as a result of lower average hedge prices and lower realized spark spreads for our Oneta and Pine Bluff power plants for the first half of 2010 compared to the same period in 2009. During the first six months of 2009, in contrast to the same period in 2010, these plants were advantaged by lower delivered natural gas prices relative to many of our competitors driving higher realized spark spreads. The decrease in Commodity Margin was partially offset by higher realized spark spreads on open positions throughout the rest of the Southeast region (excluding our Oneta and Pine Bluff power plants) caused by warmer weather in May and June 2010, as well as the non-recurring negative impact from the settlement of a disputed steam contract in the second quarter of 2009.

48

Adjusted EBITDA

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

	Three Months Ended September 30, 2010
													Consolidation
													and
	West			Texas			North			Southeast			Elimination			Total
Net income attributable to Calpine																$	217
Net income attributable to noncontrolling interest																	—
Discontinued operations, net of tax expense																	(19	)
Income tax expense																	21
Other (income) expense and debt extinguishment costs, net																	23
Interest expense, net																	312
Income from operations	$	218		$	122		$	185		$	28		$	1		$	554
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs (1)		51			37			37			27			(1	)		151
Impairment loss		—			—			—			19			—			19
Major maintenance expense		2			8			1			2			—			13
Operating lease expense		5			—			6			—			—			11
Unrealized gains on commodity derivative mark-to-market activity		(39	)		(57	)		(17	)		(18	)		—			(131	)
Adjustments to reflect Adjusted EBITDA from unconsolidated investments (2)		—			—			10			—			—			10
Stock-based compensation expense		3			1			1			1			—			6
Non-cash loss on dispositions of assets		—			2			—			—			—			2
Conectiv acquisition-related costs		—			—			6			—			—			6
Other		—			1			1			—			—			2
Adjusted EBITDA from continuing operations		240			114			230			59			—			643
Adjusted EBITDA from discontinued operations		20			—			—			—			—			20
Total Adjusted EBITDA	$	260		$	114		$	230		$	59		$	—		$	663

49

	Three Months Ended September 30, 2009
											Consolidation
											and
	West			Texas		North			Southeast		Elimination			Total
Net income attributable to Calpine														$	238
Net loss attributable to noncontrolling interest															(1	)
Discontinued operations, net of tax expense															(11	)
Income tax benefit															(7	)
Reorganization items															(8	)
Other (income) expense and debt extinguishment costs, net															20
Interest expense, net															192
Income from operations	$	223		$	107	$	70		$	33	$	(10	)	$	423
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs (1)		46			29		16			17		(2	)		106
Major maintenance expense		8			4		2			5		—			19
Operating lease expense		6			—		6			—		—			12
Unrealized gains on commodity derivative mark-to-market activity		(34	)		3		(19	)		7		—			(43	)
Adjustments to reflect Adjusted EBITDA from unconsolidated investments (2)		13			—		15			—		—			28
Stock-based compensation expense		3			3		—			2		—			8
Non-cash loss on dispositions of assets		4			6		—			2		—			12
Other		—			—		(1	)		—		—			(1	)
Adjusted EBITDA from continuing operations		269			152		89			66		(12	)		564
Adjusted EBITDA from discontinued operations		22			—		—			—		—			22
Total Adjusted EBITDA	$	291		$	152	$	89		$	66	$	(12	)	$	586

	Nine Months Ended September 30, 2010
													Consolidation
													and
	West			Texas			North			Southeast			Elimination			Total
Net income attributable to Calpine																$	55
Discontinued operations, net of tax expense																	(31	)
Income tax expense																	38
Other (income) expense and debt extinguishment costs, net																	36
Interest expense, net																	714
Income from operations	$	371		$	187		$	205		$	44		$	5		$	812
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs (1)		155			113			76			85			(5	)		424
Impairment loss		—			—			—			19			—			19
Major maintenance expense		21			68			7			15			—			111
Operating lease expense		14			—			19			—			—			33
Unrealized gains on commodity derivative mark-to-market activity		(50	)		(118	)		(16	)		(28	)		—			(212	)
Adjustments to reflect Adjusted EBITDA from unconsolidated investments (2)		—			—			25			—			—			25
Stock-based compensation expense		8			6			2			2			—			18
Non-cash (gain) loss on dispositions of assets		(1	)		7			—			1			—			7
Conectiv acquisition-related costs		—			—			25			—			—			25
Other		1			1			1			—			—			3
Adjusted EBITDA from continuing operations		519			264			344			138			—			1,265
Adjusted EBITDA from discontinued operations		61			—			—			—			—			61
Total Adjusted EBITDA	$	580		$	264		$	344		$	138		$	—		$	1,326

50

	Nine Months Ended September 30, 2009
											Consolidation
											and
	West			Texas		North			Southeast		Elimination			Total
Net income attributable to Calpine														$	192
Net loss attributable to noncontrolling interest															(3	)
Discontinued operations, net of tax expense															(34	)
Income tax expense															17
Reorganization items															(2	)
Other (income) expense and debt extinguishment costs, net															55
Interest expense, net															591
Income from operations	$	502		$	144	$	121		$	61	$	(12	)	$	816
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs (1)		139			92		47			53		(5	)		326
Major maintenance expense		66			33		1			21		—			121
Operating lease expense		16			—		19			—		—			35
Unrealized gains on commodity derivative mark-to-market activity		(95	)		63		(33	)		5		—			(60	)
Adjustments to reflect Adjusted EBITDA from unconsolidated investments(2)		(13	)		—		24			—		—			11
Stock-based compensation expense		13			10		2			5		—			30
Non-cash loss on dispositions of assets		10			13		2			4		—			29
Other		3			—		—			—		—			3
Adjusted EBITDA from continuing operations		641			355		183			149		(17	)		1,311
Adjusted EBITDA from discontinued operations		63			—		—			—		—			63
Total Adjusted EBITDA	$	704		$	355	$	183		$	149	$	(17	)	$	1,374

__________

(1) Depreciation and amortization expense in the income from operations calculation on our Consolidated Condensed Statements of Operations excludes amortization of other assets and amounts classified as sales, general and other administrative expenses.

(2) Adjustments to reflect Adjusted EBITDA from unconsolidated investments include unrealized gains (losses) on mark-to-market activity of $(1) and $(7) million for the three months ended September 30, 2010 and 2009, respectively, and $(1) and $34 million for the nine months ended September 30, 2010 and 2009, respectively.

51

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

As of September 30, 2010, we had $914 million in cash and cash equivalents and $341 million of restricted cash. Amounts available for future cash borrowings were $740 million under our First Lien Credit Facility revolver and $65 million under our NDH Project Debt. The following table provides a summary of our liquidity position at September 30, 2010, and December 31, 2009 (in millions):

	September 30, 2010		December 31, 2009
Cash and cash equivalents, corporate(1)	$	610	$	725
Cash and cash equivalents, non-corporate		304		264
Total cash and cash equivalents		914		989
Restricted cash		341		562
Letter of credit availability(2)		40		34
Revolver availability		805		794
Total current availability	$	2,100	$	2,379

_________

(1) Includes $62 million and $9 million of margin deposits held by us posted by our counterparties as of September 30, 2010, and December 31, 2009, respectively.

(2) Includes availability under Calpine Development Holdings, Inc. at September 30, 2010.

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 the remainder of 2010 and hedged a material portion of our portfolio in a similar manner in 2011; however, we remain susceptible to significant price movements for 2012 and beyond. The future impact on our Commodity Margin beyond 2010 is highly dependent on the severity and duration of the recessionary environment we experienced in 2008 through the first nine months of 2010, the speed, strength and duration of an economic recovery, if any, the price of natural gas and the level of Market Heat Rates, and our continued ability to successfully hedge our Commodity Margin.

It is difficult to predict future developments and the amount of credit support that we may need to provide as part of our business operations should financial market and commodity price volatility and economic uncertainty persist for a significant period of time. Our ability to generate sufficient cash is dependent upon, among other things:

• improving the profitability of our operations;

• continued compliance with the covenants under our existing financing obligations, including our First Lien Credit Facility, First Lien Notes and NDH Project Debt;

• stabilizing and increasing future contractual cash flows; and

• our significant counterparties performing under their contracts with us.

Liquidity Sensitivity — Significant changes in commodity prices and Market Heat Rates can have an impact on our liquidity as we use margin deposits, cash prepayments and letters of credit as credit support (collateral) with and from our counterparties for commodity procurement and risk management activities. Utilizing our portfolio of transactions subject to collateral exposure, we estimate that as of October 15, 2010, an increase of $1/MMBtu in natural gas prices would result in an increase of collateral required by approximately $212 million. If natural gas prices decreased by $1/MMBtu, we estimate that our collateral requirements would decrease by approximately $202 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; therefore, we derived a statistical analysis that implies that a change of

52

$1/MMBtu in natural gas approximates an average Market Heat Rate change of 170 Btu/kWh. We estimate that as of October 15, 2010, an increase of 170 Btu/kWh in the Market Heat Rate would result in an increase in collateral required by approximately $19 million. If Market Heat Rates were to fall at a similar rate, we estimate that our collateral required would decrease by approximately $20 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.

In order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to our counterparties, we have granted additional liens on the assets currently subject to liens under our First Lien Credit Facility to collateralize our obligations under certain of our power and natural gas agreements that qualify as “eligible commodity hedge agreements” under our First Lien Credit Facility and certain of our interest rate swap agreements. The counterparties under such agreements will share the benefits of the collateral subject to such liens ratably with the lenders under our First Lien Credit Facility. We continue to use these additional liens to manage cash collateral that would otherwise be required. See Note 9 of the Notes to Consolidated Condensed Financial Statements for further information on our margin deposits and collateral used for commodity procurement and risk management activities.

Significant Financing Transactions — During 2010, we successfully closed the following financing transactions:
 

• On May 25, 2010, we issued the 2019 First Lien Notes in an aggregate principal amount of $400 million in a private placement. The 2019 First Lien Notes mature on August 15, 2019.

• On June 8, 2010, NDH entered into the NDH Project Debt and received net proceeds of $1.3 billion on July 1, 2010, which were used, together with available cash, to pay the Conectiv Acquisition purchase price of approximately $1.64 billion. Our NDH Project Debt includes a $1.3 billion seven-year senior secured term facility and a $100 million three-year senior secured revolving credit facility, of which up to $50 million will be available through a subfacility in the form of letters of credit.

• On July 23, 2010, we issued the 2020 First Lien Notes in an aggregate principal amount of $1.1 billion in a private placement. The 2020 First Lien Notes mature on July 31, 2020.

• On October 22, 2010, we issued $2.0 billion in aggregate principle amount of the 2021 First Lien Notes in a private placement. The 2021 First Lien Notes mature on February 15, 2021.

The net proceeds from the 2019, 2020 and 2021 First Lien Notes were used to repay approximately $3.5 billion of term loan borrowings under our First Lien Credit Facility in May, July and October 2010, effectively extending approximately $3.5 billion of our 2014 debt maturities. We also repaid $100 million, plus accrued interest, outstanding under our Commodity Collateral Revolver in accordance with its terms on July 8, 2010, from available cash. While we cannot provide any assurance that we will continue to be successful in the future, if credit markets present favorable opportunities, we will continue to refinance additional portions of our nearer term maturities or more costly debt. We have commitments to refinance our existing $1.0 billion revolver under our First Lien Credit Facility.

As part of the Conectiv Acquisition and NDH Project Debt, we entered into various intercompany agreements with our NDH subsidiaries for the related sales and purchases of power, natural gas and the operation and maintenance of our NDH power plants, which will not materially impact our results of operations, financial condition or cash flows on a consolidated basis. While there is no direct recourse by holders of the NDH Project Debt to Calpine Corporation, a substantial portion of the commodity price risk related to NDH’s power generation is absorbed by Calpine Energy Services, L.P. an indirect, wholly owned subsidiary of Calpine Corporation, which purchases the power generated by NDH under an intercompany tolling agreement, which is also guaranteed by Calpine Corporation.

See also Note 6 of the Notes to Consolidated Condensed Financial Statements for further discussion of our 2019, 2020 and 2021 First Lien Notes and our NDH Project Debt.

53

Letter of Credit Facilities — The table below represents amounts issued under our letter of credit facilities as of September 30, 2010 and December 31, 2009 (in millions):

	September 30,		December 31,
	2010		2009
First Lien Credit Facility	$	260	$	206
Calpine Development Holdings, Inc.(1)		160		116
NDH Credit Facility		35		—
Various project financing facilities		109		90
Total	$	564	$	412

__________

(1) Availability under the Calpine Development Holdings, Inc. letter of credit was increased by $50 million to $200 million on June 30, 2010.

Cash Management — We manage our cash in accordance with our intercompany cash management system subject to the requirements of our First Lien Credit 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, generally exceed FDIC insured limits or 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 do not expect to pay any cash dividends on our common stock for the foreseeable future because we are currently restricted under our First Lien Credit Facility and certain of our other debt agreements from paying cash dividends. 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.

Off Balance Sheet Arrangements

Corporate Office Lease — On October 1, 2010, we amended the lease for our corporate offices in Houston, Texas to extend the lease through 2020 for a total obligation of approximately $93 million over the life of the amended lease term.

Evolving Power Market Trends

We believe that environmental pressures continue to increase for coal-fired power generation and economic and reliability concerns remain for renewable generation. In addition, the availability of non-conventional natural gas supplies, in particular from the emergence of significant deposits of shale natural gas, has altered the natural gas supply landscape in the U.S. which could have a longer-term and profound impact on natural gas markets. The potential for sustainable supplies of natural gas at low prices relative to those seen over the last several years may adversely impact our Commodity Margin in the short term as our cost of production advantage relative to less efficient natural gas-fired generation is diminished on an absolute basis, but is expected to provide a more robust environment for natural gas-fired power generation compared to coal-fired and renewable generation over the longer-term.

54

Acquisitions and Divestitures

Conectiv Acquisition — On July 1, 2010, we, through our indirect, wholly owned subsidiary NDH, completed the Conectiv Acquisition. We financed the transaction through available cash and bank debt of $1.3 billion provided under the NDH Project Debt. The assets acquired include 18 operating power plants and one plant under construction, with approximately 4,490 MW of capacity (including completion of the York Energy Center under construction and scheduled upgrades). The Conectiv Acquisition gives us significant presence in the Eastern PJM market. 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 128 union employees acquired in the Conectiv Acquisition of less than $10 million on the acquisition date. Our purchase price was approximately $1.64 billion.

See also Notes 2 and 6 of the Notes to Consolidated Condensed Financial Statements for additional details of the Conectiv Purchase Agreement, the Conectiv Acquisition and the NDH Project Debt.

Acquisition of Broad River and South Point — On September 23, 2010, we, through our wholly owned, indirect subsidiary, Calpine BRSP, entered into a purchase agreement with CIT Capital USA Inc., to purchase the equity interests related to our Broad River and South Point power plants for $320 million. We currently operate the Broad River power plant under a lease, which did not qualify as a sale-leaseback transaction under U.S. GAAP and the lease obligation is accounted for as debt in our project financing, notes payable and other debt balance, and we operate the South Point power plant under an operating lease, both with CIT Capital USA Inc. The purchase price consists of cash of approximately $38 million and assumed debt of approximately $282 million. This transaction requires FERC approval and is expected to close in the fourth quarter of 2010.

Sale of Blue Spruce and Rocky Mountain — On April 2, 2010, we, through our wholly owned subsidiaries Riverside Energy Center, LLC and Calpine Development Holdings, Inc., entered into an agreement with PSCo to sell 100% of our ownership interests in Blue Spruce and Rocky Mountain for approximately $739 million, subject to certain working capital adjustments at closing. Both power plants currently provide power and capacity to PSCo under PPAs, which materially expire in 2013 and 2014. Under the agreement, Riverside Energy Center, LLC and Calpine Development Holdings, Inc. will use commercially reasonable efforts to cause Blue Spruce and Rocky Mountain to continue to operate and maintain the power plants in the ordinary course of business through the closing of the transaction. As of the filing of this Report, we have received all of the required approvals and we expect the sale to close in December 2010. We believe the proceeds from the sales of Blue Spruce and Rocky Mountain will enable us to continue to strengthen our balance sheet. The transaction is expected to remove the restrictions on approximately $86 million in restricted cash at closing. We expect to use the sales proceeds received and the approximately $86 million in restricted cash described above to repay project debt of approximately $418 million, for general corporate purposes and to focus more resources on our core markets. We expect to record a pre-tax gain of approximately $220 million upon closing this transaction. See also Note 2 of the Notes to Consolidated Condensed Financial Statements for additional details of the Blue Spruce and Rocky Mountain amounts reported as assets and liabilities held for sale and discontinued operations.

Freestone — On October 27, 2010, we entered into an asset purchase and sale agreement to sell a 25% undivided interest in the assets of our Freestone power plant for approximately $215 million in cash at closing and will receive annual operating and energy management fees going forward. The sale is expected to close in the fourth quarter of 2010, but no later than the first quarter of 2011 and we will continue to operate Freestone after the sale.

Pittsburg Power Plant and Watsonville (Monterey) Cogeneration Power Plant — We no longer operate these power plants which had an aggregate capacity of 93 MW. In March 2010, we transferred ownership of our Pittsburg power plant to a third party pursuant to a transfer agreement executed in August 2007. The operating lease associated with our Watsonville (Monterey) cogeneration power plant expired in May 2010 at which time we began dismantling the power plant in accordance with the lease agreement.

55

Construction, Project Development, Upgrades and Growth Initiatives

We continue to review development opportunities to determine whether future actions are appropriate. We may pursue new opportunities that arise, particularly if power contracts and financing are available and attractive returns are expected. 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 and development, 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 in Peach Bottom Township, Pennsylvania, formerly known as the Delta Project, as part of the Conectiv Acquisition. The York Energy Center remains on budget and on schedule. All permits have been received and commercial operations are expected to commence in June 2011. The York Energy Center will sell power under a six-year PPA with a third party. We do not expect to require additional financing to complete construction as NDH received a cash contribution from Calpine Corporation to fund the remaining expected capital expenditures of approximately $110 million.

Russell City Energy Center — Russell City Energy Center, remains under advanced stages of development. The Russell City Energy Center is currently contracted to deliver its full output to PG&E under a PPA, which was executed in December 2006 and approved by the CPUC in January 2007. The PPA was amended in 2008 and again on April 9, 2010, to extend the expected commercial operations date to June 2013 as a result of delays in obtaining certain permits. We are in possession of all material permits. Completion of the Russell City Energy Center is dependent upon completion of certain administrative appeals processes associated with our air permit. We do not expect the costs to complete the Russell City Energy Center to be material to our financial position or results of operations on a consolidated basis. Upon completion, this project would bring on line approximately 372 MW of net interest baseload capacity (402 MW with peaking capacity) representing our 65% share.

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. In addition to the increase in capacity, the upgrade will 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 are now effective. We are amending our California Energy Commission license and emission limits and are in the process of procuring equipment and selecting the engineering, procurement and construction contractors.

Geysers Assets Expansion — We continue to look to expand our production from our Geysers Assets. In the fourth quarter of 2009, we started drilling additional wells and have made expenditures of approximately $55 million during the first nine months of 2010 related to these expansion efforts. We have completed drilling 13 planned test wells, establishing capacity for approximately 42 MW of additional steam generation. Reservoir and economic modeling of the results obtained from the drilling is currently being performed. We expect to make a determination in the first quarter of 2011 as to whether the new wells will produce enough additional steam to warrant the construction of additional geothermal power plants at our Geysers Assets. Additionally, we are currently seeking to take advantage of certain incentives under the American Recovery and Reinvestment Act of 2009, also referred to as the Stimulus Bill. We expect that new geothermal power plant development will qualify for at least a 10% cash grant.

Turbine Upgrades — We continue to move forward with our turbine upgrade program and have entered an agreement to upgrade select GE and Siemens turbines. As of September 30, 2010, we have completed the upgrade of four Siemens turbines and have agreed to upgrade approximately 14 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 245 MW. These upgrades began in the fourth quarter of 2009 and are scheduled through 2014. The initial testing of the upgraded turbines has indicated additional capacity and improvements in operating Heat Rates falling in line with expectations.

56

Customer-Oriented Origination Business

We continue to focus on our customer origination function.

• We received approval of our PPA contracts totaling 1,250 MW with SDG&E and PG&E from the CPUC.

• We have entered into a new seven-year PPA with Xcel Energy to provide 200 MW of power generated by our Oneta Energy Center to Southwestern Public Service Company, a subsidiary of Xcel Energy.

• We have entered into a PPA with Bonneville Power Administration to provide up to 75 MW of wind power generation flexibility.

NOLs

We have significant NOLs that will provide future tax deductions when we generate sufficient taxable income during the applicable carryover periods. Our federal and state income tax reporting group is comprised primarily of two groups, CCFC and its subsidiaries, which we refer to as the CCFC group and Calpine Corporation and its subsidiaries other than CCFC, which we refer to as the Calpine group. As of December 31, 2009, our consolidated federal NOLs totaled approximately $7.5 billion, which consisted of approximately $7.0 billion from the Calpine group and approximately $513 million from the CCFC group. The Calpine group and the CCFC group adjusted their NOLs for prior periods through December 31, 2009, increasing it by approximately $150 million. These adjustments consisted of $49 million to reduce the NOL for excluded cancellation of debt income, a $230 million increase in prior period NOLs for development costs and construction in progress relating to abandoned projects, a $33 million decrease for return to provision adjustments and other increases of $2 million; however, because of the Calpine group's valuation allowance on its NOL, there is no impact on our income tax expense.

Cash Flow Activities

The following table summarizes our cash flow activities for the nine months ended September 30, 2010 and 2009 (in millions):

	2010			2009
Beginning cash and cash equivalents	$	989		$	1,657
Net cash provided by (used in):
Operating activities		783			537
Investing activities		(1,585	)		(164	)
Financing activities		727			(1,117	)
Net decrease in cash and cash equivalents		(75	)		(744	)
Ending cash and cash equivalents	$	914		$	913

Net Cash Provided By Operating Activities

Cash flows provided by operating activities for the nine months ended September 30, 2010, resulted in net inflows of $783 million compared to $537 million for the same period in 2009. The change in cash flows from operating activities is primarily due to:

• Increase in gross profit — Gross profit, after excluding non-cash items such as unrealized gains and losses in mark-to-market activity, depreciation expense, and loss on asset disposals, increased by $62 million in 2010 resulting primarily from the Conectiv Acquisition and increased realized gains on financial hedges, partially offset by lower Commodity Margins in our Texas and West segments.

• Decreases in working capital — Working capital employed decreased by approximately $172 million during the period after adjusting for debt related balances which did not impact cash provided by operating activities. The decrease was primarily due to reductions in margin deposits and certain derivative activity.

• Decreases in interest paid — Cash paid for interest decreased by $75 million to $488 million for the nine months ended September 30, 2010, as compared to $563 million for the same period in 2009, primarily due to the refinancing of portions of our First Lien Credit Facility term loans, CCFC and other project financing.

57

This was partially offset by:

• Increase in cash taxes — Cash paid for taxes (net) increased by $26 million primarily due to Canadian tax refunds received in the third quarter of 2009 with no similar activity in the nine months ended September 30, 2010.

Net Cash Used In Investing Activities

Cash flows used in investing activities for the nine months ended September 30, 2010, were $1.6 billion compared to cash flows used in investing activities of $164 million for the nine months ended September 30, 2009. The change was primarily due to the Conectiv Acquisition for approximately $1.64 billion on July 1, 2010. Additionally, capital expenditures increased by $51 million in the nine months ended September 30, 2010, partially offset by $228 million in cash provided through a reduction in restricted cash mainly due to the maturity of the PCF project financing in the second quarter of 2010.

Net Cash Provided By (Used In) Financing Activities

Cash flows provided by financing activities for the nine months ended September 30, 2010, resulted in inflows of $727 million, a $1.8 billion increase, compared to outflows of $1.1 billion for the same period in 2009. The increase is primarily due to net proceeds of $1.3 billion from the NDH Project Debt combined with a $0.7 billion payment on the First Lien Credit Facility revolver in 2009 which did not recur in 2010, partially offset by increased repayments of project and other debt.

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: Rocky Mountain Energy Center, LLC, Riverside Energy Center, LLC, Calpine Riverside Holdings, LLC, PCF, PCF III, 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

We actively seek to manage the commodity risks of our portfolio, utilizing multiple strategies of buying and selling power, natural gas or Heat Rate transactions to manage our spark spread.

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 also use interest rate swaps to manage the interest rate risk of our variable rate debt. 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.

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. 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

58

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 generation and natural gas portfolio mostly through power and natural gas forward physical and financial transactions for much of 2010 and hedged a material portion of our portfolio in a similar manner in 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. As of September 30, 2010, the maximum length of our PPAs extends 22 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 16 years, respectively. Assuming constant September 30, 2010 power and natural gas prices and interest rates, we estimate that pre-tax net gains of $33 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 to our net income (positive or negative) will be for the next 12 months. As of September 30, 2010, we had approximately $130 million to $140 million in unrealized losses recorded in AOCI for interest rate swaps that were hedging the variable interest rates on approximately $2.0 billion of First Lien Credit Facility term loans, which were repaid with the proceeds received from the issuance of the 2021 First Lien Notes on October 22, 2010 (see Note 6 of the Notes to Consolidated Condensed Financial Statements for further discussion of our issuance of the 2021 First Lien Notes). These interest rate swaps will no longer qualify as cash flow hedges and the corresponding amounts will be reclassified into our net income during the fourth quarter of 2010 as additional interest expense. Additionally, prospective changes in the fair value of these interest rate swaps will also be recorded in our net income as interest expense.

Derivatives — We enter into a variety of 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 as well as interest rate swaps. Derivative contracts are measured at their fair value and recorded as either assets or liabilities unless they qualify for, and we elect, the normal purchase normal sale exemption. All changes in the fair value of contracts accounted for as derivatives are recognized currently in earnings (as a component of our operating revenues, fuel and purchased energy expense, or interest expense) unless specific hedge criteria are met. The hedge criteria require us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting. The actual amounts that will ultimately be settled will likely vary based on changes in natural gas prices and power prices as well as changes in interest rates. Such variances could be material.

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 and MWh), changing commodity market prices, principally for power and natural gas, liquidity risk, counterparty credit risk and changes in interest rates. Volatility in both natural gas and power prices, as well as increased hedging and optimization activities, impacts the presentation of our derivative assets and liabilities. Our derivative assets have increased to $1.6 billion at September 30, 2010, compared to $1.3 billion at December 31, 2009, while our derivative liabilities have increased to $1.7 billion at September 30, 2010, compared to $1.6 billion at December 31, 2009. As of September 30, 2010, 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 7 of the Notes to Consolidated Condensed Financial Statements for further information related to determining the fair value of our derivatives, including our level 3 derivative assets and liabilities. There is a substantial amount of volatility inherent in accounting for the fair value of these derivatives, which may affect our results. The change in fair value of our outstanding commodity and interest rate derivative instruments from January 1, 2010, through September 30, 2010, is summarized in the table below (in millions):

	Interest Rate			Commodity
	Swaps			Instruments		Total
Fair value of contracts outstanding at January 1, 2010	$	(319	)	$	8	$	(311	)
Losses recognized or otherwise settled during the period(1)(2)		167			75		242
Fair value attributable to new contracts		(1	)		45		44
Changes in fair value attributable to price movements		(310	)		222		(88	)
Change in fair value attributable to nonperformance risk		6			—		6
Fair value of contracts outstanding at September 30, 2010(3)	$	(457	)	$	350	$	(107	)

__________

59

(1) Interest rate settlements consist of recognized losses from interest rate cash flow hedges of $156 million and recognized losses from undesignated interest rate swaps of $11 million (represents a portion of interest expense as reported on our Consolidated Condensed Statements of Operations).

(2) Losses on settlement of commodity contracts not designated as hedging instruments of $2 million (represents a portion of operating revenues and fuel and purchased energy expense as reported on our Consolidated Condensed Statements of Operations) and $73 million related to recognition of losses from cash flow hedges, previously reflected in OCI, offset by other changes in derivative assets and liabilities not reflected in OCI or net income (loss).

(3) Net commodity and interest rate derivative assets and liabilities reported in Notes 7 and 8 of the Notes to Consolidated Condensed Financial Statements.

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

The following tables detail the components of our total mark-to-market activity for both the net realized gain (loss) and the net unrealized gain (loss) recognized from our derivative instruments not designated as hedging instruments and where these components were recorded on our Consolidated Condensed Statements of Operations for the periods indicated (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Realized gain (loss)
Interest rate swaps	$	(14	)	$	(3	)	$	(26	)	$	(12	)
Commodity instruments		41			1			93			(13	)
Total realized gain (loss)	$	27		$	(2	)	$	67		$	(25	)
Unrealized gain (loss) (1)
Interest rate swaps	$	(96	)	$	1		$	(115	)	$	5
Commodity instruments		131			43			212			60
Total unrealized gain	$	35		$	44		$	97		$	65
Total mark-to-market activity	$	62		$	42		$	164		$	40

__________

(1) Changes in unrealized gains and losses include hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Realized and unrealized gain (loss)
Power contracts included in operating revenues	$	22		$	17		$	34		$	8
Natural gas contracts included in fuel and purchased energy expense		150			27			271			39
Interest rate swaps included in interest expense		(110	)		(2	)		(141	)		(7	)
Total mark-to-market activity	$	62		$	42		$	164		$	40

Our change in AOCI from an accumulated loss of $266 million at December 31, 2009, to an accumulated loss of $166 million at September 30, 2010, was primarily driven by the effect of a decrease in power prices and resulting gains on short power positions in cash flow hedge relationships, reclassification of an unrealized loss from AOCI to our net income as interest expense of $70 million associated with interest rate swap hedges for which the originally hedged forecasted transaction became probable of not occurring due to repayment of the debt it was hedging from the proceeds from the issuance of the 2020 First Lien Notes, and a decrease in interest rates.

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.

60

The net fair value of outstanding derivative commodity instruments at September 30, 2010, based on price source and the period during which the instruments will mature, are summarized in the table below (in millions):

Fair Value Source	2010				2011-2012		2013-2014		After 2014		Total
Prices actively quoted	$	(63	)	$	112	$	—		$	—	$	49
Prices provided by other external sources		138			119		(1	)		—		256
Prices based on models and other valuation methods		7			31		7			—		45
Total fair value	$	82		$	262	$	6		$	—	$	350

We measure the 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 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 nine months ended September 30, 2010 and 2009, as well as our VAR at September 30, 2010 and 2009 (in millions):

	2010		2009
Three months ended September 30:
High	$	30	$	50
Low	$	20	$	36
Average	$	25	$	44
Nine months ended September 30:
High	$	58	$	59
Low	$	20	$	36
Average	$	30	$	49
As of September 30	$	28	$	45

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 9 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.

61

We believe that our credit policies 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 September 30, 2010, and the period during which the instruments will mature are summarized in the table below (in millions):

Credit Quality
(Based on Standard & Poor’s Ratings as of September 30, 2010)	2010			2011-2012			2013-2014		After 2014		Total
Investment grade	$	82	$	265		$	7		$	—	$	354
Non-investment grade		—		(1	)		—			—		(1	)
No external ratings		—		(2	)		(1	)		—		(3	)
Total fair value	$	82	$	262		$	6		$	—	$	350

Interest Rate Risk — We are exposed to interest rate risk related to our variable rate debt. Interest rate risk represents the potential loss in earnings arising from adverse changes in market interest rates. Our variable rate financings are indexed to base rates, generally LIBOR. Significant LIBOR increases could have an adverse impact on our future interest expense.

Our fixed-rate debt instruments do not expose us to the risk of loss in earnings due to changes in market interest rates. In general, such a change in fair value would impact earnings and cash flows only if we were to reacquire all or a portion of the fixed rate debt in the open market prior to their maturity.

The following table summarizes the contract terms as well as the fair values of our financial instruments exposed to interest rate risk as of September 30, 2010. All outstanding balances and fair market values are shown gross of applicable premium or discount, if any (in millions):

																					Fair Value
																					September 30,
	2010			2011			2012			2013			2014			Thereafter			Total		2010
Debt by Maturity Date:
Fixed Rate	$	15		$	71		$	21		$	24		$	21		$	3,807		$	3,959	$	4,092
Average Interest Rate		2.8	%		6.9	%		9.6	%		9.6	%		9.4	%		7.7	%
Variable Rate	$	19		$	399		$	177		$	93		$	3,139		$	2,241		$	6,068	$	5,958
Average Interest Rate(1)		3.6	%		4.6	%		3.8	%		3.7	%		3.8	%		6.3	%

__________

(1) Projection based upon anticipated LIBOR rates.

Currently, we use interest rate swaps to adjust the mix between fixed and variable rate debt as a hedge of our interest rate risk. We do not use interest rate derivative instruments for trading purposes. As of September 30, 2010, we have $6.6 billion and $5.8 billion of variable to fixed interest rate swaps through December 31, 2010 and 2012, respectively, hedging our variable rate debt in order to manage our risk to significant increases in LIBOR. To the extent eligible, our interest rate swaps have been designed as cash flow hedges, and changes in fair value are recorded in OCI to the extent they are effective. During the three months ended September 30, 2010, an additional $70 million in unrealized losses were reclassified out of AOCI for interest rate swaps that no longer qualified as cash flow hedges as the variable rate debt it was hedging was repaid. The corresponding amounts were reclassified into our net income as additional interest expense. Additionally, we expect an additional $130 million to $140 million in unrealized losses recorded in AOCI as of September 30, 2010, will be reclassified out of AOCI and into our net income as interest expense during the fourth quarter of 2010. These interest rate swaps were hedging the variable interest rates on approximately $2.0 billion of First Lien Credit Facility term loans that were repaid with the proceeds received from the issuance of the 2021 First Lien Notes on October 22, 2010, and will no longer qualify for cash flow hedges.

62

New Accounting Standards and Disclosure Requirements

See Note 1 and Note 4 of the Notes to Consolidated Condensed Financial Statements for a discussion of new accounting standards and disclosure requirements.

63

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 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 to provide reasonable assurance 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 during the third quarter of 2010 that materially affected, or are reasonably likely to materially affect our internal control over financial reporting.

64

PART II — OTHER INFORMATION

Item 1.  Legal Proceedings

See Note 14 of the Notes to Consolidated Condensed Financial Statements for a description of our legal proceedings.

Item 1A.  Risk Factors

Various risk factors could have a negative effect on our business, financial position, cash flows and results of operations. These include the risk factors set forth in “Item 1A. Risk Factors” in our 2009 Form 10-K. There have been no significant changes to our risk factors from those disclosed in our 2009 Form 10-K through the filing of this Report except as noted below:

Our planned sale of Blue Spruce and Rocky Mountain may not close as planned, which could negatively impact our future business and financial results.

Our planned asset divesture to sell our ownership interests in Blue Spruce and Rocky Mountain may be delayed or may not close at all. The closing of this transaction is conditioned upon our counterparties being able to fund the approximate $739 million purchase price. The failure or delay of the purchaser to obtain the necessary funding could result in the planned closing of this transaction being delayed or not occurring at all. This could result in additional required capital or the failure to integrate the anticipated benefits from this transaction into our business and strategy as planned.

Future PJM capacity revenues expected from the Conectiv Acquisition may be diminished or may not occur at expected levels.

PJM is responsible for ensuring that there is sufficient generating capacity (plus an adequate reserve margin) to meet the load requirements within its transmission control area and requires retail sellers of electricity in the PJM region to maintain capacity either from ownership or through bilateral contracts for the purchase of capacity credits in auctions administered by PJM from wholesale generators. The purchase of the capacity credits in the PJM region is conducted through a forward capacity auction procedure known as the Reliability Pricing Model (“RPM”). Under the RPM, each auction covers capacity to be supplied over consecutive 12-month periods. The most recent auction covered the period from June 2013 through May 2014 and was completed in May 2010, with auction prices clearing at higher prices relative to previous years. The next annual auction, for the June 2014 to May 2015 period, is scheduled to be completed in May 2011.

The power generation assets we acquired from Conectiv are located in the transmission control area administered by PJM, and a significant source of revenue from these power generation assets is expected to come from the sale of capacity. If future capacity auctions occur below anticipated price levels, if there are adverse changes in the RPM, or if the power generation assets we acquired from Conectiv fail to meet certain reliability levels, the amount of capacity we may be able to sell in future capacity auctions, and hence the amount of capacity revenues we would realize in the applicable year, may be diminished.

In addition to participating in the PJM auctions, we may elect to participate in the forward capacity market as both sellers and buyers, subject to our risk management policy, and accordingly, prices realized in the PJM capacity auctions may not be indicative of Commodity Margin that we earn in respect of our capacity purchases and sales during a given period.

65

 Item 6.  Exhibits

The following exhibits are filed herewith unless otherwise indicated:

EXHIBIT INDEX

Exhibit
Number	Description
4.1	Indenture, dated October 22, 2010, among Calpine Corporation, the guarantors party thereto and Wilmington Trust Company, as trustee, including the form of the Notes (incorporated by reference to Exhibit 4.1 to Calpine’s Current Report on Form 8-K filed with the Securities and Exchange Commission on October 22, 2010).
10.1	Non-Qualified Stock Option Agreement between the Company and Jack Fusco, dated August 11, 2010 (incorporated by reference to Exhibit 10.1 to Calpine’s Current Report on Form 8-K filed with the Securities and Exchange Commission on August 17, 2010).
10.2	Non-Qualified Stock Option Agreement between the Company and John B. (Thad) Hill, dated August 11, 2010 (incorporated by reference to Exhibit 10.2 to Calpine’s Current Report on Form 8-K filed with the Securities and Exchange Commission on August 17, 2010).
10.3	Non-Qualified Stock Option Agreement between the Company and W. Thaddeus Miller, dated August 11, 2010 (incorporated by reference to Exhibit 10.3 to Calpine’s Current Report on Form 8-K filed with the Securities and Exchange Commission on August 17, 2010).
10.4	The Amended and Restated Calpine Corporation 2008 Equity Incentive Plan (incorporated by reference to Exhibit 99.1 to Calpine’s Current Report on Form 8-K filed with the Securities and Exchange Commission on August 17, 2010).
10.5	Credit Agreement, dated as of January 31, 2008, among the Company, as borrower, Goldman Sachs Credit Partners L.P., Credit Suisse, Deutsche Bank Securities Inc. and Morgan Stanley Senior Funding, Inc., as co-documentation agents and as co-syndication agents, General Electric Capital Corporation, as sub-agent for the revolving lenders, Goldman Sachs Credit Partners L.P., as administrative agent and as collateral agent and each of the financial institutions from time to time party thereto.* †
10.6	Credit Agreement dated as of June 8, 2010, among New Development Holdings, LLC, as Borrower, The Lenders Party Hereto and Credit Suisse AG, as Administrative Agent and Collateral 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 as Syndication Agent; Credit Suisse AG, Citibank, N.A., and Deutsche Bank Trust Company Americas as Co-Documentation Agents.*
31.1	Certification of the Chief Executive Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*
31.2	Certification of the Chief Financial Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*
32.1	Certification of Chief Executive Officer and 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	The following unaudited financial statements from the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, filed with the Securities and Exchange Commission, formatted in XBRL (eXtensible Business Reporting Language): (i) the Condensed Consolidated Statements of Operations, (ii) the Condensed Consolidated Balance Sheets, (iii) the Condensed Consolidated Statements of Cash Flows, and (iv) Notes to Condensed Consolidated Financial Statements, tagged as blocks of text.*

__________

* Filed herewith.

† Portions of this exhibit have been omitted pursuant to a request for confidential treatment under Rule 24b-2 under the Securities Exchange Act of 1934.

66

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:  October 28, 2010

67

EXHIBIT INDEX

Exhibit
Number	Description
4.1	Indenture, dated October 22, 2010, among Calpine Corporation, the guarantors party thereto and Wilmington Trust Company, as trustee, including the form of the Notes (incorporated by reference to Exhibit 4.1 to Calpine’s Current Report on Form 8-K filed with the Securities and Exchange Commission on October 22, 2010).
10.1	Non-Qualified Stock Option Agreement between the Company and Jack Fusco, dated August 11, 2010 (incorporated by reference to Exhibit 10.1 to Calpine’s Current Report on Form 8-K filed with the Securities and Exchange Commission on August 17, 2010).
10.2	Non-Qualified Stock Option Agreement between the Company and John B. (Thad) Hill, dated August 11, 2010 (incorporated by reference to Exhibit 10.2 to Calpine’s Current Report on Form 8-K filed with the Securities and Exchange Commission on August 17, 2010).
10.3	Non-Qualified Stock Option Agreement between the Company and W. Thaddeus Miller, dated August 11, 2010 (incorporated by reference to Exhibit 10.3 to Calpine’s Current Report on Form 8-K filed with the Securities and Exchange Commission on August 17, 2010).
10.4	The Amended and Restated Calpine Corporation 2008 Equity Incentive Plan (incorporated by reference to Exhibit 99.1 to Calpine’s Current Report on Form 8-K filed with the Securities and Exchange Commission on August 17, 2010).
10.5	Credit Agreement, dated as of January 31, 2008, among the Company, as borrower, Goldman Sachs Credit Partners L.P., Credit Suisse, Deutsche Bank Securities Inc. and Morgan Stanley Senior Funding, Inc., as co-documentation agents and as co-syndication agents, General Electric Capital Corporation, as sub-agent for the revolving lenders, Goldman Sachs Credit Partners L.P., as administrative agent and as collateral agent and each of the financial institutions from time to time party thereto.*†
10.6	Credit Agreement dated as of June 8, 2010, among New Development Holdings, LLC, as Borrower, The Lenders Party Hereto and Credit Suisse AG, as Administrative Agent and Collateral 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 as Syndication Agent; Credit Suisse AG, Citibank, N.A., and Deutsche Bank Trust Company Americas as Co-Documentation Agents.*
31.1	Certification of the Chief Executive Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*
31.2	Certification of the Chief Financial Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*
32.1	Certification of Chief Executive Officer and 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	The following unaudited financial statements from the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, filed with the Securities and Exchange Commission, formatted in XBRL (eXtensible Business Reporting Language): (i) the Condensed Consolidated Statements of Operations, (ii) the Condensed Consolidated Balance Sheets, (iii) the Condensed Consolidated Statements of Cash Flows, and (iv) Notes to Condensed Consolidated Financial Statements, tagged as blocks of text.*

__________

* Filed herewith.

† Portions of this exhibit have been omitted pursuant to a request for confidential treatment under Rule 24b-2 under the Securities Exchange Act of 1934.

68