Exhibit 99.1

As further discussed in Note 6 of the Notes to Consolidated Financial Statements, we entered into an agreement with PSCo, to sell 100% of our ownership interests in Blue Spruce and Rocky Mountain on April 2, 2010. Accordingly, our consolidated financial information for the three years ended December 31, 2009, 2008 and 2007 have been recast to present the results of operations of Blue Spruce and Rocky Mountain as discontinued operations. Information in our 2009 Form 10-K is generally stated as of December 31, 2009 and this filing does not reflect any subsequent information or events, other than to report the results of operations for Blue Spruce and Rocky Mountain as discontinued operations. Information contained in this Exhibit 99.1 should be read in conjunction with our 2009 Form 10-K and our filings made with the SEC subsequent to the filing of our 2009 Form 10-K.

.

DEFINITIONS

As used in this Report, the following abbreviations and terms have the meanings as listed below. Additionally, the terms “Calpine,” “we,” “us” and “our” refer to Calpine Corporation and its consolidated subsidiaries, unless the context clearly indicates otherwise. For clarification, for the period from December 20, 2005, through February 7, 2008, such terms do not include the Canadian Debtors and other foreign subsidiaries that were deconsolidated as of the Petition Date. The term “Calpine Corporation” refers only to Calpine Corporation and not to any of its subsidiaries. Unless and as otherwise stated, any references in this Report to any agreement means such agreement and all schedules, exhibits and attachments in each case as amended, restated, supplemented or otherwise modified to the date of filing this Report.

ABBREVIATION	DEFINITION
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
Acadia PP	Acadia Power Partners, LLC
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 non-cash realized gains on derivatives and 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) claim settlement income, (h) stock-based compensation expense (income), (i) non-cash gains or losses on sales or dispositions of assets, (j) non-cash gains and losses from intercompany foreign currency translations, (k) any gains or losses on the repurchase or extinguishment of debt (l) Adjusted EBITDA from our discontinued operations and (m) any other extraordinary, unusual or non-recurring items
AOCI	Accumulated Other Comprehensive Income
Aries Power Plant	MEP Pleasant Hill, LLC
Auburndale	Auburndale Holdings, LLC
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 during the period by (ii) the total hours in the period
Bankruptcy Code	U.S. Bankruptcy Code
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
Btu	British thermal unit(s), a measure of heat content
CalGen	Calpine Generating Company, LLC
CalGen Secured Debt	Collectively the: CalGen First Lien Debt comprised of (a) $235,000,000 First Priority Secured Floating Rate Notes Due 2009, (b) $600,000,000 First Priority Secured Institutional Term Loans Due 2009, and (c) $200,000,000 First Priority Revolving Loans issued on or about March 23, 2004; CalGen Second Lien Debt comprised of (a) $640,000,000 Second Priority Secured Floating Rate Notes Due 2010, and (b) $100,000,000 Second Priority Secured Institutional Term Loans Due 2010; and CalGen Third Lien Debt. In each case, issued by CalGen or CalGen and CalGen Finance Corp. and repaid on March 29, 2007
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 Debtors	The U.S. Debtors and the Canadian Debtors

ABBREVIATION	DEFINITION
Calpine Equity Incentive Plans	Collectively, the MEIP and the DEIP, which provide for grants of equity awards to Calpine employees and non-employee members of Calpine’s Board of Directors
Canadian Court	The Court of Queen’s Bench of Alberta, Judicial District of Calgary
Canadian Debtors	The subsidiaries and affiliates of Calpine Corporation that were granted creditor protection under the CCAA in the Canadian Court
Canadian Effective Date	February 8, 2008, the date on which the Canadian Court ordered and declared that the Canadian Debtors’ proceedings under the CCAA were terminated
Canadian Settlement Agreement	Settlement Agreement dated as of July 24, 2007, by and between Calpine Corporation, on behalf of itself and its U.S. subsidiaries, Calpine Canada Energy Ltd., Calpine Canada Power Ltd., Calpine Canada Energy Finance ULC, Calpine Energy Services Canada Ltd., Calpine Canada Resources Company, Calpine Canada Power Services Ltd., Calpine Canada Energy Finance II ULC, Calpine Natural Gas Services Limited, 3094479 Nova Scotia Company, Calpine Energy Services Canada Partnership, Calpine Canada Natural Gas Partnership, Calpine Canadian Saltend Limited Partnership and HSBC Bank USA, National Association, as successor indenture trustee
Cap-and-trade	A government imposed GHG emissions reduction program that would place a cap on the amount of GHG emissions that can be emitted from certain sources, such as power plants. In its simplest form, the cap amount is set as a reduction from the total emissions during a base year and for each year over a period of years the cap amount would be reduced to achieve the targeted overall reduction by the end of the period. Allowances or credits for emissions in an amount equal to the cap would be issued or auctioned to companies with facilities, permitting them to emit up to a certain amount of GHG during each applicable period. After allowances have been distributed or auctioned, they can be transferred, or traded
Cash Collateral Order	Second Amended Final Order of the U.S. Bankruptcy Court Authorizing Use of Cash Collateral and Granting Adequate Protection, dated February 24, 2006 as modified by orders of the U.S. Bankruptcy Court dated June 21, 2006, July 12, 2006, October 25, 2006, November 15, 2006, December 20, 2006, December 28, 2006, January 17, 2007, and March 1, 2007
CCAA	Companies’ Creditors Arrangement Act (Canada)
CCFC	Calpine Construction Finance Company, L.P.
CCFC Finance	CCFC Finance Corp.
CCFC Guarantors	Hermiston Power LLC and Brazos Valley Energy LLC, wholly owned subsidiaries of CCFC
CCFC New 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
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, comprising $365 million aggregate principal amount issued August 14, 2003, and $50 million aggregate principal amount issued September 25, 2003, and redeemed on June 18, 2009
CCFC Refinancing	The issuance of the CCFC New Notes on May 19, 2009, pursuant to Rule 144A and Regulation S under the Securities Act, and the related transactions including repayment of the CCFC Term Loans and the redemption of the CCFC Old Notes and CCFCP Preferred Shares
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
CDWR	California Department of Water Resources
CES	Calpine Energy Services, L.P.
Chapter 11	Chapter 11 of the Bankruptcy Code
CO2	Carbon dioxide

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ABBREVIATION	DEFINITION
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
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, RGGI compliance 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 subsidiaries
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 Bankruptcy Code,” entered December 19, 2007, confirming the Plan of Reorganization pursuant to section 1129 of the Bankruptcy Code
Convertible Senior Notes	Collectively, Calpine Corporation’s 4% Contingent Convertible Notes Due 2006, Contingent Convertible Notes Due 2014, 7 3/4% Contingent Convertible Notes Due 2015 and 4 3/4% Contingent Convertible Senior Notes Due 2023, all of which were terminated and settled with reorganized Calpine Corporation common stock on the Effective Date
CPUC	California Public Utilities Commission
Creed	Creed Energy Center, LLC
Deer Park	Deer Park Energy Center Limited Partnership
DEIP	Calpine Corporation 2008 Director Incentive Plan, which provides for grants of equity awards to non-employee members of Calpine’s Board of Directors
DIP	Debtor-in-possession
DIP Facility	The Revolving Credit, Term Loan and Guarantee Agreement, dated as of March 29, 2007, among Calpine Corporation, as borrower, certain of Calpine Corporation’s subsidiaries, as guarantors, the lenders party thereto, and Credit Suisse, as administrative agent and collateral agent, and the other agents, arrangers and bookrunners named therein
Disclosure Statement	Disclosure Statement for the U.S. Debtors’ Joint Plan of Reorganization Pursuant to Chapter 11 of the Bankruptcy Code filed by the U.S. Debtors with the U.S. Bankruptcy Court on June 20, 2007, as amended, modified or supplemented through the filing of our 2009 Form 10-K pursuant to the Plan of Reorganization
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
Exchange Act	U.S. Securities Exchange Act of 1934, as amended
FDIC	U.S. Federal Deposit Insurance Corporation

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ABBREVIATION	DEFINITION
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 Facilities	Together, our First Lien Credit Facility and $300 million Bridge Loan Agreement dated January 31, 2008 repaid on March 6, 2008
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
First Priority Notes	9 5/8% First Priority Senior Secured Notes Due 2014, repaid in May and June 2006
Fremont	Fremont Energy Center, LLC
GAAP	Generally accepted accounting principles
GE	General Electric International, Inc.
GEC	Collectively, Gilroy Energy Center, LLC, Creed and Goose Haven
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	Greenhouse gas(es), primarily CO2 , and including methane (CH4 ), nitrous oxide (N2 O), sulfur hexafluoride (SF6 ), hydrofluorocarbons (HFCs) and perfluorocarbons (PFCs)
Gilroy	Calpine Gilroy Cogen, L.P.
Goose Haven	Goose Haven Energy Center, LLC
Greenfield LP	Greenfield Energy Centre LP
Heat Rate(s)	A measure of the amount of fuel required to produce a unit of power
Hillabee	Hillabee Energy Center, LLC
IRC	Internal Revenue Code
ISO	Independent System Operator(s)
ISO NE	ISO New England
Knock-in Facility	Letter of Credit Facility Agreement, dated as of June 25, 2008, among Calpine Corporation as borrower and Morgan Stanley Capital Services Inc., as issuing bank which matured on June 30, 2009
KWh	Kilowatt hour(s), a measure of power produced
LIBOR	London Inter-Bank Offered Rate
LSTC	Liabilities subject to compromise
LTSA(s)	Long-Term Service Agreement(s)
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
MEIP	Calpine Corporation 2008 Equity Incentive Plan, which provides for grants of equity awards to Calpine employees and non-employee members of Calpine’s Board of Directors
Metcalf	Metcalf Energy Center, LLC
MMBtu	Million Btu
MW	Megawatt(s), a measure of plant capacity
MWh	Megawatt hour(s), a measure of power produced
NOL(s)	Net operating loss(es)
NYISO	New York ISO
NYMEX	New York Mercantile Exchange

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ABBREVIATION	DEFINITION
NYSE	New York Stock Exchange
OCI	Other Comprehensive Income
OMEC	Otay Mesa Energy Center, LLC
Original DIP Facility	The Revolving Credit, Term Loan and Guarantee Agreement, dated as of December 22, 2005, as amended on January 26, 2006, and as amended and restated by the Amended and Restated Revolving Credit, Term Loan and Guarantee Agreement, dated as of February 23, 2006, among Calpine Corporation, as borrower, the guarantors party thereto, the lenders from time to time party thereto, Deutsche Bank Trust Company Americas, as administrative agent for the First Priority Lenders, General Electric Capital Corporation, as Sub-Agent for the Revolving Lenders, Credit Suisse, as administrative agent for the Second Priority Term Lenders and the other agents named therein, refinanced in March 2007 with the DIP Facility
OTC	Over-the-Counter
Panda	Panda Energy International, Inc., and related party PLC II, LLC
PCF	Power Contract Financing, L.L.C.
PCF III	Power Contract Financing III, LLC
Petition Date	December 20, 2005
PG&E	Pacific Gas & Electric Company
PJM	Pennsylvania-New Jersey-Maryland Interconnection
Plan of Reorganization	Sixth Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the Bankruptcy Code filed by the U.S. Debtors with the U.S. Bankruptcy Court on December 19, 2007, as amended, modified or supplemented through the filing of our 2009 Form 10-K
Pomifer	Pomifer Power Funding, LLC, a subsidiary of Arclight Energy Partners Fund I, L.P.
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
PSCo	Public Service Company of Colorado, a wholly owned subsidiary of Xcel, Inc.
PSM	Power Systems Manufacturing, LLC
REC(s)	Renewable energy credit(s)
Reserve margin(s)	The measure of how much the total generating capacity installed in a region exceeds the peak demand for power in that region
RGGI	Regional Greenhouse Gas Initiative
RMR Contract(s)	Reliability Must Run contract(s)
RockGen	RockGen Energy LLC
RockGen Owner Lessors	Collectively, RockGen OL-1, LLC; RockGen OL-2, LLC; RockGen OL-3, LLC and RockGen OL-4, LLC
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
Rosetta	Rosetta Resources Inc.
SDG&E	San Diego Gas & Electric Company
SEC	U.S. Securities and Exchange Commission
Second Circuit	U.S. Court of Appeals for the Second Circuit
Second Priority Debt	Collectively, Calpine Corporation’s Second Priority Senior Secured Floating Rate Notes Due 2007, 8 1/2% Second Priority Senior Secured Notes Due 2010, 8 3/4% Second Priority Senior Secured Notes Due 2013 and 9 7/8% Second Priority Senior Secured Notes Due 2011 and Second Priority Senior Secured Term Loans Due 2007; all of which were repaid on the Effective Date
Securities Act	U.S. Securities Act of 1933, as amended
Spark spread(s)	The difference between the sales price of power per MWh and the cost of fuel to produce it

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ABBREVIATION	DEFINITION
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
Steamboat	Calpine Steamboat Holdings, LLC, an indirect, wholly owned subsidiary of Calpine Corporation
Steamboat Amended Credit Facility	The Amended and Restated Credit Agreement dated November 24, 2009 between Steamboat, as borrower, the lenders named therein, Calyon New York Branch as lead arranger, co-book runner, administrative agent, collateral agent and Security Fund LC issuer and the other agents, bookrunners and agents named therein amending and restating the Credit Agreement, dated as of February 25, 2005, among the parties as defined therein
ULC I	Calpine Canada Energy Finance ULC
ULC II	Calpine Canada Energy Finance II ULC
Unsecured Notes	Collectively, Calpine Corporation’s 7 7/8% Senior Notes due 2008, 7 3/4% Senior Notes due 2009, 8 5/8% Senior Notes due 2010 and 8 1/2% Senior Notes due 2011, which constitute a portion of Calpine Corporation’s Unsecured Senior Notes all of which were terminated and settled with Calpine Corporation common stock on the Effective Date
Unsecured Senior Notes	Collectively, Calpine Corporation’s 7 5/8% Senior Notes due 2006, 10 1/2% Senior Notes due 2006, 8 3/4% Senior Notes due 2007, 7 7/8% Senior Notes due 2008, 7 3/4% Senior Notes due 2009, 8 5/8% Senior Notes due 2010 and 8 1/2% Senior Notes due 2011, all of which were terminated and settled with Calpine Corporation common stock on the Effective Date
U.S. Bankruptcy Court	U.S. Bankruptcy Court for the Southern District of New York
U.S. Debtor(s)	Calpine Corporation and each of its subsidiaries and affiliates that have filed voluntary petitions for reorganization under Chapter 11 of the 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)
VAR	Value-at-risk
VIE(s)	Variable interest entity(ies)
Whitby	Whitby Cogeneration Limited Partnership
WP&L	Wisconsin Power & Light Company

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Item 6.  Selected Financial Data

SELECTED CONSOLIDATED FINANCIAL DATA

	Years Ended December 31,
	2009		2008			2007		2006			2005
	(in millions, except earnings (loss) per share)
Statement of Operations data:
Operating revenues	$	6,463	$	9,837		$	7,869	$	6,843		$	10,206
Income (loss) before discontinued operations attributable to Calpine(1)	$	114	$	(26	)	$	2,666	$	(1,773	)	$	(9,863	)
Discontinued operations, net of tax, attributable to Calpine		35		36			27		8			(76	)
Net income (loss) attributable to Calpine(1)	$	149	$	10		$	2,693	$	(1,765	)	$	(9,939	)
Basic earnings (loss) per common share(2) :
Income (loss) before discontinued operations attributable to Calpine (1)	$	0.24	$	(0.05	)	$	5.56	$	(3.70	)	$	(21.28	)
Discontinued operations, net of tax, attributable to Calpine		0.07		0.07			0.06		0.02			(0.16	)
Net income (loss) per common share attributable to Calpine(1)	$	0.31	$	0.02		$	5.62	$	(3.68	)	$	(21.44	)
Diluted earnings (loss) per common share(2) :
Income (loss) before discontinued operations attributable to Calpine (1)	$	0.24	$	(0.05	)	$	5.56	$	(3.70	)	$	(21.28	)
Discontinued operations, net of tax, attributable to Calpine		0.07		0.07			0.06		0.02			(0.16	)
Net income (loss) per common share attributable to Calpine(1)	$	0.31	$	0.02		$	5.62	$	(3.68	)	$	(21.44	)
Balance Sheet data(3) :
Total assets	$	16,650	$	20,738		$	19,050	$	18,590		$	20,545
Short-term debt and capital lease obligations(4)		463		716			1,710		4,569			5,414
Long-term debt and capital lease obligations(4)(5)		8,996		9,756			9,946		3,352			2,462
Liabilities subject to compromise(5)		—		—			8,788		14,757			14,610

__________

(1) As a result of our Chapter 11 and CCAA filings, for the year ended December 31, 2005, we recorded $5.0 billion of reorganization items primarily related to the provisions for expected allowed claims, impairment of our Canadian subsidiaries, guarantees, write-off of unamortized deferred financing costs and losses on terminated contracts. During 2007, we were released from a portion of our direct and indirect Canadian guarantee of the ULC I notes, ULC II notes and redundant Canadian claims and recorded a $4.1 billion credit for the reversal of these redundant claims.

(2) Although earnings (loss) per share information for the years ended December 31, 2007, 2006 and 2005 is presented, it is not comparable to the information presented for the years ended December 31, 2009 and 2008, due to the changes in our capital structure on the Effective Date, which also included termination of all outstanding convertible securities.

(3) See Note 16 of the Notes to Consolidated Financial Statements regarding certain “plan effect” adjustments to our Consolidated Balance Sheet as of the Effective Date.

(4) As a result of our Chapter 11 filings, we reclassified approximately $5.1 billion of long-term debt and capital lease obligations to short-term at December 31, 2006 and 2005, as our Chapter 11 filings constituted events of default or otherwise triggered repayment obligations for the Calpine Debtors and certain Non-Debtor entities. We classified our long-term debt and capital lease obligations at December 31, 2007, based upon the refinanced terms of our First Lien Facilities.

(5) LSTC included unsecured and under secured liabilities incurred prior to the Petition Date and excluded liabilities that are fully secured or liabilities of our subsidiaries or affiliates that did not make Chapter 11 filings and other approved payments such as taxes and payroll. As a result of our Chapter 11 filings, we reclassified approximately $7.5 billion of long-term debt to LSTC at December 31, 2005. We subsequently reclassified $3.7 billion from LSTC back to long-term debt based upon the terms of our Plan of Reorganization at December 31, 2007. See Note 16 of the Notes to Consolidated Financial Statements for more information.

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Item 7.  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 Financial Statements and related notes. See the cautionary statement regarding forward-looking statements on page 1 of this Report for a description of important factors that could cause actual results to differ from expected results. See also Item 1A. “Risk Factors” included in our 2009 Form 10-K.

INTRODUCTION AND OVERVIEW

Our Business

We are the largest independent wholesale power company in the U.S. measured by power produced. We own and operate natural gas-fired and geothermal power plants in North America and have a significant presence in major competitive power markets in the U.S., including California and Texas, and to a lesser extent, in the competitive PJM, ISO NE and NYISO markets. We sell wholesale power, steam, 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.

Our portfolio, including partnership interests, consists of 77 operating power plants, located throughout 16 states and Canada, with an aggregate generation capacity of approximately 24,802 MW. It is comprised of two types of power generation technologies: natural gas-fired combustion turbines, which are primarily combined-cycle plants, and renewable geothermal conventional steam turbines. We are among the world’s largest owners and operators of industrial gas turbines as well as cogeneration power plants. Our Geysers Assets located in northern California represent the largest geothermal power generation portfolio in the U.S. and produced approximately 21% of all renewable energy produced in the state of California during 2008. Geothermal energy is one of the only baseload renewable energy supplies that exists today.

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, Southeast and North (including Canada). In these segments we have an aggregate generation capacity of 7,910 MW in the West, 7,392 MW in Texas, 6,083 MW in the Southeast and 3,417 MW in the North. Our Geysers Assets, included in our West segment, have generation capacity of approximately 725 MW from 15 operating power plants.

We remain focused on increasing our earnings and generating cash flow 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.

Our Regulatory and Environmental Profile

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. Federal and state legislative and regulatory actions continue to change how our business is regulated. The federal government is expected to take action on climate change legislation, as well as other air pollutant emissions, and many states and regions in the U.S. have implemented or are considering implementing regulations to reduce GHG emissions. We are actively participating in these debates at the federal, regional and state levels. For a further discussion of the environmental and other governmental regulations that affect us, see “— Governmental and Regulatory Matters” in Item 1. of our 2009 Form 10-K. Although we cannot predict the ultimate effect future climate change legislation or regulations could have on our business, we believe that we will be less adversely impacted by potential cap-and-trade limits, carbon taxes or required environmental upgrades as a result of future potential regulation or legislation addressing GHG, other air emissions, as well as water use or emissions, than compared to our competitors who use other fossil fuels or steam condensation technologies. Since our inception in 1984, we have been a leader in environmental stewardship and have invested exclusively in clean power generation to become a recognized leader in developing, constructing, owning and operating an environmentally responsible portfolio of power plants. The combination of our Geysers Assets and our high efficiency portfolio of natural gas-fired power plants results in substantially lower emissions of these gases compared to our competitors’ power plants using other fossil fuels, such as coal. Consequently, our power generation portfolio has the lowest GHG footprint per MWh of any major independent power producer in the U.S. In addition, we strive to preserve our nation’s valuable water and land resources. To condense steam, we use cooling towers

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with a closed water cooling system, or air cooled condensers and do not employ “once-through” water cooling, which uses large quantities of water from adjacent waterways negatively impacting aquatic life. Since our plants are modern and efficient and utilize clean burning natural gas, we do not require large areas of land for our power plants nor do we require large specialized landfills for the disposal of coal ash or nuclear plant waste.

Our Market and Our Key Financial Performance Drivers

The market spark spread, sales of RECs, revenues from our steam sales and the results from our marketing, hedging and optimization activities are the primary components of our Commodity Margin and contribute significantly to our financial results. The market spark spread is primarily impacted by natural gas prices, weather and reserve margins, which impact both our supply and demand fundamentals. Those factors, plus the relationship between our operating Heat Rate compared to the Market Heat Rate, our power plant operating performance and availability are key to our financial performance.

Depending upon our hedge levels and holding other factors constant, increases in natural gas prices tend to increase our Commodity Margin and decreases in natural gas prices tend to decrease our Commodity Margin because we generally have lower Heat Rates and are more efficient than our competitors. Efficient operation of our fleet creates the opportunity to capture Commodity Margin in a cost effective manner. However, unplanned outages during periods of positive Commodity Margin could result in a loss of that opportunity. We generally measure our fleet performance based on our availability factors, Heat Rate and plant operating expense. The higher our availability factor, the better positioned we are to capture Commodity Margin. The less natural gas we must consume for each MWh of power generated, the lower our Heat Rate. The lower our operating Heat Rate compared to the Market Heat Rate, the more favorable the impact on our Commodity Margin. Holding all other factors constant, our Commodity Margin increases when we are able to lower our operating Heat Rate compared to the Market Heat Rate and conversely decreases when our operating Heat Rate increases compared to the Market Heat Rate. See also “— The Market for Power — Our Power Market Economics” in Item 1. of our 2009 Form 10-K for additional information on how these factors impact our Commodity Margin.

Current Year Operational Developments

During 2009, we have continued to implement our strategy to become the premier independent power company in the U.S. and achieve sustainable growth through financially disciplined power plant development, construction, operations and ownership. We have made some notable achievements that are listed below:

• On February 4, 2010, we received the Prevention of Significant Deterioration, or PSD, air permit, the final permit necessary, to begin construction of our Russell City Energy Center. We hope to complete financing and break ground for this new state-of-the-art power plant during 2010 with commercial operations scheduled to begin in 2013. Russell City Energy Center is intended to become the first power plant in the U.S. with a federal limit on GHG emissions, and will be designed to operate in a way that produces 25% fewer GHG emissions than the CPUC standard.

• Throughout 2009, our plant operating personnel exceeded the first quartile performance for employee lost time incident rate for fossil fuel electric power generation companies with 1,000 or more employees.

• Our Geysers Assets generated approximately 6 million MWh and achieved an exceptional equivalent availability factor of over 97%. Our natural gas-fired fleet achieved exceptional performance during 2009, with an equivalent forced outage factor of 2.7%, an improvement of 35% over full year 2008.

• We completed 14 major inspections and 13 hot gas path inspections on schedule and on budget during 2009 and completed one of several planned natural gas-fired turbine upgrades and two steam turbine upgrades, which not only added incremental capacity but improved the efficiency of the entire turbines.

• OMEC, located in San Diego, California, achieved commercial operations on October 3, 2009, adding 608 MW of capacity to our fleet.

• Under one of our new PPAs, we will modernize and upgrade our Los Esteros Critical Energy Facility to add 120 MW by converting it from simple-cycle (peaking) to combined-cycle technology, increasing the efficiency and environmental performance of the power plant.

• We successfully restructured and streamlined our power and commercial operations, as well as our corporate functions, to more effectively manage our business and reduce expenses.

3

Customer-Oriented Origination Business

During 2009, we reorganized our customer origination function to allow our dedicated group of professionals to more effectively help manage this function. This effort is beginning to deliver real, tangible results and we, through certain of our wholly owned subsidiaries, entered into new PPAs and amended certain PPAs, which are all on mutually beneficial terms and many are subject to regulatory approvals. They include the following:

• We and PG&E have agreed to an extension of the term and an increase in the volume under the existing contracts for delivery of power from our Geysers Assets. Our Geysers Assets currently provide PG&E 375 MW of power under two contracts. We have agreed to increase the volume to 425 MW through 2017, and from 2018 through the end of 2021, our Geysers Assets will supply PG&E 250 MW of renewable energy.

• Our wholly owned subsidiaries, Gilroy Energy Center, LLC, Creed and Goose Haven, have entered into a replacement contract with PG&E, whereby PG&E will have greater dispatch flexibility for all 11 of our peaking units in California through 2017 and for seven of our peaking units through 2021.

• We and PG&E negotiated a new agreement to replace the existing CDWR 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. While the upgrade is under construction, we will provide capacity to PG&E from our Gilroy Cogeneration Plant. Upon completion of the upgrade, PG&E will purchase all of the capacity from our Los Esteros Critical Energy Facility for a term of ten years.

• We have entered into a new tolling arrangement with PG&E for all of the capacity from our Delta Energy Center from 2011 through 2013.

• We executed a resource adequacy agreement for all of the capacity from our Pastoria Energy Center with Southern California Edison for 2012 and 2013.

• We executed a contract for 500 MW of capacity from our Morgan Energy Center with the Tennessee Valley Authority through 2011.

• We executed a contract for 485 MW of capacity from our Carville Energy Center with Entergy Corporation through May 2012.

• We executed a contract for 200 MW of capacity from our Oneta Energy Center with American Electric Power through 2010.

• In addition to the suite of products we plan to supply through the agreements described above, our commercial operations team is also identifying creative opportunities to match our capabilities with the needs of our customers. During 2009, we entered into a PPA with the Los Angeles Department of Water and Power to provide integration services of up to 270 MW, leveraging our quick-responding natural gas-fired Hermiston Power Project located in Hermiston, Oregon, as well as its contracted transmission resources in the northwest as back up for wind generated power.

The last transaction is an indication of the need our customers and more generally the market will have to utilize flexible natural gas-fired generation to assure reliability of supply while integrating intermittent and variable renewable resources, such as wind and solar power, that they are required to procure as part of a renewable energy portfolio.

Capital Management

We have opportunistically completed several financing transactions for a total of approximately $3.0 billion to improve our flexibility and management of our balance sheet. Significant transactions in 2009 include, but are not limited to, the following:

• On November 24, 2009, we amended and extended our Steamboat project debt which extended the maturity date from December 2011 to November 24, 2017.

• On December 11, 2009, we amended the letter of credit facility related to our subsidiary, Calpine Development Holdings, Inc., to extend the maturity from January 31, 2010 to December 11, 2012, with an option to increase the letters of credit available from $150 million to $200 million by satisfying certain conditions.

4

• On August 20, 2009, we amended our First Lien Credit Facility and related collateral agency and intercreditor agreement in several respects to give us greater flexibility, including allowing us to exchange First Lien Credit Facility term loans for First Lien Notes.

• On October 21, 2009, we issued approximately $1.2 billion aggregate principal amount of First Lien Notes in a private placement as a permitted debt exchange pursuant to our First Lien Credit Facility, which retired an aggregate principal amount of term loans under our First Lien Credit Facility equal to the aggregate principal amount of First Lien Notes issued. As a result of the issuance of the First Lien Notes, we were able to extend the maturities of approximately $1.2 billion in debt to 2017, at the same time converting it from a variable to a fixed interest rate.

• On May 19, 2009, our wholly owned subsidiaries, CCFC and CCFC Finance, issued approximately $1.0 billion aggregate principal amount of CCFC New Notes in a private placement. The net proceeds were used to repay the CCFC Term Loans, CCFC Old Notes and CCFCP Preferred Shares. As a result of the CCFC Refinancing transactions, we were able to extend the maturities of approximately $1.0 billion of debt by several years, at the same time converting it from a variable to a fixed interest rate and lowering our effective interest rates.

• On January 21, 2009, we closed on our Deer Park $156 million senior secured credit facilities, which included a $150 million term facility and a $6 million letter of credit facility. Proceeds received were used to settle an existing commodity contract of approximately $79 million, pay financing and legal fees, fund additional restricted cash and for general corporate purposes.

For a further discussion of our 2009 significant financing transactions, see “— Liquidity and Capital Resources.”

5

RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2009 AND 2008

Below are our results of operations for the year ended December 31, 2009, as compared to the same period in 2008 (in millions, except for percentages and operating performance metrics). Our results of operations and operating performance metrics have been recast to exclude Blue Spruce and Rocky Mountain, which are reported in discontinued operations. We have modified our presentation of commodity revenue and commodity expense to include cash settlements from our commodity marketing, hedging and optimization activities that were previously included in mark-to-market activity. Our 2008 commodity revenue and commodity expense information has been reclassified to conform to the current year presentation. 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 in the “Change” and “% Change” columns.

	2009			2008			Change			% Change
Operating revenues:
Commodity revenue	$	6,362		$	9,776		$	(3,414	)		(35)	%
Mark-to-market activity(1)		80			4			76			#
Other revenue		21			57			(36	)		(63)
Operating revenues		6,463			9,837			(3,374	)		(34)
Cost of revenue:
Fuel and purchased energy expense:
Commodity expense		3,896			7,352			3,456			47
Mark-to-market activity(1)		1			(71	)		(72	)		#
Fuel and purchased energy expense		3,897			7,281			3,384			46
Plant operating expense		868			890			22			2
Depreciation and amortization expense		447			416			(31	)		(7)
Operating asset impairments		4			33			29			88
Other cost of revenue(2)		83			114			31			27
Total cost of revenue		5,299			8,734			3,435			39
Gross profit		1,164			1,103			61			6
Sales, general and other administrative expense		183			215			32			15
(Income) loss from unconsolidated investments in power plants		(50	)		229			279			#
Other operating expense		18			25			7			28
Income from operations		1,013			634			379			60
Interest expense		815			1,044			229			22
Interest (income)		(16	)		(46	)		(30	)		(65)
Debt extinguishment costs		76			6			(70	)		#
Other (income) expense, net		14			15			1			7
Income (loss) before reorganization items, income taxes and discontinued operations		124			(385	)		509			#
Reorganization items		(1	)		(302	)		(301	)		#
Income (loss) before income taxes and discontinued operations		125			(83	)		208			#
Income tax expense (benefit)		15			(56	)		(71	)		#
Income (loss) before discontinued operations		110			(27	)		137			#
Discontinued operations, net of tax expense		35			36			(1	)		(3)
Net income		145			9			136			#
Net loss attributable to the noncontrolling interest		4			1			3			#
Net income attributable to Calpine	$	149		$	10		$	139			#
		2009			2008		Change			% Change
Operating Performance Metrics:
MWh generated (in thousands)(3)		84,376			84,078			298			—	%
Average availability		92.1	%		90.3	%		1.8			2
Average total MW in operation		22,483			22,106			377			2
Average capacity factor, excluding peakers		48.2	%		47.6	%		0.6			1
Steam Adjusted Heat Rate		7,264			7,231			(33	)		—

__________

# Variance of 100% or greater

6

(1) Amount represents the unrealized portion of our commodity mark-to-market activity as well as a non-cash gain from amortization of prepaid power sales agreements.

(2) Includes $5 million and nil of RGGI compliance costs for the years ended December 31, 2009 and 2008, respectively, which is a component of Commodity Margin.

(3) Represents generation from power plants that we both consolidate and operate.

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 and commodity expense decreased for the year ended December 31, 2009 compared to 2008, largely due to lower natural gas prices which decreased 53% in 2009 compared to 2008; however, commodity revenue, net of commodity expense, increased $42 million for the year ended December 31, 2009 compared to 2008, primarily due to:

• higher average hedge margins in 2009 compared to 2008;

• average annual Market Heat Rates were relatively unchanged for the year ended December 31, 2009 compared to 2008, with the exception of our Southeast segment which experienced a 35% increase in generation in 2009 compared to 2008 largely due to higher natural gas generation displacement of coal generation in certain sub-markets in our Southeast segment caused by lower natural gas prices resulting in higher Market Heat Rates; partially offset by

• lower natural gas prices in 2009 compared to 2008 and the resulting negative impact on our open positions.

These factors were also positively impacted by our operational performance where we experienced a 2% increase in our average availability and a 1% increase in our average capacity factor, excluding peakers, for the year ended December 31, 2009 compared to 2008.

Revenues from mark-to-market activity increased for the year ended December 31, 2009 compared to 2008, which is consistent with a falling commodity price environment. Expenses from mark-to-market activity increased for the year ended December 31, 2009 compared to 2008, due to the impact of natural gas market price volatility on our natural gas hedge position for our generation portfolio.

Other revenue decreased for the year ended December 31, 2009 compared to 2008, primarily related to a $14 million decrease in revenue from operation and maintenance contracts and a $7 million decrease in revenue from construction management projects completed in 2008. Also contributing to the decrease was an $11 million decrease in other revenue related to royalty income on oil and gas producing properties.

Normal, recurring plant operating expenses decreased by $22 million for the year ended December 31, 2009 compared to 2008, after accounting for $29 million in reimbursements for insurance claims from prior periods that reduced our 2008 and, to a much lesser extent, 2009 expenses. Additionally, major maintenance costs resulting from our plant outage schedule decreased $17 million and plant personnel costs related to stock-based compensation expense decreased $8 million for the year ended December 31, 2009 compared to 2008.

Depreciation and amortization expense increased for the year ended December 31, 2009 compared to 2008, primarily resulting from an increase of $22 million in the fourth quarter of 2009 related 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 as well as a $9 million increase resulting from an upward revision in the rate used to depreciate our Geysers Assets due to changes in our estimate of our future development costs for the first nine months of 2009. See Note 3 of the Notes to Consolidated 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.

Our operating asset impairments decreased for the year ended December 31, 2009 compared to 2008, primarily from a $33 million impairment recorded in 2008 relating to our Auburndale Peaking Energy Center resulting from lower forecasted future cash flows.

7

Other cost of revenue decreased for the year ended December 31, 2009 compared to 2008, as a result of a decrease of $17 million related to the discontinuation of the amortization of other assets associated with the deconsolidation and subsequent sale of Auburndale in 2008 as well as an $11 million decrease in royalty expense due to lower revenues from our Geysers Assets resulting from lower spot market power prices in the year ended December 31, 2009 compared to 2008. The decrease was partially offset by an increase of $5 million in expenses related to RGGI compliance costs in the Northeast which was initiated in 2009.

Sales, general and other administrative expense decreased for the year ended December 31, 2009 compared to 2008, due to a $10 million decrease in personnel costs and stock-based compensation expense resulting primarily from a lower headcount in 2009 as well as a $13 million decrease in legal and consulting expenses. In addition, we experienced a $5 million favorable year over year change in our bad debt expense.

Our (income) loss from unconsolidated investments in power plants increased for the year ended December 31, 2009 compared to 2008, primarily due to an impairment loss of $180 million related to our equity interest in Auburndale recorded during the year ended December 31, 2008. Also contributing to the increase was income from our investment in Greenfield LP of $16 million for the year ended December 31, 2009 compared to a loss of $5 million for the year ended December 31, 2008, which is due to Greenfield LP achieving commercial operations in October 2008. We also had income of $32 million related to our investment of OMEC, of which, $4 million related to OMEC achieving commercial operation in October 2009 and a $28 million gain related to mark-to-market activities from interest rate swap contracts compared to a loss of $55 million incurred for the year ended December 31, 2008, related to unrealized mark-to-market losses from interest rate swap contracts. See Note 4 of the Notes to Consolidated Financial Statements for further information regarding our unconsolidated investments.

Other operating expense decreased for the year ended December 31, 2009 compared to 2008, due to impairments of $13 million related to development projects recorded in 2008 which was partially offset by an increase of $6 million in project development expense for the year ended December 31, 2009 compared to 2008, related to Russell City Energy Center which is under advanced development.

Due to the changes in our capital structure on the Effective Date, our interest expense for the years ended December 31, 2009 and 2008, is not directly comparable. Interest expense decreased primarily due to $135 million in post-petition interest related to pre-emergence debt recorded in the first quarter of 2008 and $27 million for settlement obligations related to the Canadian Debtors and other deconsolidated foreign entities recorded prior to their reconsolidation in February 2008. In addition, interest expense decreased for the year ended December 31, 2009 compared to 2008, due to lower average interest rates on our variable rate debt resulting from a decrease in LIBOR over the same periods. 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, were 8.0% and 8.8% for the year ended December 31, 2009 and 2008, respectively. The decrease in interest expense was partially offset by the negative period over period impact of $151 million related to interest rate swap settlements resulting from a decrease in LIBOR.

Interest income decreased for the year ended December 31, 2009 compared to 2008, largely resulting from lower average interest rates earned on our cash balances which were primarily invested in U.S. Treasury securities or government-backed securities for the year ended December 31, 2009 compared to primarily invested in institutional-backed money market accounts for the year ended December 31, 2008.

Debt extinguishment costs increased for the year ended December 31, 2009 compared to 2008, primarily due to $76 million in debt extinguishment costs associated with the retirement of the term loans under the First Lien Credit Facility in October 2009, the refinancing of our CCFC Old Notes and CCFC Term Loans in May and June 2009 and the CCFCP Preferred Shares that were redeemed on or before July 1, 2009. This increase was partially offset by $6 million in debt extinguishment costs for the write-off of unamortized deferred financing costs associated with the refinancing of our Metcalf term loan facility and preferred interests in June 2008.

During the year ended December 31, 2009, reorganization items primarily consisted of settlements of various disputed claims. During the year ended December 31, 2008, reorganization items primarily consisted of $206 million in gains on asset sales, a $71 million gain on the reconsolidation of the Canadian Debtors and other deconsolidated foreign entities, a $62 million credit related to the settlement of claims with the Canadian Debtors and other deconsolidated foreign entities, a $34 million credit for RockGen related to a prior period which we determined was not material to any period, a $12 million credit related to the settlement with Rosetta of our fraudulent conveyance claim and $85 million in professional and trustee fees related to activity managed by our third party advisors for our Chapter 11 and CCAA cases.

8

For the year ended December 31, 2009, we recorded tax expense of $15 million before discontinued operations compared to a benefit of $56 million for the year ended December 31, 2008. Due to the valuation allowances recorded against certain deferred tax assets, our effective tax rate differs considerably from the federal statutory rate. Our tax structure is comprised primarily of two taxable groups, CCFC and its subsidiaries and Calpine Corporation and its subsidiaries other than CCFC. CCFC and its subsidiaries no longer have a valuation allowance recorded against its deferred tax assets due to its ability to generate sufficient income to utilize its NOLs. Our 2009 income tax expense primarily relates to a foreign tax expense of $2 million and $43 million expense relating to the reversal of prior years intraperiod tax allocation due to OCI gains partially offset by a $30 million tax benefit from the CCFC group. Our 2008 benefit for income taxes before discontinued operations primarily relates to a foreign tax benefit of $70 million recorded as a result of the Canadian Settlement Agreement, and intraperiod tax allocation benefit of $99 million, which was comprised of a $76 million tax benefit to continuing operations due to current OCI gains and a $23 million tax benefit in income from discontinued operations, both of which are reflected in deferred tax benefit, offset by tax expense of approximately $100 million on CCFC’s income. See Note 11 of the Notes to Consolidated Financial Statements for further information.

During the year ended December 31, 2009, we recorded $35 million in income from discontinued operations related to the results of operations of Blue Spruce and Rocky Mountain. During the year ended December 31, 2008, we recorded $36 million in income from discontinued operations, net of taxes of $23 million, related to the results of operations of Blue Spruce and Rocky Mountain as well as the settlement with Rosetta of all of our outstanding claims related to our domestic oil and gas assets we sold to Rosetta for $1.1 billion in 2005. See Note 6 of the Notes to Consolidated Financial Statements for further information related to our discontinued operations.

9

RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2008 AND 2007

Below are our results of operations for the year ended December 31, 2008, as compared to the same period in 2007 (in millions, except for percentages and operating performance metrics). Our results of operations and operating performance metrics have been recast to exclude Blue Spruce and Rocky Mountain, which are reported in discontinued operations. We have modified our presentation of commodity revenue and commodity expense to include cash settlements from our commodity marketing, hedging and optimization activities that were previously included in mark-to-market activity. Our 2008 and 2007 commodity revenue and commodity expense information has been reclassified to conform to the current year presentation. 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 in the “Change” and “% Change” columns.

	2008			2007			Change			% Change
Operating revenues:
Commodity revenue	$	9,776		$	7,801		$	1,975			25	%
Mark-to-market activity(1)		4			10			(6	)		(60)
Other revenue		57			58			(1	)		(2)
Operating revenues		9,837			7,869			1,968			25
Cost of revenue:
Fuel and purchased energy expense:
Commodity expense		7,352			5,691			(1,661	)		(29)
Mark-to-market activity(1)		(71	)		(9	)		62			#
Fuel and purchased energy expense		7,281			5,682			(1,599	)		(28)
Plant operating expense		890			723			(167	)		(23)
Depreciation and amortization expense		416			446			30			7
Operating asset impairments		33			44			11			25
Other cost of revenue		114			136			22			16
Total cost of revenue		8,734			7,031			(1,703	)		(24)
Gross profit		1,103			838			265			32
Sales, general and other administrative expense		215			146			(69	)		(47)
Loss from unconsolidated investments in power plants		229			21			(208	)		#
Other operating expense		25			23			(2	)		(9)
Income from operations		634			648			(14	)		(2)
Interest expense		1,044			1,988			944			47
Interest (income)		(46	)		(61	)		(15	)		(25)
Debt extinguishment costs		6			(1	)		(7	)		#
Other (income) expense, net		15			(140	)		(155	)		#
Loss before reorganization items, income taxes and discontinued operations		(385	)		(1,138	)		753			66
Reorganization items		(302	)		(3,258	)		(2,956	)		(91)
Income (loss) before income taxes and discontinued operations		(83	)		2,120			(2,203	)		#
Income tax benefit		(56	)		(546	)		(490	)		(90)
Income (loss) before discontinued operations		(27	)		2,666			(2,693	)		#
Discontinued operations, net of tax expense		36			27			9			33
Net income		9			2,693			(2,684	)		#
Net loss attributable to the noncontrolling interest		1			—			1			—
Net income attributable to Calpine	$	10		$	2,693		$	(2,683	)		#
		2008			2007		Change			% Change
Operating Performance Metrics:
MWh generated (in thousands)(2)		84,078			86,763			(2,685	)		(3)	%
Average availability		90.3	%		90.6	%		(0.3	)		—
Average total MW in operation		22,106			23,748			(1,642	)		(7)
Average capacity factor, excluding peakers		47.6	%		46.3	%		1.3			3
Steam Adjusted Heat Rate		7,231			7,172			(59	)		(1)

 __________

# Variance of 100% or greater

10

(1) Amount represents the unrealized portion of our mark-to-market activity as well as a non-cash gain from amortization of prepaid power sales agreements.

(2) Represents generation from power plants that we both consolidate and operate.

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 and commodity expense increased for the year ended December 31, 2008 compared to 2007, largely due to higher natural gas prices which increased 25% in 2008 compared to 2007. In addition, commodity revenue, net of commodity expense, increased $314 million for the year ended December 31, 2008, compared to 2007 primarily due to:

• higher market spark spreads on open positions due to higher natural gas prices throughout the first three quarters of 2008 in our key Texas and West markets which benefited our power plants in these regions as they operated more efficiently against corresponding Market Heat Rates;

• higher Market Heat Rates in the second quarter of 2008, particularly in Texas which resulted from higher temperatures and transmission congestion in the South and Houston zones;

• higher realized spark spreads for our generally higher levels of hedging in all regions; and

• earnings from settlement of dedesignated hedges, the value for which was previously reflected in OCI.

Generation decreased 3% despite a 3% increase in our average capacity factor, excluding peakers, due to a 7%, or 1,642 MW, decrease in our average total MW in operation for the year ended December 31, 2008, compared to 2007. The generation decrease primarily resulted from power plant sales in 2007, the deconsolidation and subsequent sale of Auburndale in 2008 and an increase in the number of unscheduled outages in 2008 compared to 2007.

Results of net unrealized mark-to-market activity are driven primarily from our commodity hedging activities that do not qualify for hedge accounting. The $56 million increase for the year ended December 31, 2008 compared to 2007, is largely due to a decrease in expenses from mark-to-market activity primarily driven by the impact of natural gas market price volatility on our natural gas hedge position for our generation portfolio.

Plant operating expense increased during the year ended December 31, 2008, compared to the year ended December 31, 2007, primarily as a result of a $93 million increase in expense for major maintenance for scheduled outages related to the life cycle of our power plant fleet and an increase of $25 million in plant personnel costs related to stock-based compensation expense for equity awards issued in 2008. The increase in major maintenance is driven by the fact that we placed 23 power plants in service in the 2001-2002 time frame and many have reached their 24,000 or 48,000 hour major inspection operating intervals. Routine operating and repair costs also contributed $30 million to the increase in plant operating expense which related to increases in chemical costs and other consumables, and increases in routine repairs. A $15 million increase in expense for outages, many of which occurred in 2007 and equipment repairs made in 2008, caused by equipment failures, net of insurance recoveries, also contributed to the increase in plant operating expense for the year ended December 31, 2008, compared to 2007.

Depreciation and amortization expense decreased for the year ended December 31, 2008, compared to the year ended December 31, 2007, primarily due to an upward revision in the estimated useful life of our Geysers Assets as well as the sale of Acadia PP in September 2007. The upward revision in the estimated useful life of our Geysers Assets relates to our reservoir replenishment activities which extends the estimated economic life of our Geysers Assets from 2034 to 2050.

Our operating asset impairments for the year ended December 31, 2008, consisted of a $33 million impairment relating to our Auburndale Peaking Energy Center resulting from lower forecasted future cash flows. Operating asset impairments of $44 million during the year ended December 31, 2007, were recorded primarily for the Bethpage Power Plant resulting from the expected adverse impact on power pricing of new power transmission capacity from the PJM market into Long Island.

Other cost of revenue decreased for the year ended December 31, 2008, compared to the year ended December 31, 2007, as a result of an $8 million decrease for the sale of PSM in March 2007, a $10 million decrease in operating lease expense due to the termination of the lease associated with our purchase of the RockGen Energy Center in January 2008 and a decrease of $8 million related to the discontinuation of the amortization of other assets associated with the deconsolidation and subsequent sale of Auburndale in 2008. These decreases were partially offset by a $5 million increase in royalty expense due to higher spot market power prices in 2008 compared to 2007.

11

Sales, general and other administrative expense was higher for the year ended December 31, 2008, compared to the same period in 2007 due to a $42 million increase in personnel costs resulting primarily from higher stock-based compensation expense arising from the grant of equity awards during the first quarter of 2008 and a $15 million increase in legal and consulting expenses.

Our loss from unconsolidated investments in power plants increased in 2008 compared to 2007 primarily due to an impairment loss of $180 million related to our equity interest in Auburndale during the year ended December 31, 2008. We also incurred an increase of $47 million in unrealized mark-to-market losses from interest rate swap contracts related to our investment in OMEC. The increase was partially offset by $9 million in income from our investment in RockGen and an $8 million reduction in losses related to our investment in Greenfield LP for the year ended December 31, 2008, compared to 2007. See Note 4 of the Notes to Consolidated Financial Statements for further information regarding our unconsolidated investments.

Due to the changes in our capital structure on the Effective Date, our interest expense for the years ended December 31, 2008 and 2007, is not directly comparable. Interest expense decreased primarily due to $376 million in post-petition interest related to pre-emergence debt recorded in 2007, resulting from the Canadian Settlement Agreement as well as $347 million in post-petition interest related to other pre-petition obligations recorded during the year ended December 31, 2007, which was partially offset by $135 million in post-petition interest recorded during the year ended December 31, 2008. In addition, interest expense decreased for the year ended December 31, 2008, compared to the year ended December 31, 2007, due to lower average debt balances and lower average interest rates. During the first quarter of 2008, we settled a portion of our debt through payment of cash and issuance of reorganized Calpine Corporation common stock pursuant to our Plan of Reorganization. Additionally, interest rates on our variable rate debt were lower for the year ended December 31, 2008, compared to 2007, due to a decrease in LIBOR over the same periods. The annualized effective interest rates on our consolidated debt, excluding the impacts of items not directly attributed to the cost of the debt instruments, after amortization of deferred financing costs and debt discounts, were 8.8% and 11.0% for the years ended December 31, 2008 and 2007, respectively. The decrease was partially offset by the negative period over period impact of $85 million related to interest rate swap settlements resulting from a decrease in LIBOR as well as $27 million for settlement obligations related to our Canadian subsidiaries recorded prior to their reconsolidation in February 2008.

Interest income decreased primarily due to lower average cash balances for the year ended December 31, 2008, compared to the same period in 2007 resulting from the distribution of cash pursuant to our Plan of Reorganization in the first quarter of 2008, and due to lower average interest rates.

Other (income) expense, net had an unfavorable variance primarily as a result of the non-recurrence of $135 million in income pertaining to a claim settlement with a customer which received court approval and was recorded during the third quarter of 2007. The claim related to the customer’s rejection of our energy services agreement following the customer’s bankruptcy filing and was unrelated to our Chapter 11 cases. Also contributing to the decrease was a loss of $13 million incurred during 2008 related to our settlement with Panda.

Debt extinguishment costs increased for the year ended December 31, 2008 compared to 2007, primarily due to $6 million in debt extinguishment costs for the write-off of unamortized deferred financing costs associated with the refinancing of our Metcalf term loan facility and preferred interests in June 2008.

The table below lists the significant components of reorganization items for the years ended December 31, 2008 and 2007 (in millions):

	2008			2007			Change			% Change
Provision for expected allowed claims	$	(95	)	$	(3,687	)	$	(3,592	)		(97	)%
Professional and trustee fees		85			217			132			61
Gains on asset sales		(206	)		(285	)		(79	)		(28	)
Asset impairments		—			120			120			#
Gain on reconsolidation of Canadian Debtors and other deconsolidated foreign entities		(71	)		—			71			—
DIP Facility and First Lien Facilities financing and CalGen Secured Debt repayment costs		(4	)		202			206			#
Interest (income) on accumulated cash		(7	)		(59	)		(52	)		(88	)
Other		(4	)		234			238			#
Total reorganization items	$	(302	)	$	(3,258	)	$	(2,956	)		(91	)

__________

# Variance of 100% or greater

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Provision for Expected Allowed Claims — During the year ended December 31, 2008, our provision for expected allowed claims consisted primarily of a $62 million credit related to the settlement of claims with the Canadian Debtors and other deconsolidated foreign entities, a $12 million credit related to the settlement with Rosetta of our fraudulent conveyance claim and a $34 million credit for RockGen related to a prior period which we determined was not material to any period. During the year ended December 31, 2007, our provision for expected allowed claims consisted primarily of a $4.1 billion credit related to the settlement of claims related to Calpine Corporation’s guarantee of the ULC I notes and the release of our guarantee of the ULC II notes following repayment of those notes in September 2007, accruals totaling $275 million for make whole premiums and/or damages related to the First Priority Notes, Second Priority Debt and Unsecured Notes settlements, $141 million resulting from the termination of the RockGen operating lease agreement and write-off of the related prepaid lease expense, $98 million resulting from settlements and repudiation of certain natural gas transportation and PPA contracts, and an additional accrual of $79 million resulting from the rejection of certain leases and other agreements related to the Rumford and Tiverton power plants for which we agreed to allow general unsecured claims in the aggregate of $190 million.

Professional and Trustee Fees — The decrease in professional fees for the year ended December 31, 2008, over the comparable period in 2007 resulted primarily from a decrease in activity managed by our third party advisors related to our Chapter 11 and CCAA cases.

Gains on Asset Sales — During the year ended December 31, 2008, gains on asset sales primarily resulted from the sales of the Hillabee and Fremont development project assets. During the year ended December 31, 2007, gains on asset sales primarily resulted from the sale of the Aries Power Plant, Goldendale Energy Center, PSM and Parlin Power Plant during 2007. See Note 6 of the Notes to Consolidated Financial Statements for further information.

Asset Impairments — During the year ended December 31, 2007, asset impairment charges were primarily due to a pre-tax impairment charge of approximately $89 million to record our interest in Acadia PP at fair value less cost to sell.

Gain on Reconsolidation of Canadian Debtors and Other Deconsolidated Foreign Entities — During the year ended December 31, 2008, we recorded a gain of $71 million related to the reconsolidation of our Canadian subsidiaries. See Note 2 of the Notes to Consolidated Financial Statements for further information.

DIP Facility and First Lien Facilities Financing and CalGen Secured Debt Repayment Costs — During the year ended December 31, 2008, we recorded a $4 million credit related to a valuation revision for secured shortfall claims related to our Second Priority Debt. During the year ended December 31, 2007, we recorded costs related to the refinancing of our Original DIP Facility and repayment of the CalGen Secured Debt consisting of $52 million of DIP Facility transaction costs, the write-off of $32 million in unamortized discount and deferred financing costs related to the CalGen Secured Debt, and $76 million as our estimate of the expected allowed claims resulting from the unsecured claims for damages granted to the holders of the CalGen Secured Debt. We also recorded transaction costs of $22 million related to the execution of a commitment letter to fund our First Lien Facilities as well as $13 million for secured shortfall claims relating to settlements for the First Priority Notes and the CalGen First Lien Debt during the year ended December 31, 2007.

Interest (Income) on Accumulated Cash — The decrease in interest income on accumulated cash for the year ended December 31, 2008, over the comparable period in 2007 related to our emergence from Chapter 11 at which time we ceased allocating a portion of interest income to reorganization items.

Other  — Other reorganization items decreased primarily due to recording a gain of $4 million during the year ended December 31, 2008, versus a loss of $164 million in the year ended December 31, 2007, related to foreign exchange movements on LSTC denominated in a foreign currency and the non-recurrence of a charge of $14 million during the year ended December 31, 2007, resulting from debt pre-payment and make whole premium fees to the project lenders related to the sale of the Aries Power Plant. Also contributing to the decrease was $53 million in emergence incentive cost accruals related to our emergence from Chapter 11 recorded during the year ended December 31, 2007, while no such accruals were recorded in 2008.

For the year ended December 31, 2008, we recorded a tax benefit of $56 million before discontinued operations compared to a benefit of $546 million for the year ended December 31, 2007. Due to the valuation allowances recorded against certain deferred tax assets, our effective tax rate differs considerably from the federal statutory rate. Our tax structure is comprised primarily of two taxable groups, CCFC and its subsidiaries and Calpine Corporation and its subsidiaries other than CCFC. CCFC and its subsidiaries no longer have a valuation allowance recorded against its deferred tax assets due to its ability to generate sufficient income to utilize its NOLs. Our 2008 benefit for income taxes before discontinued operations primarily relates to a foreign tax benefit of $70 million recorded as a result of the Canadian Settlement Agreement, and intraperiod tax allocation benefit of $99 million, which was comprised of a $76 million tax benefit to continuing operations due to current OCI gains and a $23 million tax benefit in income from discontinued operations, both of which are reflected in deferred tax benefit, offset by tax expense of approximately $100 million on

13

CCFC’s income. Our 2007 benefit for income taxesconsisting primarily of $485 million related to the release of valuation allowance in 2007. See Note 11 of the Notes to Consolidated Financial Statements for further information.

During the year ended December 31, 2008, we recorded $36 million in income from discontinued operations, net of taxes of $23 million, related to the results of operations of Blue Spruce and Rocky Mountain as well as the settlement with Rosetta of all of our outstanding claims related to our domestic oil and gas assets we sold to Rosetta for $1.1 billion in 2005. During the year ended December 31, 2007, we recorded $27 million in income from discontinued operations related to the results of operations of Blue Spruce and Rocky Mountain. See Note 6 of the Notes to Consolidated Financial Statements for further information.

COMMODITY MARGIN AND ADJUSTED EBITDA

Management’s Discussion and Analysis of Financial Condition and Results of Operations includes financial information prepared in accordance with 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. Generally, a non-GAAP financial measure is a numerical measure of financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP.

Commodity Margin by Segment for the Years Ended December 31, 2009 and 2008

We use the non-GAAP financial measure “Commodity Margin” 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, RGGI compliance 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 GAAP, and should be viewed as a supplement to and not a substitute for our results of operations presented in accordance with GAAP. Commodity Margin does not intend to represent gross profit (loss), the most comparable GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly-titled measures reported by other companies. See Note 18 of the Notes to Consolidated Financial Statements for a reconciliation of Commodity Margin to income (loss) from operations by segment.

The following tables show our Commodity Margin and related operating performance metrics by segment for the years ended December 31, 2009 and 2008. Our Commodity Margin and related operating performance metrics in our West segment have been recast to exclude Blue Spruce and Rocky Mountain, which are reported as discontinued operations. During the first quarter of 2009, we began assessing the performance of our regional segments to include the allocation (based upon each regional segment’s MWh) of revenues and expenses from our fuel management, Turbine Maintenance Group and certain non-region specific natural gas marketing and optimization and other corporate activities, which had formerly been separately reported as our “Other” segment. Additionally, we have modified our definition of Commodity Margin to include cash settlements from our marketing, hedging and optimization activities that were previously included in mark-to-market activity. Our 2008 Commodity Margin by segment information has been recast to conform to the current year presentation. In the “Change” and “% Change” columns below, favorable variances are shown without brackets while unfavorable variances are shown with brackets. The MWh generated by segment below represents generation from power plants that we both consolidated and operate.

West:	2009			2008			Change			% Change
Commodity Margin (in millions)	$	1,245		$	1,155		$	90			8	%
Commodity Margin per MWh generated	$	38.82		$	34.53		$	4.29			12
MWh generated (in thousands)		32,070			33,453			(1,383	)		(4	)
Average availability		92.1	%		88.2	%		3.9			4
Average total MW in operation		6,371			6,364			7			—
Average capacity factor, excluding peakers		64.0	%		66.5	%		(2.5	)		(4	)
Steam Adjusted Heat Rate		7,314			7,271			(43	)		(1	)

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West — Commodity Margin in our West segment increased by $90 million, or 8%, for the year ended December 31, 2009 compared to the year ended December 31, 2008. The increase was primarily a result of higher hedge levels and prices, sales of surplus emission allowances in the first quarter of 2009 and higher resource adequacy and REC revenues in 2009 compared to 2008. Market Heat Rates remained relatively unchanged across periods, and lower natural gas prices resulted in lower market spark spreads for the year ended December 31, 2009 compared to 2008. In addition, the current period benefited from the non-recurrence in 2009 of an unfavorable natural gas storage inventory price adjustment in September 2008. Consistent with the weaker price conditions, generation decreased 4% for the year ended December 31, 2009 compared to 2008, despite a 4% increase in our average availability. Commodity Margin per MWh generated increased 12% due in part to the effect of our positive portfolio hedge value being allocated across a reduced number of generated MWh for the year ended December 31, 2009 as compared to 2008.

Texas:	2009			2008			Change			% Change
Commodity Margin (in millions)	$	644		$	726		$	(82	)		(11	)%
Commodity Margin per MWh generated	$	21.69		$	22.40		$	(0.71	)		(3	)
MWh generated (in thousands)		29,687			32,408			(2,721	)		(8	)
Average availability		90.0	%		88.8	%		1.2			1
Average total MW in operation		7,156			7,147			9			—
Average capacity factor, excluding peakers		47.4	%		51.6	%		(4.2	)		(8	)
Steam Adjusted Heat Rate		7,142			7,082			(60	)		(1	)

Texas — Commodity Margin in our Texas segment decreased by $82 million, or 11%, for the year ended December 31, 2009 compared to 2008. This decrease is primarily attributable to weaker natural gas prices that were 56% lower in 2009 compared to 2008. Overall, Market Heat Rates were relatively unchanged in 2009 compared to 2008; however, Market Heat Rates were higher in the third quarter of 2009 compared to the same period in 2008 due to warmer than average weather and lower in the second quarter of 2009 compared to the same period in 2008 due to the congestion-driven pricing environment of the second quarter of 2008. Also contributing to the overall decrease in Commodity Margin was lower steam sales resulting from weaker industrial demand in 2009 compared to 2008. Despite a 1% increase in average availability, generation decreased 8% on softer demand in the first half of 2009 and weaker Market Heat Rates in the second quarter of 2009. We experienced a 1% increase in our Steam Adjusted Heat Rate for the year ended December 31, 2009 compared to 2008, resulting from lower steam sales in 2009 compared to 2008.

Southeast:	2009			2008			Change			% Change
Commodity Margin (in millions)	$	304		$	264		$	40			15	%
Commodity Margin per MWh generated	$	17.50		$	20.59		$	(3.09	)		(15	)
MWh generated (in thousands)		17,370			12,820			4,550			35
Average availability		93.2	%		93.6	%		(0.4	)		—
Average total MW in operation		6,083			6,183			(100	)		(2	)
Average capacity factor, excluding peakers		37.9	%		26.6	%		11.3			42
Steam Adjusted Heat Rate		7,299			7,388			89			1

Southeast — Commodity Margin in our Southeast segment increased by $40 million, or 15%, for the year ended December 31, 2009 compared to 2008. The increase was driven by a 35% increase in generation which resulted from higher natural gas generation displacement of coal generation in certain sub-markets in our Southeast segment primarily caused by lower natural gas prices resulting in higher Market Heat Rates in 2009 compared to 2008. Commodity Margin in the Southeast was also positively affected in 2009 compared to 2008, by the favorable impact of an off-take agreement at one of our power plants and incremental natural gas hedges. The benefit from these positive performance factors was partially offset by the negative impact from the settlement of a disputed steam contract, which adversely impacted operating revenues in 2009. In addition, a gain of $21 million related to the temporary assignment of a transmission capacity contract in the second quarter of 2008 led to a reduction in relative year over year performance. We experienced a 1% decrease in our Steam Adjusted Heat Rate in 2009 compared to 2008, resulting from increased generation. The 100 MW, or 2%, decrease in our average total MW in operation for the year ended December 31, 2009 compared to 2008, was due to the deconsolidation of Auburndale in the third quarter of 2008.

North:	2009			2008			Change			% Change
Commodity Margin (in millions)	$	268		$	279		$	(11	)		(4	)%
Commodity Margin per MWh generated	$	51.06		$	51.70		$	(0.64	)		(1	)
MWh generated (in thousands)		5,249			5,397			(148	)		(3	)
Average availability		94.7	%		92.6	%		2.1			2
Average total MW in operation		2,873			2,412			461			19
Average capacity factor, excluding peakers		31.1	%		32.8	%		(1.7	)		(5	)
Steam Adjusted Heat Rate		7,614			7,584			(30	)		—

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North — Commodity Margin in our North segment decreased by $11 million, or 4%, for the year ended December 31, 2009 compared to 2008. Although market spark spreads were lower in 2009 compared to 2008, the impact was largely mitigated by our hedge position as well as the favorable impact of the reconsolidation of RockGen in December 2008. In addition, despite a 2% increase in our average availability, generation decreased 3% due primarily to lower Market Heat Rates in certain sub-markets in our North segment for the year ended December 31, 2009 compared to 2008. The 461 MW, or 19%, increase in our average total MW in operation for the year ended December 31, 2009 compared to 2008, was due to the reconsolidation of RockGen in December 2008.

Commodity Margin by Segment for the Years Ended December 31, 2008 and 2007

The following tables show our Commodity Margin and related operating performance metrics by segment for the years ended December 31, 2008 and 2007. Our Commodity Margin and related operating performance metrics in our West segment have been recast to exclude Blue Spruce and Rocky Mountain, which are reported in discontinued operations. Our 2008 and 2007 Commodity Margin by segment information has been recast to conform to the current year presentation. In the “Change” and “% Change” columns below, favorable variances are shown without brackets while unfavorable variances are shown with brackets. The MWh generated by segment below represents generation from power plants that we both consolidated and operate.

West:	2008			2007			Change			% Change
Commodity Margin (in millions)	$	1,155		$	1,071		$	84			8	%
Commodity Margin per MWh generated	$	34.53		$	32.66		$	1.87			6
MWh generated (in thousands)		33,453			32,789			664			2
Average availability		88.2	%		90.1	%		(1.9	)		(2	)
Average total MW in operation		6,364			6,389			(25	)		—
Average capacity factor, excluding peakers		66.5	%		65.2	%		1.3			2
Steam Adjusted Heat Rate		7,271			7,304			33			—

West — Commodity Margin in our West segment increased by $84 million, or 8%, for the year ended December 31, 2008, compared to the year ended December 31, 2007. The increase resulted primarily from higher on-peak market spark spreads driven by higher natural gas prices and the favorable impact of new and renegotiated power contracts for 2008. The Commodity Margin increase associated with the much stronger commodity price environment was largely reflected in an $88 million year over year increase in the realized value of non-region specific gas hedges and the settlement of commodity derivative instruments. The increase in Commodity Margin was partially offset by lower realized margins in the fourth quarter of 2008 as compared to the same period in 2007, and a negative year on year variance associated with natural gas storage inventory. In 2008, we recorded a loss on natural gas storage resulting from the decrease in market natural gas prices in late summer through the fourth quarter of 2008, while in the fourth quarter of 2007 we recognized a positive impact from sales of natural gas storage inventory.

Texas:	2008			2007			Change			% Change
Commodity Margin (in millions)	$	726		$	505		$	221			44	%
Commodity Margin per MWh generated	$	22.40		$	15.23		$	7.17			47
MWh generated (in thousands)		32,408			33,154			(746	)		(2	)
Average availability		88.8	%		90.8	%		(2.0	)		(2	)
Average total MW in operation		7,147			7,146			1			—
Average capacity factor, excluding peakers		51.6	%		53.0	%		(1.4	)		(3	)
Steam Adjusted Heat Rate		7,082			6,830			(252	)		(4	)

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Texas — Commodity Margin in our Texas segment increased by $221 million, or 44%, for the year ended December 31, 2008, compared to 2007, due primarily to higher market spark spreads driven by higher natural gas prices during the second and third quarters of 2008 and congestion pricing in the South and Houston zones in the second quarter of 2008. Commodity Margin was also improved by higher realized spark spreads on hedged positions in the fourth quarter of 2008 despite lower market spark spreads during the same period. Market spark spreads decreased in September 2008 as compared to the same period in 2007 due to the impact of Hurricane Ike; however, we were able to purchase replacement power at prices below our generation cost and hedged prices during the same period, which had a favorable impact in September 2008. Included in the favorable year on year comparison is a decrease in Commodity Margin as a result of an unfavorable year over year impact of $94 million from the allocation of non-region specific natural gas hedges and the settlement of commodity derivative instruments. Generation in our Texas segment decreased by 2% due to an increase in planned outages for major maintenance for the year ended December 31, 2008 compared to 2007. We experienced a 4% increase in our Steam Adjusted Heat Rate for the year ended December 31, 2008 compared to 2007, resulting from the loss of steam load due to the impact of Hurricane Ike, an extended outage at our Baytown power plant in the first and second quarters of 2008 and lower steam demand from our customers during the second half of 2008.

Southeast:	2008			2007			Change			% Change
Commodity Margin (in millions)	$	264		$	256		$	8			3	%
Commodity Margin per MWh generated	$	20.59		$	17.30		$	3.29			19
MWh generated (in thousands)		12,820			14,795			(1,975	)		(13	)
Average availability		93.6	%		92.1	%		1.5			2
Average total MW in operation		6,183			7,204			(1,021	)		(14	)
Average capacity factor, excluding peakers		26.6	%		25.6	%		1.0			4
Steam Adjusted Heat Rate		7,388			7,544			156			2

Southeast — Commodity Margin in our Southeast segment increased by $8 million, or 3%, for the year ended December 31, 2008 compared to 2007, resulting from the impact of more favorable hedge pricing, the favorable impact of new power contracts and a gain of $21 million during the second quarter of 2008 related to the temporary assignment of a transmission capacity contract. These increases were partially offset by a decrease in market spark spreads realized on open positions for 2008 compared to 2007 and an unfavorable year over year impact of $24 million from the allocation of non-region specific natural gas hedges and the settlement of commodity derivative instruments. We experienced a 4% increase in our average capacity factor, excluding peakers, and a 2% increase in our average availability for the year ended December 31, 2008 compared to 2007. Despite higher availability, generation decreased 13% due to a 1,021 MW decrease in our average total MW in operation following the sale of our interest in Acadia PP in 2007, the sale of Auburndale in 2008 and an unplanned outage at our Carville power plant due to Hurricane Gustav during the third quarter of 2008.

North:	2008			2007			Change			% Change
Commodity Margin (in millions)	$	279		$	278		$	1			—	%
Commodity Margin per MWh generated	$	51.70		$	46.14		$	5.56			12
MWh generated (in thousands)		5,397			6,025			(628	)		(10	)
Average availability		92.6	%		87.4	%		5.2			6
Average total MW in operation		2,412			3,009			(597	)		(20	)
Average capacity factor, excluding peakers		32.8	%		33.2	%		(0.4	)		(1	)
Steam Adjusted Heat Rate		7,584			7,646			62			1

North — Commodity Margin in our North segment increased by $1 million resulting from higher hedged levels at more favorable pricing during the third quarter of 2008 compared to the same period in 2007 and a $4 million favorable year over year impact from the allocation of non-region specific natural gas hedges and the settlement of commodity derivative hedging instruments. These gains were largely offset by lower realized spark spreads during the fourth quarter of 2008 compared to the same period in 2007 and the deconsolidation of RockGen in January 2008. Generation in the North decreased 10% due primarily to lower generation at power plants whose generation is contracted and controlled by third parties and outages at our Westbrook Energy Center power plant during the second quarter of 2008.

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Adjusted EBITDA

We define Adjusted EBITDA as EBITDA adjusted for certain items described below and presented in the accompanying reconciliation. Adjusted EBITDA is not a measure calculated in accordance with GAAP, and should be viewed as a supplement to and not a substitute for our results of operations presented in accordance with GAAP. Our First Lien Credit Facility and certain of our other debt instruments, including the Commodity Collateral Revolver, include a similar measure as a basis for our material covenants under those debt agreements that excludes our net interest in our unconsolidated subsidiaries and includes distributions received from unconsolidated investments. However, we believe that inclusion of our share of the Adjusted EBITDA of our unconsolidated subsidiaries is useful in evaluating our overall performance and therefore we include Adjusted EBITDA from our unconsolidated investments and exclude distributions received from our unconsolidated investments in our definition of Adjusted EBITDA. Adjusted EBITDA is not intended to represent cash flows from operations or net income (loss) as defined by GAAP as an indicator of operating performance. Furthermore, Adjusted EBITDA is not necessarily comparable to similarly-titled measures reported by other companies.

We believe Adjusted EBITDA is also used by and is useful to investors and other users of our financial statements in evaluating our operating performance because it provides them with an additional tool to compare business performance across companies and across periods. We believe that EBITDA is widely used by investors to measure a company’s operating performance without regard to items such as interest expense, taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired.

Additionally, we believe that investors commonly adjust EBITDA information to eliminate the effect of restructuring and other expenses, which vary widely from company to company and impair comparability. As we define it, Adjusted EBITDA represents EBITDA adjusted for the income effects of impairment charges, non-cash gains or losses on sales or dispositions of assets, any unrealized gains or losses and any non-cash realized gains or losses from accounting for derivatives, stock-based compensation expense, operating lease expense, non-cash gains and losses from intercompany foreign currency translations, reorganization items, major maintenance expense, gains or losses on the repurchase or extinguishment of debt and any other extraordinary, unusual or non-recurring items plus adjustments to reflect the Adjusted EBITDA from our unconsolidated investments. We exclude these items from Adjusted EBITDA as our management believes that these items would distort their ability to efficiently view and assess our core operating trends.

In summary, our management uses Adjusted EBITDA as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with our Board of Directors, shareholders, creditors, analysts and investors concerning our financial performance.

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The tables below provide a reconciliation of Adjusted EBITDA to our income (loss) from operations on a segment basis and to net income attributable to Calpine on a consolidated basis for years ended December 31, 2009, 2008 and 2007 (in millions). Adjusted EBITDA from West segment for the years ended December 2009, 2008 and 2007 has been recast to present discontinued operations from Blue Spruce and Rocky Mountain.

	2009
											Consolidation
											and
	West			Texas		Southeast		North			Elimination			Total
Net income attributable to Calpine														$	149
Net loss attributable to noncontrolling interest															(4	)
Discontinued operations, net of tax expense															(35	)
Income tax expense															15
Reorganization items															(1	)
Other (income) expense and debt extinguishment costs, net															90
Interest expense, net															799
Income from operations	$	681		$	166	$	47	$	126		$	(7	)	$	1,013
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs(1)		186			130		84		67			(8	)		459
Impairment loss		4			—		—		—			—			4
Major maintenance expense		81			49		32		5			—			167
Operating lease expense		21			—		—		26			—			47
Unrealized (gains) losses on commodity derivative mark-to-market activity		(110	)		59		14		(42	)		—			(79	)
Adjustments to reflect Adjusted EBITDA from unconsolidated investments(2)(3)		(16	)		—		—		33			—			17
Stock-based compensation expense		17			12		6		3			—			38
Non-cash loss on dispositions of assets		11			14		5		2			—			32
Other		2			—		—		—			—			2
Adjusted EBITDA from continuing operations		877			430		188		220			(15	)		1,700
Adjusted EBITDA from discontinued operations		82			—		—		—			—			82
Total Adjusted EBITDA	$	959		$	430	$	188	$	220		$	(15	)	$	1,782

19

	2008(4)
													Consolidation
													and
	West			Texas			Southeast			North			Elimination			Total
Net income attributable to Calpine																$	10
Net loss attributable to noncontrolling interest																	(1	)
Discontinued operations, net of tax expense																	(36	)
Income tax benefit																	(56	)
Reorganization items																	(302	)
Other (income) expense and debt extinguishment costs, net																	21
Interest expense, net																	998
Income (loss) from operations	$	320		$	427		$	(168	)	$	37		$	18		$	634
Add:
Adjustments to reconcile income (loss) from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs(1)		177			129			92			56			(5	)		449
Impairment loss		13			—			213			—			—			226
Major maintenance expense		89			62			20			14			(1	)		184
Operating lease expense		21			—			—			25			—			46
Non-cash realized gains on derivatives		—			(40	)		—			—			—			(40	)
Unrealized (gains) losses on commodity derivative mark-to-market activity		86			(138	)		(27	)		44			—			(35	)
Adjustments to reflect Adjusted EBITDA from unconsolidated investments(2)(3)		55			—			6			15			—			76
Stock-based compensation expense		23			16			8			3			—			50
Non-cash loss on dispositions of assets		9			12			10			3			(1	)		33
Other		(6	)		3			—			(1	)		—			(4	)
Adjusted EBITDA from continuing operations		787			471			154			196			11			1,619
Adjusted EBITDA from discontinued operations		80			—			—			—			—			80
Total Adjusted EBITDA	$	867		$	471		$	154		$	196		$	11		$	1,699

20

	2007(4)
												Consolidation
												and
	West		Texas			Southeast			North			Elimination			Total
Net income attributable to Calpine															$	2,693
Net loss attributable to noncontrolling interest																—
Discontinued operations, net of tax expense																(27	)
Income tax benefit																(546	)
Reorganization items																(3,258	)
Other (income) expense and debt extinguishment costs, net																(141	)
Interest expense, net																1,927
Income (loss) from operations	$	450	$	175		$	(12	)	$	38		$	(3	)	$	648
Add:
Adjustments to reconcile income (loss) from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs(1)		196		129			113			55			(3	)		490
Impairment loss		10		—			2			34			—			46
Major maintenance expense		28		38			14			12			(1	)		91
Operating lease expense		20		—			—			34			—			54
Non-cash realized (gains) losses on derivatives		4		(62	)		3			1			—			(54	)
Unrealized (gains) losses on commodity derivative mark-to-market activity		15		16			2			2			—			35
Adjustments to reflect Adjusted EBITDA from unconsolidated investments(2)(3)		8		—			—			13			—			21
Stock-based compensation expense (income)		—		—			—			—			—			—
Non-cash loss on dispositions of assets		9		11			5			5			—			30
Other		1		(5	)		9			(3	)		—			2
Adjusted EBITDA from continuing operations		741		302			136			191			(7	)		1,363
Adjusted EBITDA from discontinued operations		82		—			—			—			—			82
Total Adjusted EBITDA	$	823	$	302		$	136		$	191		$	(7	)	$	1,445

__________

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

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

(3) Adjustments to reflect Adjusted EBITDA from unconsolidated investments include $(47) million, $55 million and $17 million in unrealized (gains) losses on mark-to-market activity for the years ended December 31, 2009, 2008 and 2007, respectively.

(4) Our calculation of Adjusted EBITDA for 2008 and 2007 has been recast to conform to our 2009 presentation.

21

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 and to meet certain near-term debt repayment obligations is dependent on maintaining sufficient liquidity.

Liquidity

As of December 31, 2009, we had $989 million in cash and cash equivalents and $562 million of restricted cash. Our availability under our First Lien Credit Facility revolver as of December 31, 2009, is $794 million for future letters of credit or cash borrowings. The following table provides a summary of our liquidity position at December 31, 2009 and 2008 (in millions):

	2009		2008
Cash and cash equivalents, corporate(1)	$	725	$	1,361
Cash and cash equivalents, non-corporate		264		296
Total cash and cash equivalents		989		1,657
Restricted cash		562		503
Letter of credit availability(2)		34		2
Revolver availability(3)		794		16
Total current liquidity availability(4)	$	2,379	$	2,178

__________

(1) Includes $9 million and $169 million of margin deposits held by us posted by our counterparties as of December 31, 2009 and 2008, respectively.

(2) Additional available balances for Calpine Development Holdings, Inc. As of December 31, 2009, we have the option to increase our availability by an additional $50 million under this letter of credit facility by satisfying certain conditions.

(3) We repaid $725 million previously drawn on our First Lien Credit Facility revolver on September 28, 2009.

(4) Excludes contingent amounts of $150 million under the Knock-in Facility and $200 million under the Commodity Collateral Revolver as of December 31, 2008.

Volatility in the financial markets in late 2008 and continuing into 2009, including the failure or merger of certain financial institutions and continued uncertainty surrounding the stability of others continues to constrict access to capital and credit markets in the U.S. and worldwide, including within our industry, for us and for our counterparties. As a result, we and the industry have experienced increased credit and liquidity risk over the past year. Although there have been some signs of economic recovery, we are unable to predict the timing, strength or related impacts that a recovery, if any, will have on us, our counterparties or the current volatility in the financial markets. Additionally, while we have been successful in completing significant financing transactions in 2009, we cannot provide any assurance that we will continue to be successful in the future. Consequently, current uncertain economic conditions and volatile financial markets may persist during 2010 or possibly longer. Even if we are not impacted directly, we could be impacted indirectly in the event our counterparties are unable to perform under their contractual obligations with us. We actively monitor our exposure to our counterparties including their credit status.

Downward pressure on our Commodity Margin continues to be a risk as a result of the current economic conditions. As of December 31, 2009, 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 2010; however, we remain susceptible to significant price movements for 2011 and beyond. The future impact on our Commodity Margin, primarily beyond 2010, is highly dependent on the severity and duration of the economic downturn, the speed, strength and duration of an economic recovery, if any, and our continued ability to successfully hedge our Commodity Margin. During pronounced recessionary periods, there can be a decrease in power demand primarily driven by decreased usage by the industrial and manufacturing sectors. This “softening” of demand typically results in more demand satisfied by baseload and intermediate units using lower variable cost fuel sources, such as coal and nuclear fuel, and less demand served by higher variable cost units such as natural gas-fired peaker power plants. Additionally, a recessionary environment can result in lower natural gas prices, which may adversely impact our Commodity Margin as our cost of production advantage relative to less efficient natural gas-fired generation is diminished on an absolute basis.

22

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 February 5, 2010, an increase of $1/MMBtu in natural gas prices would result in an increase of collateral required by approximately $46 million. If natural gas prices decreased by $1/MMBtu, we estimate that our collateral requirements would decrease by approximately $19 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 $1/MMBtu in natural gas approximates an average Market Heat Rate change of 170 Btu/KWh. We estimate that as of February 5, 2010, an increase of 170 Btu/KWh in the Market Heat Rate would result in an increase in collateral required by approximately $23 million. If Market Heat Rates were to fall at a similar rate, we estimate that our collateral required would decrease by $23 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 First Lien Notes, 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. During 2009, we have increased our usage of these additional liens in order to help manage cash collateral that would otherwise be required. See Note 10 of the Notes to Consolidated Financial Statements for further information on our margin deposits and collateral used for commodity procurement and risk management activities.

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 the economic downturn persist for a significant period of time; however, 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. 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 First Lien Credit Facility, First Lien Notes and other existing financing obligations;

• stabilizing and increasing future contractual cash flows; and

• our significant counterparties performing under their contracts with us.

Capital Resources and Management

During 2009, we have opportunistically completed several financing transactions to strengthen our balance sheet and improve our flexibility and management of our capital structure. For a more detailed discussion of our 2009 financing transactions, our debt and related terms, see Note 7 of the Notes to Consolidated Financial Statements. Significant 2009 financing transactions are summarized below.

Steamboat Amended Credit Facility — On November 24, 2009, Steamboat amended and extended the terms of its credit agreement. The Steamboat Amended Credit Facility increases the amount of term loans outstanding by $17 million from $448 million to $465 million. The increase in the borrowing was used to pay accrued and unpaid interest, breakage costs and other fees in connection with closing the Steamboat Amended Credit Facility. The Steamboat Amended Credit Facility also provides for a “security fund” letter of credit facility of up to $11 million and a “DSR” letter of credit facility of up to approximately $23 million. The maturity date of the term loans has been extended from December 2011 to November 24, 2017. The security fund letter of credit facility matures on November 24, 2017 with the term loans and the DSR letter of credit facility matures on September 29, 2017.

23

Amendment of First Lien Credit Facility and Issuance of First Lien Notes due 2017 — We executed the First Amendment to Credit Agreement and Second Amendment to Collateral Agency and Intercreditor Agreement dated as of August 20, 2009, which amended both the First Lien Credit Facility Credit Agreement and the First Lien Credit Facility Collateral Agency and Intercreditor Agreement. The amendment provides additional flexibility with our capital structure and First Lien Credit Facility by granting us the option, subject to certain conditions, to buy back debt at a discount using cash on hand via an auction process; to offer first lien bonds in exchange for or to retire First Lien Credit Facility term loans; to issue up to $2.0 billion of first lien bonds in lieu of issuing first lien term loans under the accordion provision of our First Lien Credit Facility; and to extend all or a portion of the revolver and term loan maturities, on revised terms, subject to acceptance by applicable lenders. In addition, the amendment provides for the aggregation of various investment and capital expenditure baskets for covenant purposes. We subsequently issued approximately $1.2 billion aggregate principal amount of First Lien Notes in a private placement on October 21, 2009. We received no net cash proceeds from the transaction. The offer and sale of our First Lien Notes was consummated as a permitted debt exchange pursuant to our First Lien Credit Facility in exchange for a like principal amount of First Lien Credit Facility term loans. Upon their exchange for First Lien Notes, such term loans were canceled and may not be redrawn.

CCFC Refinancing — On May 19, 2009, our wholly owned subsidiaries, CCFC and CCFC Finance, issued approximately $1.0 billion aggregate principal amount of CCFC New Notes in a private placement. The CCFC New Notes mature on June 1, 2016. The CCFC New Notes are not guaranteed by Calpine Corporation and are without recourse to Calpine Corporation or any of our other non-CCFC or CCFC Finance subsidiaries or assets. The net proceeds received of $939 million, together with CCFC cash on hand of $271 million, were used to:

• repay the $364 million outstanding under the CCFC Term Loans on May 19, 2009;

• redeem the $415 million outstanding principal amount of CCFC Old Notes on June 18, 2009;

• distribute $327 million to CCFC’s indirect parent, CCFCP, which was used by CCFCP to redeem its $300 million CCFCP Preferred Shares on or before July 1, 2009; and

• in each case, pay any interest, prepayment penalties and other amounts due through the date of such repayment or redemption.

As a result of the CCFC Refinancing transactions, we were able to extend the maturities of approximately $1.0 billion of debt by several years, at the same time converting it from a floating to a fixed interest rate and lowering our effective interest rate on such debt to 8.0% from a current weighted average interest rate of approximately 9.4% with respect to the CCFC Term Loans, CCFC Old Notes and CCFCP Preferred Shares.

Concurrent with the CCFC Refinancing, we replaced various intercompany agreements with our CCFC subsidiaries for the related sales and purchases of power, natural gas and the operation and maintenance of our CCFC power plants, which did 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 CCFC New Notes to Calpine Corporation, a substantial portion of the commodity price risk related to CCFC’s power generation is absorbed by Calpine Corporation as an indirect wholly owned subsidiary of Calpine Corporation purchases the power generated by CCFC under an intercompany tolling agreement, which is also guaranteed by Calpine Corporation.

Deer Park Financing — On January 21, 2009, Deer Park, our indirect wholly owned subsidiary, closed on $156 million of senior secured credit facilities, which include a $150 million term facility and a $6 million letter of credit facility. Proceeds received were used to settle an existing commodity contract of approximately $79 million, pay financing and legal fees of approximately $8 million and fund approximately $22 million in restricted cash. The remainder was distributed to Calpine Corporation for general corporate purposes. The senior term loan facility matures on January 21, 2012.

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

	2009
First Lien Credit Facility	$	206
Calpine Development Holdings, Inc.		116
Various project financing facilities		90
Total	$	412

24

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 prohibited 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.

NOLs  — We have significant NOLs that will provide future tax deductions if we generate sufficient taxable income, and do not become subject to significant limitations under Section 382 of the IRC 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 consists of approximately $7.0 billion from the Calpine group and approximately $513 million from the CCFC group. Approximately $5.5 billion of our NOLs have annual limitations under Section 382 of the IRC. Subject to limitations, Section 382 amounts not used can be carried forward to succeeding years. In addition, as of December 31, 2009, we have approximately $1.1 billion in foreign NOLs and $4.6 billion in state NOLs on a consolidated basis. The Calpine group has recorded a valuation allowance against the deferred taxes related to most of their NOLs as we determined it is more likely than not that they will expire unutilized.

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. 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 outstanding project debt at closing 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. Our results of operations for Blue Spruce and Rocky Mountain are reported as discontinued operations on our Consolidated Condensed Statements of Operations for the three years ended December 31, 2009, 2008 and 2007, respectively. However, there was no change to our total consolidated net income and there was no effect on our Consolidated Balance Sheets, Consolidated Statements of Comprehensive Income (Loss) and Stockholders’ Equity (Deficit) or our Consolidated Statements of Cash Flows.

Project Development, Upgrades and Growth Initiatives

We continue to review development opportunities, which were put on hold during the pendency of our Chapter 11 cases, to determine whether future actions are appropriate and we may pursue new opportunities that arise, particularly if power contracts and financing are available and attractive returns are expected.

OMEC — OMEC began commercial operations on October 3, 2009. The completion of OMEC added approximately 608 MW of baseload (with peaking) capacity representing our unconsolidated net interest in the power plant.

Russell City Energy Center — Russell City Energy Center remains under advanced 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 was approved by the CPUC on April 16, 2009. On February 4, 2010, we received the PSD air permit, the final permit necessary, to begin construction of our Russell City Energy Center. We hope to complete financing and break ground for this new state-of-the-art power plant during 2010 with commercial operations scheduled to begin in 2013. We do not expect the costs to complete the Russell City Energy Center to be material to us on a consolidated basis. Upon completion, this project would bring on line approximately 362 MW of net interest baseload capacity (390 MW with peaking capacity) representing our 65% interest.

25

Los Esteros Critical Energy Center — During 2009, we and PG&E negotiated a new agreement to replace the existing CDWR 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.

Geysers Development and Investment Tax Credits — 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, that could impact our growth and development of our Geysers Assets. Specifically, the Stimulus Bill:

• extends the placed-in-service deadline through 2013 for geothermal projects to qualify for “production tax credits”;

• allows geothermal developers to elect to receive a 30% “investment tax credit” in lieu of production tax credits with respect to certain new construction of “qualified property” placed in service during 2009 or 2010 (or, in certain cases, after 2010), or 10% on re-powering of existing power plants or a cash grant in lieu of investment tax credits or production tax credits with respect to such qualified property (subject to satisfying certain procedural and other requirements mandated by recently-issued Department of Treasury guidance); and

• designates $6.0 billion in funds to serve as a loss reserve and source of funding for a federal loan guarantee program anticipated to backstop renewable energy project financing.

In December 2009, we filed for cash grants of approximately $2 million in lieu of the 10% investment tax credit on two of our re-power projects. We expect that any new geothermal power plant development of our Geysers Assets will qualify for the 30% investment tax credit from the U.S. Internal Revenue Service, and our additional projects for the re-powering of our existing power plants will qualify for the 10% investment tax credit.

Major Maintenance and Capital Spending — Our major maintenance and capital spending remains an important part of our business. Our expected expenditures for 2010 are the following (in millions):

	2010
Major maintenance expense	$	178
Capital expenditures, operations		112
Total		290
Turbine upgrades and Geysers Assets expansion		50
Total major maintenance expense and capital spending	$	340

We believe that upgrades and expansions to our current assets offer proven and financially disciplined opportunities to improve our operations, capacity and efficiencies. We are in the process of upgrading certain of our Siemens turbines to increase our generation capacity by approximately 180 MW. These upgrades began in the fourth quarter of 2009 and are scheduled through 2014 with estimated remaining capital expenditures of approximately $87 million as of December 31, 2009. Our expected capital expenditures for each of the next five years for major maintenance and for operations are expected to average approximately $300 million.

These amounts do not include approximately $85 million, which we expect to incur in 2010 for the new construction for Russell City Energy Center and upgrade of the Los Esteros Critical Energy Facility.

Prior Asset Sales and Purchase — A significant component of our restructuring activities was to return our focus to our core strategic assets. As a result of the review of our asset portfolio performed during our Chapter 11 restructuring, during 2008 and 2007, we have sold or otherwise disposed of the Fremont and Hillabee development projects, our equity interests in Auburndale and Acadia PP and our assets related to the Parlin Power Plant, PSM, Goldendale Energy Center and the Aries Power Plant. In addition, we purchased the assets of the RockGen Energy Center in 2008. See Notes 4 and 6 of the Notes to Consolidated Financial Statements for additional discussion of these asset sales and purchase. While we have made no significant asset dispositions or purchases in 2009, we continually evaluate our portfolio of assets and may take such actions in the future if we believe they will optimize our existing assets.

26

Cash Flow Activities

The following table summarizes our cash flow activities for the years ended December 31, 2009, 2008 and 2007 (in millions):

	2009			2008			2007
Beginning cash and cash equivalents	$	1,657		$	1,915		$	1,077
Net cash provided by (used in):
Operating activities		761			494			187
Investing activities		(250	)		516			473
Financing activities		(1,179	)		(1,268	)		178
Net (decrease) increase in cash and cash equivalents		(668	)		(258	)		838
Ending cash and cash equivalents	$	989		$	1,657		$	1,915

2009 — 2008

Net Cash Provided By Operating Activities

Cash provided by operating activities for the year ended December 31, 2009, improved to $761 million compared to $494 million for the year ended December 31, 2008. Our improvement in cash provided by operating activities was primarily due to:

• Gross profit — Gross profit, excluding changes in unrealized mark-to-market activity, depreciation expense, loss on asset disposals and discontinued operations, increased by $26 million for the year ended December 31, 2009, as compared to 2008. This was attributable to higher Commodity Margin and lower cash operating costs in 2009.

• Interest paid — Cash paid for interest decreased by $299 million to $761 million for the year ended December 31, 2009, as compared to $1,060 million for 2008, primarily due to the repayment of the Second Priority Debt, and, to a lesser extent, lower interest rates for the comparable period in 2009.

• Reorganization items — Cash payments for reorganization items decreased by $115 million.

• Cash taxes — Net cash received for taxes increased by $33 million.

Our improvements in cash provided by operating activities were partially offset by the following:

• Working capital — Working capital employed, after adjusting for debt related balances and derivative activities which did not impact cash provided by operating activities, increased by approximately $152 million for the year ended December 31, 2009 compared to 2008. The increase was primarily due to the sale during 2008 of assets previously reflected as assets held for sale at December 31, 2007 offset by a net reduction in working capital employed in 2009 for margins and net accounts receivable and payable.

• Debt extinguishment costs — Cash payments for debt extinguishment costs in 2009 were $39 million related to the CCFC Refinancing, compared to cash payments of $6 million related to the refinancing of Blue Spruce and Metcalf in 2008.

Net Cash Provided By (Used In) Investing Activities

Cash flows used in investing activities for the year ended December 31, 2009, were $250 million compared to cash flows provided by investing activities of $516 million for the year ended December 31, 2008. The decrease in cash flows from investing activities was primarily due to:

• Sales of power plants, turbines and investments — We had no significant asset sales in 2009 compared to $413 million of cash received primarily from the sales of the Fremont and Hillabee development projects in 2008.

• Sales of discontinued operations — We had no significant asset sales in 2009 compared to $79 million of cash received from the sale of Rosetta in 2008.

• Reconsolidation of our Canadian Debtors and other deconsolidated foreign entities — In 2008, we had a favorable cash effect of $64 million from the reconsolidation of our Canadian Debtors and other deconsolidated foreign entities.

27

• Contributions to unconsolidated investments — Contributions increased by $2 million in 2009 primarily due to the funding of OMEC offset by reduced contributions to Greenfield LP.

• Return of investment from unconsolidated investments — For the year ended December 31, 2009, we received distributions of $9 million compared to $27 million for the year ended December 31, 2008.

• Capital expenditures — Capital expenditures increased by $36 million resulting from our maintenance programs and turbine upgrades.

• Increase in restricted cash — Restricted cash increased $59 million in 2009 compared to a $78 million decrease in 2008 primarily due to our refinancing activities.

Net Cash Used In Financing Activities

Due to our emergence from Chapter 11 during the first quarter of 2008, our financing activities are not directly comparable. Cash used in financing activities for the year ended December 31, 2009, resulted in a net outflow of $1.2 billion compared to a net outflow of $1.3 billion for the same period in 2008. Our significant cash flows from our 2009 and 2008 financing transactions are described below:

• During the year ended December 31, 2009, we repaid approximately $725 million previously drawn on our First Lien Credit Facility revolver and we made a net pay down of approximately $119 million when we refinanced the CCFC Old Notes, CCFC Term Loans and CCFC Preferred Shares with the CCFC New Notes. We also made scheduled repayments of approximately $60 million under our First Lien Credit Facility term loans and $280 million on notes payable, other project debt and capital lease obligations.

• During 2008, we borrowed approximately $4.2 billion under our First Lien Facilities and used that borrowing and cash on hand to repay approximately $3.7 billion of the Second Priority Debt, $1.1 billion on the senior secured revolver, $300 million on the bridge facility, and $143 million of First Lien Credit Facility term loans. In addition, we received proceeds of $355 million from refinancing Metcalf and Blue Spruce and repaid $585 million of other project debt, capital leases and notes payable.

• We incurred finance costs of $65 million in 2009 to facilitate an amendment to our First Lien Credit Facility term loans and to refinance CCFC, Deer Park and other project debt. During the year ended December 31, 2008, we incurred $207 million of finance costs primarily related to closing on our First Lien Facilities.

• We received $64 million from the settlement of derivatives with an other-than-insignificant financing element for the year ended December 31, 2008.

2008 — 2007

Net Cash Provided By Operating Activities

Cash flows provided by operating activities for the year ended December 31, 2008, resulted in net inflows of $494 million as compared to net inflows of $187 million for the same period in 2007. Cash flows from operating activities were primarily due to increases in:

• Gross profit — Gross profit, excluding changes in depreciation, impairments and discontinued operations, increased by $222 million in 2008 primarily due to higher spark spreads resulting from high gas prices during the first half of the year. The favorable margins were partially offset by higher plant operating expenses.

• Interest paid — Cash paid for interest decreased by $83 million to $1,060 million for the year ended December 31, 2008, as compared to $1,143 million in 2007, primarily due to additional adequate protection payments required while in Chapter 11 to holders of our Second Priority Debt in 2007.

• Working capital — Working capital employed relating to operating assets and liabilities changed by approximately $53 million during the year, after adjusting for actual cash flows from derivative activities that are included in net derivative assets and liabilities. This increase in 2008 was primarily the result of a slight increase in inventory levels as compared to 2007.

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Net Cash Provided By Investing Activities

Cash flows provided by investing activities for the year ended December 31, 2008, increased by $43 million to $516 million from $473 million for the year ended December 31, 2007. The difference was primarily due to:

• Capital expenditures — Purchases for property, plant and equipment decreased by $53 million in 2008 as compared to 2007.

• Sales of power plants, turbines and investments — Proceeds from asset sales decreased by $128 million in 2008 compared to 2007. See Note 6 of the Notes to Consolidated Financial Statements for a list of assets sold during 2008 and 2007.

• Sale of discontinued operations — Proceeds of $79 million were received in 2008 from the sale of Rosetta.

• Deconsolidation and reconsolidation — We experienced a favorable effect on cash of $64 million from the reconsolidation of our Canadian Debtors and other deconsolidated foreign entities in 2008, as compared to an unfavorable effect on cash of $29 million for the deconsolidation of OMEC in 2007.

• Contributions to unconsolidated investments — Contributions decreased by $51 million in 2008 primarily due to the completion of the Greenfield LP project financing in May 2007.

• Return of investment from unconsolidated investments — For the year ended December 31, 2008, we received cash of $27 million as a partial return of investment compared to $104 million received from Greenfield LP and $75 million related to the Canadian Debtors and other deconsolidated foreign entities for the year ended December 31, 2007.

• Decrease in restricted cash — The net reduction in restricted cash was $78 million, compared to a $37 million decrease in 2007. Restricted cash decreased in 2008 mainly due to paying down debt and refinancing activities.

Net Cash Provided By (Used In) Financing Activities

Cash flows used in financing activities for the year ended December 31, 2008, resulted in net outflows of approximately $1.3 billion, as compared to cash provided by financing activities of $178 million for the year ended December 31, 2007; because of our emergence from Chapter 11 in 2008, our cash flows provided by (used in) our financing activities are not directly comparable to 2007. The significant transactions and changes in our financing activities as compared to 2007 are described below:

• Borrowings and repayments under our First Lien Facilities — On and subsequent to the Effective Date, we borrowed $4.2 billion under our First Lien Facilities and used cash on hand to repay a portion of the Second Priority Debt and to fund other cash payment obligations under our Plan of Reorganization, working capital and other general corporate purposes. In addition, for the year ended December 31, 2008, we repaid approximately $1.5 billion of borrowings under our First Lien Facilities consisting of the repayment of the $300 million bridge facility, with the remainder applied to repayments under our First Lien Credit Facility, primarily the revolving facility thereunder, and $725 million of which amount was subsequently reborrowed in October 2008. For the year ended December 31, 2007, borrowings under our DIP Facility resulted in cash inflows of $614 million.

• Repayment of debt obligations — During 2008 we repaid $275 million for project financing, which primarily related to the Metcalf and Blue Spruce refinancings. During 2007, the repayment of debt obligations, in general, related to only those project finance facilities and other borrowings associated with our subsidiaries and affiliates that were not Calpine Debtors, except as otherwise ordered by the U.S. Bankruptcy Court or the Canadian Court such as the repayment of $224 million of CalGen Secured Debt pursuant to a settlement approved by the U.S. Bankruptcy Court.

• Financing costs — We incurred financing costs of $207 million, primarily related to closing on our First Lien Facilities in 2008, as compared to financing costs incurred in 2007 of $81 million primarily related to the refinancing in March 2007 of the Original DIP Facility with the DIP Facility.

• Preferred interests — For the year ended December 31, 2008, we paid $166 million for the redemption or repayment of preferred interests primarily consisting of the repayment of $155 million in preferred interests related to Metcalf, as compared to $9 million for the year ended December 31, 2007.

• Derivative contracts — We received $64 million from the settlement of derivatives with an other-than-insignificant financing element for the year ended December 31, 2008.

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Emergence from Chapter 11 and Implementation of Our Plan of Reorganization

We emerged from Chapter 11 on January 31, 2008. At the Petition Date, we carried $17.4 billion of debt with an average interest rate of 10.3%. As a result of retiring unsecured debt with reorganized Calpine Corporation common stock, proceeds received from the sale of certain of our assets and the repayment or refinancing of certain of our project debt, we reduced our pre-petition debt by approximately $7.0 billion. Upon our emergence from Chapter 11, we carried $10.4 billion of debt with an average interest rate of 8.1%.

In connection with our emergence from Chapter 11, we recorded certain “plan effect” adjustments to our Consolidated Balance Sheet as of the Effective Date in order to reflect certain provisions of our Plan of Reorganization. These adjustments included the distribution of approximately $4.1 billion in cash and the authorized issuance of 485 million shares of reorganized Calpine Corporation common stock primarily for the discharge of LSTC, repayment of the Second Priority Debt and for various other administrative and other post-petition claims. As a result, our equity increased by approximately $8.9 billion. We borrowed approximately $6.4 billion under our First Lien Facilities, which was used to repay the outstanding term loan balance of $3.9 billion (excluding the unused portion under the $1.0 billion revolver) under our DIP Facility. The remaining net proceeds of approximately $2.5 billion were used to fund cash payment obligations under our Plan of Reorganization including the repayment of a portion of the Second Priority Debt and the payment of administrative claims. The reorganization items on our Consolidated Statements of Operations are primarily driven by our financing and restructuring activities. Our historical financial performance during the pendency of our Chapter 11 cases and CCAA proceedings is likely not indicative of our future financial performance.

See Note 16 of the Notes to Consolidated Financial Statements for further information regarding our Chapter 11 proceedings and our emergence from Chapter 11.

Counterparties and Customers

Our counterparties primarily consist of three categories of entities who participate in the wholesale energy markets: financial institutions and trading companies; regulated utilities, municipalities, cooperatives and other retail power suppliers; and oil, natural gas, chemical and other energy-related industrial companies. We have exposure to trends within the energy industry, including declines in the creditworthiness of our marketing counterparties. Currently, certain of our marketing counterparties within the energy industry have below investment grade credit ratings. However, we do not currently have any significant exposures to counterparties that are not paying on a current basis.

Credit Considerations

Our credit rating has, among other things, generally required us to post significant collateral with our hedging counterparties. Our collateral is generally in the form of cash deposits, letters of credit or first liens on our assets. See also Note 10 of the Notes to Consolidated Financial Statements for our use of collateral. Our credit rating has also reduced the number of hedging counterparties willing to extend credit to us and reduced our ability to negotiate more favorable terms with them. However, we believe that we will continue to be able to work with our hedging counterparties to execute beneficial hedging transactions and provide adequate collateral.

As of December 31, 2009, our First Lien Credit Facility and our corporate rating had the following ratings and commentary from Standard and Poor’s and Moody’s Investors Service:

	Standard and Poor’s	Moody’s Investors Service
First Lien Credit Facility rating	B+	B2
Corporate rating	B	B2
Commentary	Stable	Positive Watch

Off Balance Sheet Commitments of Our Power Plant Operating Leases and Our Unconsolidated Subsidiaries

Some of our power plant operating leases include certain sale/leaseback transactions that are not reflected on our balance sheet. All counterparties in these transactions are third parties that are unrelated to us. The sale/leaseback transactions utilize special purpose entities formed by the equity investors with the sole purpose of owning a power plant. Some of these operating leases contain customary restrictions on dividends, additional debt and further encumbrances similar to those typically found in project finance debt instruments. We have no ownership or other interest in any of these special purpose entities. See Note 17 of the Notes to Consolidated Financial Statements for the future minimum lease payments under our power plant operating leases.

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Some of our unconsolidated equity method investments have debt that is not reflected on our Consolidated Balance Sheets. As of December 31, 2009, our equity method investees (Greenfield LP, OMEC and Whitby) had aggregate debt outstanding of $873 million. Based on our pro rata share of each of the investments, our share of such debt would be approximately $624 million. All such debt is non-recourse to us. See Note 4 of the Notes to Consolidated Financial Statements for additional information on our investments.

Guarantee Commitments — As part of our normal business operations, we enter into various agreements providing, or otherwise arranging, financial or performance assurance to third parties on behalf of our subsidiaries in the ordinary course of such subsidiaries’ respective business. Such arrangements include guarantees, standby letters of credit and surety bonds for power and natural gas purchase and sale arrangements and contracts associated with the development, construction, operation and maintenance of our fleet of power plants. These arrangements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended commercial purposes. Our primary commercial obligations as of December 31, 2009, are as follows (in millions):

	Amounts of Commitment Expiration per Period
Guarantee Commitments	2010		2011		2012		2013		2014		Thereafter		Total Amounts Committed
Guarantee of subsidiary debt(1)	$	73	$	72	$	70	$	66	$	54	$	647	$	982
Standby letters of credit(2)(4)		384		28		—		—		—		—		412
Surety bonds(3)(4)(5)		—		—		—		—		—		4		4
Guarantee of subsidiary operating lease payments(4)		10		67		5		5		5		216		308
Total	$	467	$	167	$	75	$	71	$	59	$	867	$	1,706

__________

(1) Represents Calpine Corporation guarantees of certain power plant capital leases and related interest. All guaranteed capital leases are recorded on our Consolidated Balance Sheets.

(2) The standby letters of credit disclosed above represent those disclosed in Note 7 of the Notes to Consolidated Financial Statements.

(3) The majority of surety bonds do not have expiration or cancellation dates.

(4) These are off balance sheet obligations.

(5) As of December 31, 2009, $4 million of cash collateral is outstanding related to these bonds.

Contractual Obligations — Our contractual obligations as of December 31, 2009, are as follows (in millions):

	2010		2011		2012		2013			2014			Thereafter			Total
Total operating lease obligations(1)	$	58	$	112	$	48	$	47		$	33		$	335		$	633
Debt(2)	$	464	$	627	$	259	$	138		$	4,448		$	3,508		$	9,444
Interest payments on debt(3)	$	438	$	436	$	417	$	448		$	288		$	779		$	2,806
Interest rate swap agreement payments(3)	$	202	$	96	$	43	$	(3	)	$	(5	)	$	(14	)	$	319
Purchase obligations:
Turbine commitments		23		46		15		16			16			—			116
Commodity purchase obligations(4)		502		428		418		361			271			2,722			4,702
Land leases		7		7		7		6			6			346			379
LTSAs		13		9		10		4			6			42			84
Other purchase obligations		56		81		90		50			50			1,005			1,332
Total purchase obligations(5)	$	601	$	571	$	540	$	437		$	349		$	4,115		$	6,613
Liability for uncertain tax positions	$	1	$	13	$	18	$	—		$	—		$	25		$	57
Other contractual obligations(6)	$	37	$	—	$	5	$	—		$	—		$	8		$	50

__________

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(1) Included in the total are future minimum payments for power plant operating leases and office and equipment leases. See Note 17 of the Notes to Consolidated Financial Statements for more information.

(2) A note payable totaling $77 million associated with the sale of the PG&E note receivable to a third party is excluded from debt for this purpose as it is a non-cash liability.

(3) Amounts are projected based upon interest rates at December 31, 2009.

(4) The amounts presented here are primarily the notional volumes for indexed fuel purchase contracts for the purchase, transportation, or storage of commodities accounted for as executory contracts or as a normal purchase normal sale and, therefore, not recognized as liabilities on our Consolidated Balance Sheets. See “— Risk Management and Commodity Accounting” for a discussion of our commodity derivative contracts recorded at fair value on our Consolidated Balance Sheets.

(5) The amounts included above for purchase obligations include the minimum requirements under contract.

(6) Represents cash obligations included in other current liabilities and long-term liabilities on our Consolidated Balance Sheet as of December 31, 2009.

Special Purpose Subsidiaries

Pursuant to applicable transaction agreements, we have established certain of our entities legally separate from Calpine and our other subsidiaries. In accordance with GAAP, we consolidate these entities. As of the date of filing our 2009 Form 10-K, 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, Goose Haven, Calpine Gilroy Cogen, L.P., Calpine Gilroy 1, Inc., Calpine King City Cogen, LLC, Calpine Securities Company, L.P. (a parent company of Calpine King City Cogen, LLC), Calpine King City, LLC (an indirect parent company of Calpine Securities Company, L.P.), CCFCP and Russell City Energy Company, LLC. The following disclosures are required under certain applicable agreements and pertain to some of these entities. The financial information provided below represents the assets, liabilities, and results of operations for each of the special purpose subsidiaries as reflected on our Consolidated Financial Statements. These amounts may differ materially from the assets, liabilities, and results of operations for these entities that present individual financial statements on a stand-alone basis to their project lenders.

On June 13, 2003, PCF, our wholly owned stand-alone subsidiary, completed an offering of two tranches of senior secured notes due 2006 and 2010 with original principal amounts totaling $802 million. PCF’s senior secured notes due 2006 were paid in accordance with their terms upon maturity in 2006 and are no longer outstanding. PCF’s 6.256% senior secured notes due 2010 were paid in accordance with their terms upon maturity in February 2010 and are no longer outstanding. Pursuant to the applicable agreements relating to the issuance of PCF’s senior secured notes, we are required to report the following information in our 2009 Form 10-K (in millions):

	2009
Assets	$	203
Liabilities		90

See Note 7 of the Notes to Consolidated Financial Statements for further information.

In accordance with the terms thereof, the PCF III notes were repaid in accordance with their terms upon maturity in February 2010 and are no longer outstanding. Pursuant to the applicable agreements relating to the issuance of the PCF III notes, we are required to report the following information in this Form 10-K (in millions):

	2009
Assets	$	114
Liabilities		85

See Note 7 of the Notes to Consolidated Financial Statements for further information.

GEC, a wholly owned subsidiary of GEC Holdings, LLC, has been established as an entity with its existence separate from us and other subsidiaries of ours. On September 30, 2003, GEC completed an offering of $302 million of 4% senior secured notes due 2011. In connection with the issuance of the secured notes, we received funding on a third party preferred equity investment in GEC Holdings, LLC totaling $74 million. This preferred interest meets the criteria of a mandatorily redeemable financial instrument and has been classified as debt due to certain preferential distributions to the third party. The preferential distributions are due semi-annually beginning in March 2004 through September 2011 and total approximately $113 million over the eight-year period. As of December 31, 2009 and 2008, there was $25 million and $35 million, respectively, outstanding under the preferred interest.

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A long-term PPA between CES and CDWR was acquired by GEC by means of a series of capital contributions by CES and certain of its affiliates and is an asset of GEC, and the secured notes and the preferred interest are liabilities of GEC, separate from the assets and liabilities of us and other subsidiaries of ours. In addition to the PPA and nine peaker power plants (including Creed and Goose Haven) owned directly or indirectly by GEC, GEC’s assets include cash and a 100% equity interest in each of Creed and Goose Haven, each of which is a wholly owned subsidiary of GEC and a guarantor of the 4% senior secured notes due 2011 issued by GEC. Each of GEC, Creed and Goose Haven has been established as an entity with its existence separate from us and other subsidiaries of ours. Creed and Goose Haven each have assets consisting of a peaker power plant and other assets. The following table sets forth selected financial information of GEC for the year ended December 31, 2009 (in millions):

	2009
Assets	$	505
Liabilities		89

On December 4, 2003, we announced that we had sold to a group of institutional investors our right to receive payments from PG&E under an agreement between PG&E and Gilroy regarding the termination and buy-out of a standard offer contract between PG&E and Gilroy for $133 million in cash. Since the transaction did not satisfy the criteria for sales treatment in accordance with GAAP, it was recorded on our Consolidated Financial Statements as a secured financing, with a note payable of $133 million. The notes receivable balance and note payable balance are both reduced as PG&E makes payments to the buyers of the notes receivable. The $24 million difference between the $157 million net book value of the notes receivable at the transaction date and the $133 million cash received is recognized as additional interest expense over the repayment term. We will continue to record interest income over the repayment term, and interest expense will be accreted on the amortizing note payable balance.

Pursuant to the applicable transaction agreements, each of Gilroy and Calpine Gilroy 1, Inc. (the general partner of Gilroy), has been established as an entity with its existence separate from us and other subsidiaries of ours. The following table sets forth the assets and liabilities of Gilroy and Calpine Gilroy I, Inc. as of December 31, 2009 (in millions):

	2009
Assets	$	394
Liabilities		78

See Notes 5 and 7 of the Notes to Consolidated Financial Statements for further information.

On June 29, 2004, Rocky Mountain Energy Center, LLC and Riverside Energy Center, LLC, wholly owned subsidiaries of our Calpine Riverside Holdings, LLC subsidiary, received funding in the aggregate amount of $661 million comprising $633 million of first priority secured floating rate term loans due 2011 and a $28 million letter of credit-linked deposit facility.

Pursuant to the applicable transaction agreements, each of Rocky Mountain Energy Center, LLC, Riverside Energy Center, LLC and Calpine Riverside Holdings, LLC has been established as an entity with its existence separate from us. The following table sets forth the assets and liabilities of these entities as of December 31, 2009 (in millions):

	Rocky Mountain Energy Center, LLC 2009		Riverside Energy Center, LLC 2009		Calpine Riverside Holdings, LLC 2009
Assets	$	390	$	724	$	404
Liabilities		152		320		—

See Note 7 of the Notes to Consolidated Financial Statements for further information.

On October 14, 2005, our indirect subsidiary CCFCP issued $300 million of six-year redeemable preferred shares. The CCFCP Preferred Shares were mandatorily redeemable on the maturity date of October 31, 2011; however, these preferred shares were redeemed on or before July 1, 2009, and are no longer outstanding. Pursuant to the applicable agreements relating to the issuance of the CCFCP Preferred Shares, we are required to report the following information in this Form 10-K (in millions):

	2009
Assets	$	1,829
Liabilities		1,007

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RISK MANAGEMENT AND COMMODITY ACCOUNTING

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

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 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 2010. 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 December 31, 2009, 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 3 and 16 years, respectively. Assuming constant December 31, 2009, power and natural gas prices and interest rates, we estimate that pre-tax net losses of $94 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 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 into earnings (positive or negative) will be for the next 12 months.

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 and our credit risk and changes in interest rates. Since prices for power and natural gas are among the most volatile of all commodity prices, there may be material changes in the fair value of our derivatives over time, driven both by price volatility and the changes in volume of open derivative transactions. Our derivative assets and liabilities have decreased to approximately $1.3 billion and $(1.6) billion at December 31, 2009, compared to $4.1 billion and $(4.5) billion at December 31, 2008, respectively. As of December 31, 2009, 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 8 of the Notes to Consolidated Financial Statements for further information related to our level 3 derivative assets and liabilities. There is a substantial amount of volatility inherent in accounting for the fair value of these derivatives, and our results during the years ended December 31, 2009 and 2008 have reflected this as discussed below.

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The change in fair value of our outstanding commodity and interest rate derivative instruments from January 1, 2009, through December 31, 2009, is summarized in the table below (in millions):

	Interest Rate Swaps			Commodity Instruments			Total
Fair value of contracts outstanding at January 1, 2009	$	(452	)	$	12		$	(440	)
Losses recognized or otherwise settled during the period(1)(2)		198			5			203
Fair value attributable to new contracts		4			2			6
Changes in fair value attributable to price movements		(15	)		(11	)		(26	)
Changes in fair value attributable to nonperformance risk		(54	)		—			(54	)
Fair value of contracts outstanding at December 31, 2009(3)	$	(319	)	$	8		$	(311	)

__________

(1) Interest rate settlements consist of recognized losses from interest rate cash flow hedges of $184 million and recognized losses from undesignated interest rate swaps of $14 million (represents a portion of interest expense or discontinued operations as reported on our Consolidated Statements of Operations).

(2) Settlement of commodity contracts not designated as hedging instruments of $(92) million (represents a portion of operating revenues and fuel and purchased energy expense as reported on our Consolidated Statements of Operations) and $87 million related to recognition of gains from cash flow hedges, previously reflected in OCI, offset by other changes in derivative assets and liabilities not reflected in OCI or net income.

(3) Net commodity and interest rate derivative assets and liabilities reported in Notes 8 and 9 of the Notes to Consolidated 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 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 Statements of Operations for the years ended December 31, 2009, 2008 and 2007 (in millions):

	2009			2008			2007
Realized gain (loss)
Interest rate swaps	$	(32	)	$	(9	)	$	3
Commodity derivative instruments(1)		37			(146	)		40
Total realized gain (loss)	$	5		$	(155	)	$	43
Unrealized gain (loss)
Interest rate swaps	$	8		$	(11	)	$	(15	)
Commodity derivative instruments		79			35			(35	)
Total unrealized gain (loss)	$	87		$	24		$	(50	)
Total mark-to-market activity	$	92		$	(131	)	$	(7	)

__________

(1) Balance includes a non-cash gain from amortization of prepaid power sales agreements of approximately nil, $40 million and $54 million for the years ended December 31, 2009, 2008 and 2007, respectively.

	2009			2008			2007
Power contracts included in operating revenues	$	7		$	232		$	252
Natural gas contracts included in fuel and purchased energy expense		109			(343	)		(247	)
Interest rate swaps included in interest expense		(24	)		(20	)		(12	)
Total mark-to-market activity	$	92		$	(131	)	$	(7	)

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Our change in AOCI from an accumulated loss of $158 million at December 31, 2008, to an accumulated loss of $266 million at December 31, 2009, was primarily driven by reclassification adjustments for cash flow hedges realized in net income and a decrease in interest rates, which were partially offset by decreases in commodity prices and the effect of income taxes, which includes a net $43 million tax expense reclassified from OCI to continuing operations related to the intraperiod tax allocation provisions under GAAP.

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

The net fair value of outstanding derivative commodity instruments at December 31, 2009, 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	$	(165	)	$	9	$	—		$	—	$	(156	)
Prices provided by other external sources		115			20		(1	)		—		134
Prices based on models and other valuation methods		10			19		—			1		30
Total fair value	$	(40	)	$	48	$	(1	)	$	1	$	8

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 years ended December 31, 2009 and 2008 (in millions):

	2009		2008
Year ended December 31:
High	$	59	$	70
Low	$	28	$	29
Average	$	47	$	49
As of December 31	$	51	$	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 10 of the Notes to Consolidated Financial Statements.

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

• credit approvals;

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

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

• margin, collateral, or prepayment arrangements; and

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

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We 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 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 December 31, 2009, 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 December 31, 2009)	2010				2011-2012			2013-2014		After 2014		Total
Investment grade	$	(39	)	$	49		$	(1	)	$	—	$	9
Non-investment grade		—			—			—			—		—
No external ratings		(1	)		(1	)		—			1		(1	)
Total fair value	$	(40	)	$	48		$	(1	)	$	1	$	8

The fair value of our interest rate swaps are validated based upon external quotes. See further discussion of our interest rate swaps in the “— Interest Rate Risk” section below.

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.

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 December 31, 2009. All outstanding balances and fair market values are shown gross of applicable premium or discount, if any (in millions):

	2010			2011			2012			2013			2014			Thereafter			Total		Fair Value December 31, 2009
Debt by Maturity Date:
Fixed Rate	$	218		$	71		$	21		$	24		$	21		$	2,312		$	2,667	$	2,609
Average Interest Rate		6.5	%		6.9	%		9.6	%		9.6	%		9.4	%		7.6	%
Variable Rate	$	223		$	528		$	210		$	88		$	4,410		$	688		$	6,147	$	5,863
Average Interest Rate(1)		3.1	%		4.5	%		3.9	%		4.2	%		4.9	%		6.8	%

__________

(1) Projection based upon anticipated LIBOR rates.

Currently, we use interest rate swaps to adjust the mix between fixed and floating rate debt as a hedge of our interest rate risk. We do not use interest rate derivative instruments for trading purposes. The majority of our interest rate swaps mature in years 2010 through 2012. To the extent eligible, our interest rate swaps have been designated as cash flow hedges, and changes in fair value are recorded in OCI to the extent they are effective. Holding all other factors constant, we estimate that a 10% adverse change in interest rates would result in a change in the fair value of our interest rate swaps of approximately $(37) million.

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APPLICATION OF CRITICAL ACCOUNTING POLICIES

The preparation of financial statements in accordance with GAAP requires management to make certain estimates and assumptions which are inherently imprecise and may differ significantly from actual results achieved. We believe the following are our more critical accounting policies due to the significance, subjectivity and judgment involved in determining our estimates used in preparing our Consolidated Financial Statements. See Note 2 of the Notes to Consolidated Financial Statements for a discussion of the application of these and other accounting policies. We evaluate our estimates and assumptions used in preparing our Consolidated Financial Statements on an ongoing basis utilizing historic experience, anticipated future events or trends, consultation with third party advisors or other methods that involve judgment as determined appropriate under the circumstances. The resulting effects of changes in our estimates are recorded in our Consolidated Financial Statements in the period in which the facts and circumstances that give rise to the change in estimate become known.

Revenue Recognition

We routinely enter into physical commodity contracts for sales of our generated power to manage risk and capture the value inherent in our generation. Determining the proper accounting for our power contracts can require significant judgment and impact how we recognize revenue. In addition, we determine whether the contract should be accounted for on a gross or net basis. Determining the proper accounting treatment involves the evaluation of quantitative, as well as qualitative factors, to determine if the contract should be accounted for as one of the following:

• a derivative;

• a contract that meets the definition of a derivative but is eligible for the normal purchase normal sale exemption;

• a contract that is a physical or executory contract; or

• a contract that qualifies as a lease.

See “ — Accounting for Derivative Instruments” directly below for a discussion of the significant judgments and estimates related to accounting for derivative instruments. We apply lease or traditional accrual accounting to contracts that are exempt from derivative accounting or do not meet the definition of a derivative instrument.

Executory and Physical Contracts Exempt from Derivative Accounting — We generally recognize revenue from the sale of power or host steam, thermal energy for sale to our customers for use in industrial or other heating operations, upon transmission and delivery to the customer at the contractual price. In addition to revenues from power, host steam revenues and RECs from our Geysers Assets related to generation, our operating revenues also include:

• power and steam revenue consisting of fixed capacity payments, which are not related to generation;

• other revenues such as RMR Contracts, resource adequacy and certain ancillary service revenues; and

• other service revenues including revenue related to the sales of combustion turbine component parts and services from PSM prior to its sale in March 2007.

RMR Contracts, resource adequacy and other ancillary revenues are recognized when contractually earned and consist of revenues received from our customer either at the market price or a contract price.

Lease Accounting — Contracts accounted for as operating leases, such as certain tolling agreements, with minimum lease rentals which vary over time must be levelized. Generally, we levelize these contract revenues on a straight-line basis over the term of the contract.

Gross vs. Net Accounting — We determine whether the financial statement presentation of revenues should be on a gross or net basis. Where we act as principal, we record settlement of our physical commodity contracts on a gross basis. With respect to our physical executory contracts, where we do not take title of the commodities but receive a variable payment to convert natural gas into power and steam in a tolling operation, we record revenues on a net basis. Our physical commodity contracts are not entered into for the purpose of settling on a net basis with another counterparty.

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Accounting for Derivative Instruments

We enter into a variety of derivative 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. We also use interest rate swaps to manage the interest rate risk of our variable rate debt. The majority of this activity is related to the fuel and power price risk associated with our generation assets and our contractual obligations. 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 the normal purchase normal sale exemption.

Hedge Accounting — Revenues and expenses derived from derivative instruments that qualify for hedge accounting are recorded in the period and same financial statement line item as the hedged item. 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 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), fuel and purchased energy expense (for natural gas contracts) 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. If the hedging instrument is terminated or de-designated prior to the occurrence of the hedged forecasted transaction, the gain or loss associated with 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.

Fair Value Hedges — Changes in fair value of derivatives designated as fair value hedges and the corresponding changes in the fair value of the hedged risk attributable to a recognized asset or liability, or unrecognized firm commitment are recorded in earnings. If the fair value hedge is effective, the amounts recorded will offset in earnings. If the underlying asset, liability or firm commitment being hedged is disposed of or otherwise terminated, the gain or loss associated with the underlying hedged item is recognized currently in earnings. If the hedging instrument is terminated or de-designated prior to the settlement of the hedged asset, liability or firm commitment, the carrying amount of the hedged item is adjusted by any gain or loss from the hedging instrument and remains until the hedged item is recognized in earnings. As of December 31, 2009, we had no fair value hedges; however, we had one fair value hedge at December 31, 2008 related to PCF.

Derivatives Not Designated as Hedging Instruments — Along with our portfolio of hedging transactions, 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 hedge accounting guidelines or qualify under the hedge accounting guidelines and the hedge accounting designation has not been elected, such as commodity futures, forwards, options, fixed for floating swaps and instruments that settle on power price to natural gas price relationships (Heat Rate swaps and options). 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) and interest expense (for interest rate swaps).

Mark-to-Market Activity — A component of operating revenues (for power contracts), fuel and purchased energy expense (for natural gas contracts) and interest expense (for interest rate swaps), includes realized settlements and unrealized mark-to-market gains and losses resulting from general market price movements on power, natural gas and interest rate swap derivative instruments not designated or not qualifying as cash flow hedges. Gains and losses due to ineffectiveness on commodity hedging instruments are also included in unrealized mark-to-market gains and losses.

Significant judgment and estimates used in accounting for our derivative instruments include contract interpretation, valuation techniques and assumptions, assumptions used in forecasting future generation and market expectations. As defined by GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability in the principal or most advantageous market in an orderly transaction between market participants at the measurement date (exit price). GAAP establishes a fair value hierarchy which classifies fair value measurements from level 1 through level 3 based upon the inputs used to measure fair value.

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The following is a summary of the most significant estimates and assumptions associated with the calculation of fair value of our commodity derivative instruments.

Pricing  — 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 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.

Valuation Techniques — In certain instances, we utilize models to measure fair value. These models are primarily industry-standard models, including the Black-Scholes pricing model, that incorporate various assumptions, including quoted interest rates and time value, as well as other relevant economic measures. 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.

Credit Reserves — We assess non-performance risk by adjusting the fair value of our derivatives based on the credit standing of the counterparties involved and the impact of credit enhancements, if any. Such valuation adjustments represent the amount of probable loss due to default either by us or a third party. Our credit valuation methodology is based on a quantitative approach which allocates a credit adjustment to the fair value of derivative transactions based on the net exposure of each counterparty. We develop our credit reserve based on our expectation of the market participants’ perspective of potential credit exposure. Our calculation of the credit reserve on net asset positions is based on available market information including credit default swap rates, credit ratings and historical default information. We also incorporate non-performance risk in net liability positions based on an assessment of our potential risk of default.

See Notes 8 and 9 of the Notes to Consolidated Financial Statements for further discussion of our derivative instruments.

Accounting for VIEs and Financial Statement Consolidation Criteria

We consolidate all VIEs where we have determined that we are the primary beneficiary. This determination is made at the inception of our involvement with the VIE and, in accordance with GAAP, is updated only in response to a reconsideration event. We consider both qualitative and quantitative factors to form a conclusion as to whether we, or another interest holder, absorbs a majority of the entity’s risk of expected losses, receives a majority of the entity’s potential for expected residual returns, or both.

Making these determinations can require the use of significant judgment, both on a qualitative and quantitative basis, which include, but are not limited to:

• consideration of the design of the VIE, its purpose and variability is designed to create and pass along to its interest holders;

• preparation of future expected financial results and future expected cash flows from the VIE;

• assigning probabilities to future events, markets and potential outcomes, such as the exercise of purchase options;

• estimates in future residual fair values of power plant assets years into the future; and

• determinations of our counterparties’ reasons and intentions for entering into the VIE.

If we determine that we will absorb a majority of a VIE’s expected losses, receive a majority of the entity’s potential for expected residual returns or both, we consolidate the VIE in accordance with GAAP into our Consolidated Financial Statements. Beginning on January 1, 2010, new accounting standards will change the approach for determination of the primary beneficiary and will require us to perform an ongoing reassessment of whether we continue to be the primary beneficiary, which may result in future deconsolidation or consolidation of our VIEs.

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We do not consolidate VIE’s where we have determined, at the inception of our involvement with the VIE, that we are not the primary beneficiary. These include OMEC, a VIE and 100% owned subsidiary due to purchase option rights, a 50% joint venture interest in Greenfield LP and a 50% equity interest in Whitby where we do not have control and therefore do not consolidate. We account for these entities under the equity method of accounting and include our net equity interest in investments on our Consolidated Balance Sheets as we exercise significant influence over their operating and financial policies. Our equity interest in the net (income) loss from our unconsolidated VIE, joint venture and equity interest is recorded in (income) loss from unconsolidated investments in power plants.

Depreciation Expense

Determination of the appropriate depreciation method, proper useful lives and salvage values involves significant judgment, estimates, assumptions and historical experience. Changes in our estimates and methods can result in a significant impact in the amounts and timing of when we recognize depreciation expense and therefore significantly impact our financial condition and results of operations from period to period. Different depreciation methods can impact the timing and amount of deprecation expense affecting our results of operations and could result in different net book values of assets at a particular time during the useful life of the asset affecting our financial position. Estimates of useful lives also significantly impact the timing and amounts of depreciation expense and include significant estimates. If useful lives are too short then the asset is depreciated too quickly and depreciation expense is overstated. Estimated useful lives can significantly decrease if routine maintenance is not performed, premature mechanical failure of the asset occurs, significant increases in the planned level of usage occur, advances in technology make the asset obsolete, or if there are adverse changes in environmental regulations. Our depreciable cost basis of our assets is reduced by their estimated salvage values. Estimates involved with salvage values include future estimated costs of dismantlement and repair, market prices, environmental regulations and technological advancements. Dependent upon our ability to accurately estimate salvage values and the timing of disposal, the salvage values actually realized for our assets could significantly increase or decrease resulting in additional gains or losses in the year of disposal.

We depreciate our assets under the straight line method over the shorter of their estimated useful lives or lease term using an estimated salvage value which approximates 10% of the depreciable cost basis for our power plant assets where we own the land or have a favorable option to purchase the land at conclusion of the lease term and approximately 0.15% of the depreciable costs basis for our rotable spares equipment. We use component depreciation method for our rotable parts and composite depreciation method for all the other power plant asset groups and Geysers Assets. During 2009, we reviewed our accounting policies related to depreciation including our estimates of useful lives and salvage values. We determined changing from composite depreciation to component depreciation for our rotable natural gas-fired power plant assets, and changing our Geysers Assets depreciation from the units of production method to the straight line method was preferable under GAAP. In addition, we completed a depreciable life study of our natural gas-fired power plants and Geysers Assets, and determined that a change in the depreciable lives of our natural gas-fired power plants and Geysers Assets was appropriate. See Note 3 of the Notes to Consolidated Financial Statements for further discussion regarding our changes in depreciation and the effective date of our changes.

Impairment Evaluation of Long-Lived Assets

We evaluate our long-lived assets, such as property, plant and equipment, equity method investments, turbine equipment, patents, and specifically identified intangibles, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Examples of such events or changes in circumstances are:

• a significant decrease in the market price of a long-lived asset;

• a significant adverse change in the manner an asset is being used or its physical condition;

• an adverse action by a regulator or legislature or an adverse change in the business climate;

• an accumulation of costs significantly in excess of the amount originally expected for the construction or acquisition of an asset;

• a current-period loss combined with a history of losses or the projection of future losses; or

• a change in our intent about an asset from an intent to hold to a greater than 50% likelihood that an asset will be sold or disposed of before the end of its previously estimated useful life.

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When we believe an impairment condition may have occurred, we are required to estimate the undiscounted future cash flows associated with a long-lived asset or group of long-lived assets at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities for long-lived assets that are expected to be held and used. Equipment assigned to each power plant is not evaluated for impairment separately; instead, we evaluate our operating power plants and related equipment as a whole unit.

All construction and development projects are reviewed for impairment whenever there is an indication of potential reduction in fair value. If it is determined that it is no longer probable that the projects will be completed and all capitalized costs recovered through future operations, the carrying values of the projects would be written down to their fair value.

When we determine that our assets meet the assets held-for-sale criteria, they are reported at the lower of the carrying amount or fair value less the cost to sell. We are also required to evaluate our equity method investments to determine whether or not they are impaired when the value is considered an “other than a temporary” decline in value.

If we determine that the undiscounted cash flows from an asset to be held and used are less than the carrying amount of the asset, or if we have classified an asset as held for sale, we must estimate fair value to determine the amount of any impairment charge.

The following summarizes some of the most significant estimates and assumptions used in evaluating if we have an impairment charge.

Undiscounted Expected Future Cash Flows — In order to estimate future cash flows, we consider historical cash flows, existing and future contracts and PPA’s and changes in the market environment and other factors that may affect future cash flows. To the extent applicable, the assumptions we use are consistent with forecasts that we are otherwise required to make (for example, in preparing our other earnings forecasts). Certain of our operating power plants are located in regions with depressed demand and Commodity Margin. Our forecasts generally assume that Commodity Margin will increase in future years in these regions as the supply and demand relationships improve. The use of this method involves inherent uncertainty. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.

Fair Value — Generally, fair value is determined using valuation techniques such as the present value of expected future cash flows. We also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment including contract terms, tenor and credit risk of counterparts. We may also consider prices of similar assets, consult with brokers, or employ other valuation techniques. We use our best estimates in making these evaluations; however, actual future market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.

The evaluation and measurement of impairments for equity method investments involve the same uncertainties as described for long-lived assets that we own directly. Similarly, our estimates that we make with respect to our equity and cost-method investments are subjective, and the impact of variations in these estimates could be material.

See Note 2 of the Notes to Consolidated Financial Statements for further discussion of our impairment evaluation of long-lived assets.

Accounting for Income Taxes

To arrive at our consolidated income tax provision and other tax balances, significant judgment and estimates are required. Although we believe that our estimates are reasonable, no assurance can be given that the final tax outcome of these matters will not be different than that which is reflected in our historical tax provisions and accruals. Such differences could have a material impact on our income tax provision, other tax accounts and net income in the period in which such determination is made.

Our federal 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. 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 December 31, 2009, our NOL and credit carryforwards consists of federal carryforwards of approximately $7.5 billion which expire between 2021 and 2029. This includes an NOL carryforward of approximately $513 million for the CCFC group. 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 benefit of the deferred tax assets. Future realization of the

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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 the ordinary course of business, there are many transactions and calculations where the ultimate tax outcome is uncertain. Some of these uncertainties arise as a consequence of the treatment of capital assets, financing transactions, multistate taxation of operations and segregation of foreign and domestic income and expense to avoid double taxation. We recognize the financial statement effects of a tax position when it is more likely than not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority. We derecognize previously recognized tax positions in the first period in which it is no longer more likely than not that the tax position would be sustained upon examination. The determination and calculation of uncertain tax positions involves significant judgment in the application of complex tax laws. Resolution of these uncertainties in a manner inconsistent with our expectations could have a material impact on our financial condition or results of operations. As of December 31, 2009, we have $98 million of unrecognized tax benefits from uncertain tax positions.

See Note 11 of the Notes to Consolidated Financial Statements for further discussion of our accounting for income taxes.

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Item 8.  Financial Statements and Supplementary Data

CALPINE CORPORATION AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2009

	Page
Report of Independent Registered Public Accounting Firm	45
Consolidated Statements of Operations for the Years Ended December 31, 2009, 2008 and 2007	46
Consolidated Balance Sheets at December 31, 2009 and 2008	47
Consolidated Statements of Comprehensive Income (Loss) and Stockholders’ Equity (Deficit) for the Years Ended December 31, 2009, 2008 and 2007	48
Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and 2007	49
Notes to Consolidated Financial Statements for the Years Ended December 31, 2009, 2008 and 2007	51

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Report of Independent Registered Public Accounting Firm

To the Board of Directors

and Stockholders of Calpine Corporation

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of comprehensive income (loss) and stockholders' equity (deficit) and of cash flows present fairly, in all material respects, the financial position of Calpine Corporation and its subsidiaries at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule (not presented herein) listed in the index appearing under item 15(a)-2 of the Company's 2009 Annual Report on Form 10-K presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting (not presented herein), appearing under Item 9A of the Company's 2009 Annual Report on Form 10-K. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 3 to the consolidated financial statements, the Company changed its method of depreciation for certain of its property, plant and equipment assets in 2009.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 24, 2010, except for the effects of discontinued operations of

Blue Spruce and Rocky Mountain discussed in Note 6 to the consolidated

financial statements, as to which the date is November 19, 2010

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CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

For the Years Ended December 31, 2009, 2008 and 2007

	2009			2008			2007
	(in millions, except share and per share amounts)
Operating revenues	$	6,463		$	9,837		$	7,869
Cost of revenue:
Fuel and purchased energy expense		3,897			7,281			5,682
Plant operating expense		868			890			723
Depreciation and amortization expense		447			416			446
Operating asset impairments		4			33			44
Other cost of revenue		83			114			136
Total cost of revenue		5,299			8,734			7,031
Gross profit		1,164			1,103			838
Sales, general and other administrative expense		183			215			146
(Income) loss from unconsolidated investments in power plants		(50	)		229			21
Other operating expense		18			25			23
Income from operations		1,013			634			648
Interest expense		815			1,044			1,988
Interest (income)		(16	)		(46	)		(61	)
Debt extinguishment costs		76			6			(1	)
Other (income) expense, net		14			15			(140	)
Income (loss) before reorganization items, income taxes and discontinued operations		124			(385	)		(1,138	)
Reorganization items		(1	)		(302	)		(3,258	)
Income (loss) before income taxes and discontinued operations		125			(83	)		2,120
Income tax expense (benefit)		15			(56	)		(546	)
Income (loss) before discontinued operations		110			(27	)		2,666
Discontinued operations, net of tax		35			36			27
Net income		145			9			2,693
Net loss attributable to the noncontrolling interest		4			1			—
Net income attributable to Calpine	$	149		$	10		$	2,693
Basic earnings (loss) per common share:
Weighted average shares of common stock outstanding (in thousands)		485,659			485,054			479,235
Income (loss) before discontinued operations attributable to Calpine	$	0.24		$	(0.05	)	$	5.56
Discontinued operations, net of tax, attributable to Calpine		0.07			0.07			0.06
Net income per common share attributable to Calpine — basic	$	0.31		$	0.02		$	5.62
Diluted earnings (loss) per common share:
Weighted average shares of common stock outstanding (in thousands)		486,319			485,546			479,478
Income (loss) before discontinued operations attributable to Calpine	$	0.24		$	(0.05	)	$	5.56
Discontinued operations, net of tax, attributable to Calpine		0.07			0.07			0.06
Net income per common share attributable to Calpine — diluted	$	0.31		$	0.02		$	5.62

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

46

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

December 31, 2009 and 2008

	2009			2008
	(in millions, except share and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	989		$	1,657
Accounts receivable, net of allowance of $14 and $42		747			846
Accounts receivable, related party		3			4
Inventory		209			163
Margin deposits and other prepaid expense		490			776
Restricted cash, current		508			337
Derivative assets, current		1,119			3,653
Other current assets		34			64
Total current assets		4,099			7,500
Property, plant and equipment, net		11,583			11,908
Restricted cash, net of current portion		54			166
Investments		214			144
Long-term derivative assets		127			404
Other assets		573			616
Total assets	$	16,650		$	20,738
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	578		$	574
Accrued interest payable		54			85
Debt, current portion		463			716
Derivative liabilities, current		1,360			3,799
Income taxes payable		7			5
Other current liabilities		287			437
Total current liabilities		2,749			5,616
Debt, net of current portion		8,996			9,756
Deferred income taxes, net of current portion		54			93
Long-term derivative liabilities		197			698
Other long-term liabilities		208			203
Total liabilities		12,204			16,366
Commitments and contingencies (see Note 17)
Stockholders’ equity:
Preferred stock, $.001 par value per share; authorized 100,000,000 shares, none issued and outstanding at December 31, 2009 and 2008		—			—
Common stock, $.001 par value per share; authorized 1,400,000,000 shares, 443,325,827 shares issued and 442,998,255 shares outstanding at December 31, 2009 and 429,025,057 shares issued and 428,960,025 shares outstanding at December 31, 2008		1			1
Treasury stock, at cost, 327,572 shares and 65,032 shares at December 31, 2009 and December 31, 2008, respectively		(3	)		(1	)
Additional paid-in capital		12,256			12,217
Accumulated deficit		(7,540	)		(7,689	)
Accumulated other comprehensive loss		(266	)		(158	)
Total Calpine stockholders’ equity		4,448			4,370
Noncontrolling interest		(2	)		2
Total stockholders’ equity		4,446			4,372
Total liabilities and stockholders’ equity	$	16,650		$	20,738

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

47

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) AND

STOCKHOLDERS’ EQUITY (DEFICIT)

For the Years Ended December 31, 2009, 2008 and 2007

	Common Stock			Treasury Stock			Additional Paid-In Capital			Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest			Total Stockholders’ Equity (Deficit)
	(in millions except share amounts)
Balance, December 31, 2006	$	1		$	—		$	3,270		$	(10,378	)	$	(46	)	$	3		$	(7,150	)
Return of 50,000,000 shares of loaned common stock		—			—			(145	)		—			—			—			(145	)
Returnable shares		—			—			145			—			—			—			145
Stock-based compensation (income)		—			—			(7	)		—			—			—			(7	)
Total stockholders’ deficit before comprehensive income (loss) items																				(7,157	)
Net income		—			—			—			2,693			—			—			2,693
Loss on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income		—			—			—			—			(196	)		—			(196	)
Reclassification adjustment for cash flow hedges realized in net income		—			—			—			—			13			—			13
Foreign currency translation gain		—			—			—			—			12			—			12
Income tax expense		—			—			—			—			(14	)		—			(14	)
Total comprehensive income																				2,508
Balance, December 31, 2007	$	1		$	—		$	3,263		$	(7,685	)	$	(231	)	$	3		$	(4,649	)
Cancellation of Calpine Corporation common stock		(1	)		—			(3,263	)		—			—			—			(3,264	)
Issuance of reorganized Calpine Corporation common stock in accordance with our Plan of Reorganization		1			—			12,166			—			—			—			12,167
Treasury stock transactions		—			(1	)		—			—			—			—			(1	)
Stock-based compensation expense		—			—			50			—			—			—			50
Proceeds received from the exercise of warrants		—			—			1			—			—			—			1
Cumulative effect of adjustment from adoption of fair value measurement standards, net of tax of $8 million		—			—			—			(14	)		—			—			(14	)
Total stockholders’ equity before comprehensive income (loss) items																				4,290
Net income (loss)		—			—			—			10			—			(1	)		9
Gain on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income		—			—			—			—			141			—			141
Reclassification adjustment for cash flow hedges realized in net income		—			—			—			—			27			—			27
Foreign currency translation loss		—			—			—			—			(19	)		—			(19	)
Income tax expense		—			—			—			—			(76	)		—			(76	)
Total comprehensive income																				82
Balance, December 31, 2008	$	1		$	(1	)	$	12,217		$	(7,689	)	$	(158	)	$	2		$	4,372
Treasury stock transactions		—			(2	)		—			—			—			—			(2	)
Stock-based compensation expense		—			—			38			—			—			—			38
Other		—			—			1			—			—			—			1
Total stockholders’ equity before comprehensive income (loss) items																				4,409
Net income (loss)		—			—			—			149			—			(4	)		145
Gain on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income		—			—			—			—			180			—			180
Reclassification adjustment for cash flow hedges realized in net income		—			—			—			—			(335	)		—			(335	)
Foreign currency translation gain		—			—			—			—			4			—			4
Income tax benefit		—			—			—			—			43			—			43
Total comprehensive income																				37
Balance, December 31, 2009	$	1		$	(3	)	$	12,256		$	(7,540	)	$	(266	)	$	(2	)	$	4.446

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

48

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2009, 2008 and 2007

	2009			2008			2007
	(in millions)
Cash flows from operating activities:
Net income	$	145		$	9		$	2,693
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense(1)		556			544			554
(Income) loss from unconsolidated investments in power plants		(50	)		229			21
Debt extinguishment costs		37			7			—
Deferred income taxes		16			27			(517	)
Impairment loss		4			46			46
Gain on sale of discontinued operations		—			(37	)		—
Loss on disposal of assets, excluding reorganization items		37			36			31
Unrealized mark-to-market activity, net		(89	)		(24	)		52
Return on investment in unconsolidated subsidiaries		11			—			—
Stock-based compensation expense (income)		38			50			(1	)
Reorganization items		(6	)		(359	)		(3,342	)
Other		6			16			(2	)
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable		108			375			(194	)
Derivative instruments		(118	)		234			(34	)
Other assets		235			(101	)		(102	)
Accounts payable, LSTC and accrued expenses		(19	)		(215	)		931
Other liabilities		(150	)		(343	)		51
Net cash provided by operating activities		761			494			187
Cash flows from investing activities:
Purchases of property, plant and equipment		(179	)		(143	)		(196	)
Proceeds from sale of power plants, turbines and investments		—			413			541
Proceeds from sale of discontinued operations		—			79			—
Cash acquired due to reconsolidation of Canadian Debtors and other deconsolidated foreign entities		—			64			—
Contributions to unconsolidated investments		(19	)		(17	)		(68	)
Return of investment from unconsolidated investments		9			27			179
(Increase) decrease in restricted cash		(59	)		78			37
Cash effect of deconsolidation of VIEs		—			(2	)		(29	)
Other		(2	)		17			9
Net cash provided by (used in) investing activities		(250	)		516			473
Cash flows from financing activities:
Repayments of notes payable		(106	)		(99	)		(135	)
Borrowings from CCFC New Notes		955			—			—
Repayments of CCFC Old Notes		(781	)		(4	)		(4	)
Borrowings from project financing		79			357			21
Repayments of project financing		(121	)		(275	)		(88	)
Repayments of CalGen Secured Debt		—			—			(224	)
Borrowings under DIP Facility		—			—			614
Repayments of DIP Facility		—			(98	)		(38	)
Borrowings under First Lien Facilities		—			4,248			—
Repayments of First Lien Facilities		(785	)		(1,475	)		—
Borrowings under Commodity Collateral Revolver		—			100			—
Repayments of Second Priority Debt		—			(3,672	)		—
Proceeds from sale of ULC I notes		—			—			151
Repayments on capital leases		(43	)		(42	)		(35	)
Redemptions of preferred interests		(310	)		(166	)		(9	)
Financing costs		(65	)		(207	)		(81	)
Derivative contracts classified as financing activities		—			64			—
Other		(2	)		1			6
Net cash provided by (used in) financing activities		(1,179	)		(1,268	)		178
Net (decrease) increase in cash and cash equivalents		(668	)		(258	)		838
Cash and cash equivalents, beginning of period		1,657			1,915			1,077
Cash and cash equivalents, end of period	$	989		$	1,657		$	1,915

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

49

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS — (Continued)

	2009		2008			2007
	(in millions)
Cash paid (received) during the period for:
Interest, net of amounts capitalized	$	761	$	1,060		$	1,143
Income taxes	$	7	$	74		$	1
Reorganization items included in operating activities, net	$	5	$	120		$	126
Reorganization items included in investing activities, net	$	—	$	(418	)	$	(582	)
Reorganization items included in financing activities, net	$	—	$	—		$	74
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	$	6	$	13		$	1
Issuance of First Lien Notes in exchange for First Lien Credit Facility term loans	$	1,200	$	—		$	—
Amended Steamboat project debt	$	448	$	—		$	—
Settlement of LSTC through issuance of reorganized Calpine Corporation common stock	$	—	$	5,200		$	—
DIP Facility borrowings converted into exit financing under our First Lien Facilities	$	—	$	3,872		$	—
Settlement of Convertible Senior Notes and Unsecured Senior Notes with reorganized Calpine Corporation common stock	$	—	$	3,703		$	—
DIP Facility borrowings used to extinguish the Original DIP Facility principal $(989), CalGen Secured Debt principal $(2,309) and operating liabilities $(88)	$	—	$	—		$	3,386
Project financing $(159) and operating liabilities $(33) extinguished with sale of Aries Power Plant	$	—	$	—		$	192
Return of loaned common stock	$	—	$	—		$	145
Letter of credit draws under the CalGen Secured Debt used for operating activities	$	—	$	—		$	16
Fair value of Metcalf cooperation agreement, with offsets to notes payable $(6) and operating liabilities $(6)	$	—	$	—		$	12

__________

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

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

50

CALPINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the Years Ended December 31, 2009, 2008 and 2007

1. Organization and Operations

We are an independent wholesale power generation company engaged in the ownership and operation 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 California and Texas. We sell wholesale power, steam, 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, commodity and financial derivative transactions to economically hedge our business risks and optimize our portfolio of power plants.

2. Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

Our Consolidated Financial Statements have been prepared in accordance with GAAP and include the accounts of all majority-owned subsidiaries that are not VIEs and all VIEs where we have determined we are the primary beneficiary. Intercompany transactions have been eliminated in consolidation.

Equity Method Investments — We use the equity method of accounting to record our net interest in OMEC, a VIE where we have determined that we are not the primary beneficiary, Greenfield LP, a joint venture interest, and Whitby, a less-than-majority equity interest in which we exercise significant influence over operating and financial policies. 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.

Deconsolidations / Consolidations — As a result of filings by the Canadian Debtors under the CCAA in the Canadian Court, we deconsolidated the Canadian Debtors and their direct and indirect subsidiaries, constituting most of our foreign entities as of December 20, 2005, the Petition Date, as we determined that the administration of the CCAA proceedings in a jurisdiction other than that of the U.S. Debtors’ Chapter 11 cases resulted in a loss of the elements of control necessary for consolidation and we fully impaired our investment in the Canadian Debtors and other deconsolidated foreign entities. On February 8, 2008, the Canadian Effective Date, the Canadian Court ordered and declared that the CCAA proceedings were terminated. The termination of the CCAA proceedings and our emergence from Chapter 11 proceedings in the U.S. allowed us to maintain our equity interest in the Canadian Debtors and other deconsolidated foreign entities, whose principal assets included various working capital items and a 50% ownership interest in Whitby, an equity method investment. As a result, we regained control over the Canadian Debtors and other deconsolidated foreign entities, which were reconsolidated into our Consolidated Financial Statements as of the Canadian Effective Date. See Note 16 for a further discussion on our emergence from Chapter 11.

We accounted for the reconsolidation under the purchase method in a manner similar to a step acquisition. The excess of the fair market value of the reconsolidated net assets over the carrying value of our investment balance of $0 amounted to approximately $133 million. We recorded the Canadian assets acquired and the liabilities assumed based on their estimated fair value, with the exception of Whitby. We reduced the fair value of our Whitby equity investment (approximately $62 million) to $0 on the Canadian Effective Date and recorded the $71 million balance of the excess as a gain in reorganization items on our 2008 Consolidated Statement of Operations.

During the second quarter of 2007, we deconsolidated OMEC. We deconsolidated RockGen in January 2008 and Auburndale in August 2008, and subsequently reconsolidated RockGen in December 2008. See Note 4 for further discussion of our VIEs.

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Reclassifications

Certain reclassifications have been made to our December 31, 2008 Consolidated Balance Sheet, and our Consolidated Statements of Operations and Consolidated Statements of Cash Flows for the years ended December 31, 2008 and 2007 to conform to the current year presentation. Our reclassifications are summarized as follows:

• As further discussed in Note 6, our consolidated financial information for the three years ended December 31, 2009, 2008 and 2007 have been recast to present the results of operations of Blue Spruce and Rocky Mountain as discontinued operations.

• We adopted the new accounting standards under GAAP for noncontrolling interests in consolidated financial statements effective January 1, 2009, and accordingly have reclassified minority interest as “noncontrolling interest,” a component of stockholders’ equity, on our Consolidated Balance Sheets and included “net loss attributable to the noncontrolling interest” as a separate line item on our Consolidated Statements of Operations. See “New Accounting Standards and Disclosure Requirements” for a further discussion regarding this requirement.

• We have reclassified certain amounts on our Consolidated Statements of Cash Flows for years ended December 31, 2008 and 2007, to separately report non-cash debt extinguishment costs of $7 million for the year ended December 31, 2008, previously reflected in depreciation and amortization expense and unrealized mark-to-market activity of $(24) million and $52 million previously reflected in our changes in derivative instruments included within our cash flows provided by operating activities.

Use of Estimates in Preparation of Financial Statements

The preparation of financial statements in conformity with 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 Financial Statements. Actual results could differ from those estimates.

Fair Value of Financial Instruments and Derivatives

The carrying values of accounts receivable, accounts payable and other receivables and payables approximate their respective fair values due to their short-term maturities. See Note 7 for disclosures regarding the fair value of our debt instruments and Notes 8 and 9 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 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. Additionally, we actively 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 December 31, 2009 and 2008, we had cash and cash equivalents of $264 million and $296 million, respectively, that were subject to such project finance facilities and lease agreements.

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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 Balance Sheets and Statements of Cash Flows.

The table below represents the components of our restricted cash as of December 31, 2009 and 2008 (in millions):

	2009						2008
	Current		Non-Current		Total		Current		Non-Current		Total
Debt service	$	193	$	25	$	218	$	102	$	121	$	223
Rent reserve		34		—		34		34		—		34
Construction/major maintenance		87		22		109		72		18		90
Security/project/insurance		146		—		146		96		1		97
Other		48		7		55		33		26		59
Total	$	508	$	54	$	562	$	337	$	166	$	503

Of our restricted cash at December 31, 2009 and 2008, $292 million and $265 million, respectively, relate to the assets of the following entities, each of which is an entity with its legal existence separate from us and our other subsidiaries (in millions):

	2009		2008
PCF	$	159	$	159
Gilroy Energy Center, LLC		34		35
Rocky Mountain Energy Center, LLC		48		29
Riverside Energy Center, LLC		42		33
Calpine King City Cogen, LLC		8		8
PCF III		1		1
Total	$	292	$	265

Accounts Receivable and Payable

Accounts receivable and payable represent amounts due from customers and owed to vendors. Accounts receivable are recorded at invoiced amounts, net of reserves and allowances, and do not bear interest. Receivable balances greater than 30 days past due are individually reviewed for collectability, and if deemed uncollectible, are charged off against the allowance accounts after all means of collection have been exhausted and the potential for recovery is considered remote. We use our best estimate to determine the required allowance for doubtful accounts based on a variety of factors, including the length of time receivables are past due, economic trends and conditions affecting our customer base, significant one-time events and historical write-off experience. Specific provisions are recorded for individual receivables when we become aware of a customer’s inability to meet its financial obligations. We review the adequacy of our reserves and allowances quarterly.

The accounts receivable and payable balances also include settled but unpaid amounts relating to marketing, hedging and optimization activities of CES. Some of these receivables and payables with individual counterparties are subject to master netting arrangements whereby we legally have a right of offset and we settle the balances net. However, for balance sheet presentation purposes and to be consistent with the way we present the majority of amounts related to marketing, hedging and optimization activities on our Consolidated Statements of Operations, we present our receivables and payables on a gross basis. We do not have any significant off balance sheet credit exposure related to our customers.

Counterparty Credit Risk

Our counterparties primarily consist of three categories of entities who participate in the wholesale energy markets:

• financial institutions and trading companies;

• regulated utilities, municipalities, cooperatives and other retail power suppliers; and

• oil, natural gas, chemical and other energy-related industrial companies.

53

We have exposure to trends within the energy industry, including declines in the creditworthiness of our marketing counterparties. Currently, certain of our marketing counterparties within the energy industry have below investment grade credit ratings. Our risk control group manages counterparty credit risk and monitors our net exposure with each counterparty on a daily basis. The analysis is performed on a mark-to-market basis using forward curves. The net exposure is compared against a counterparty credit risk threshold which is determined based on each counterparty’s credit rating and evaluation of their financial statements. We utilize these thresholds to determine the need for additional collateral or restriction of activity with the counterparty. We do not currently have any significant exposure to counterparties that are not paying on a current basis.

Inventory

Inventory primarily consists of spare parts, stored natural gas, 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 the costs are expensed to plant operating costs or capitalized to property, plant and equipment as the parts are utilized and consumed.

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 our counterparties under such agreements. The counterparties under such agreements would share the benefits of the collateral subject to such first priority liens ratably with the lenders under our First Lien Credit Facility. See Note 10 for a further discussion on our amounts and use of collateral.

Deferred Financing Costs

Costs incurred related to the issuance of debt instruments are deferred and amortized over the term of the related debt using a method that approximates the effective interest rate method. However, when the timing of debt transactions involve contemporaneous exchanges of cash between us and the same creditor(s) in connection with the issuance of a new debt obligation and satisfaction of an existing debt obligation, deferred financing costs are accounted for depending on whether the transaction qualifies as an extinguishment or modification, which requires us to either write off the original deferred financing costs and capitalize the new issuance costs, or continue to amortize the original deferred financing costs and immediately expense the new issuance costs.

Property, Plant and Equipment, Net

Property, plant, and equipment items are recorded at cost. We capitalize costs incurred in connection with the construction of power plants, the development of geothermal properties and the refurbishment of major turbine generator equipment. When capital improvements to leased power plants meet our capitalization criteria they are capitalized as leasehold improvements and amortized over the shorter of the term of the lease or the economic life of the capital improvement. We expense maintenance when the service is performed for work that does not meet our capitalization criteria. Our current capital expenditures at our Geysers Assets are those incurred for proven reserves and reservoir replenishment (primarily water injection), pipeline and power generation assets and drilling of “development wells” as all drilling activity has been performed within the known boundaries of the steam reservoir. We have capitalized costs incurred during ownership consisting of additions, repairs or replacements when they appreciably extend the life, increase the capacity or improve the efficiency or safety of the property. Such costs are expensed when they do not meet the above criteria. We purchased our Geysers Assets as a proven steam reservoir and accounted for the assets under purchase accounting. All well costs, except well workovers, have been capitalized since our purchase date. Exploration activities are extremely limited and are not material to our overall capital expenditures or our fixed assets. We drilled one deep test well in the Glass Mountain area in northern California in 2001, which produced economically viable quantities of steam. Immaterial holding costs at Glass Mountain are expensed.

We depreciate our assets under the straight line method over the shorter of their estimated useful life or lease term using an estimated salvage value which approximates 10% of the depreciable cost basis for our power plant assets where we own the land or have a favorable option to purchase the land at conclusion of the lease term and approximately 0.15% of the depreciable costs basis for our rotable spares equipment. During 2009, we reviewed our accounting policies related to depreciation including our estimates of useful lives. We determined changing from composite depreciation to component depreciation for our rotable natural gas-fired power plant assets, and changing our Geysers Assets depreciation from the units of production method to the straight line method was preferable under GAAP. We also revised our estimates of useful lives. See Note 3 for further discussion regarding our changes in depreciation and the effective date of our changes.

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Generally, upon normal retirement of assets under the composite depreciation method, the costs of such assets are retired against accumulated depreciation and no gain or loss is recorded. For the retirement of assets under the component depreciation method, generally, the costs and related accumulated depreciation of such assets are removed from our Consolidated Balance Sheets and a gain or loss is recorded.

Impairment Evaluation of Long-Lived Assets (Including Intangibles and Investments)

We evaluate our long-lived assets, such as property, plant and equipment, equity method investments, turbine equipment patents and specifically identifiable intangibles for impairment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Examples of such events or changes in circumstances are:

• a significant decrease in the market price of a long-lived asset;

• a significant adverse change in the manner an asset is being used or its physical condition;

• an adverse action by a regulator or legislature or an adverse change in the business climate;

• an accumulation of costs significantly in excess of the amount originally expected for the construction or acquisition of an asset;

• a current-period loss combined with a history of losses or the projection of future losses; or

• a change in our intent about an asset from an intent to hold to a greater than 50% likelihood that an asset will be sold or disposed of before the end of its previously estimated useful life.

When we believe an impairment condition may have occurred, we are required to estimate the undiscounted future cash flows associated with a long-lived asset or group of long-lived assets at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities for long-lived assets that are expected to be held and used. Equipment assigned to each power plant is not evaluated for impairment separately; instead, we evaluate our operating power plants and related equipment as a whole unit. All construction and development projects are reviewed for impairment whenever there is an indication of potential reduction in fair value. If it is determined that it is no longer probable that the projects will be completed and all capitalized costs will be recovered through future operations, the carrying values of the projects would be written down to their fair value.

In order to estimate future cash flows, we consider historical cash flows, existing and future contracts and PPAs and changes in the market environment and other factors that may affect future cash flows. To the extent applicable, the assumptions we use are consistent with forecasts that we are otherwise required to make (for example, in preparing our other earnings forecasts). The use of this method involves inherent uncertainty. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.

When we determine that our assets meet the assets held-for-sale criteria, they are reported at the lower of the carrying amount or fair value less the cost to sell.

If we determine that the undiscounted cash flows from an asset to be held and used are less than the carrying amount of the asset, or if we have classified an asset as held for sale, we must estimate fair value to determine the amount of any impairment charge.

Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. We will also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment including contract terms, tenor and credit risk of counterparts. We may also consider prices of similar assets, consult with brokers, or employ other valuation techniques. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.

We are also required to evaluate our equity method investments to determine whether or not they are impaired when the value is considered an “other than a temporary” decline in value. The evaluation and measurement of impairments for equity method investments involve the same uncertainties as described for long-lived assets that we own directly. Similarly, our estimates that we make with respect to our equity method investments are subjective, and the impact of variations in these estimates could be material.

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During 2009, we reviewed our power plants and determined that no events or changes in circumstances indicated that impairment conditions had occurred. However, based upon a sales agreement with a third party we wrote-down our natural gas reserves by approximately $4 million. The following table details impairment charges recorded during the years ended December 31, 2009, 2008 and 2007 (in millions):

	2009		2008		2007
Operating asset impairments	$	4	$	33	$	44
Impairment of equity method investment(1)		—		180		—
Equipment, development project and other impairment charges(2)		—		13		2
Impairments included in reorganization items		—		—		120
Total impairment charges	$	4	$	226	$	166

__________

(1) Amounts are included in (income) loss from unconsolidated investments in power plants on our Consolidated Statements of Operations.

(2) Amounts are included in other operating expense on our Consolidated Statements of Operations.

During the year ended December 31, 2008, we recorded an impairment loss of $180 million as a result of the anticipated sale of our investment in Auburndale as further described in Note 4. An additional impairment charge of $33 million was recorded at December 31, 2008, for our Auburndale Peaking Energy Center (a separate power plant from Auburndale) which did not receive an expected contract renewal resulting in reduced future expected cash flows. Additionally, we recorded impairments related to certain development projects that we determined were not probable of completion as of December 31, 2008. For the year ended December 31, 2007, we recorded operating asset impairment charges primarily related to the Bethpage Power Plant as additional competition from new transmission lines reduced future expected cash flows and we recorded $120 million in reorganization items primarily related to the sale of our interest in Acadia PP.

Asset Retirement Obligation

We record all known asset retirement obligations for which the liability’s fair value can be reasonably estimated. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. At December 31, 2009 and 2008, our asset retirement obligation liabilities were $48 million and $47 million, respectively, primarily relating to land leases upon which our power plants are built and the requirement that the property meet specific conditions upon its return.

Revenue Recognition

Our operating revenues are composed of the following:

• power and steam revenue consisting of fixed capacity payments, which are not related to generation, variable payments, which are related to generation, host steam and RECs from our Geysers Assets, and other revenues such as RMR Contracts, resource adequacy and certain ancillary service revenues;

• revenues from derivative instruments as a result of our marketing, hedging and optimization activities; and

• other service revenues including revenue related to the sales of combustion turbine component parts and services from PSM prior to its sale in March 2007.

Power and Steam

Physical Commodity Contracts — We recognize revenue primarily from the sale of power or host steam, thermal energy for sale to our customers for use in industrial or other heating operations, upon transmission and delivery to the customer.

We also routinely enter into physical commodity contracts for sales of our generated power to manage risk and capture the value inherent in our generation. Such contracts often meet the criteria of a derivative but are generally eligible for the normal purchase normal sale exemption. Certain other contracts do not meet the definition of a derivative and may be considered physical executory contracts or leases. We apply lease or traditional accrual accounting to these contracts that are exempt from derivative accounting or do not meet the definition of a derivative instrument. Additionally, we determine whether the financial statement presentation of revenues should be on a gross or net basis.

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With respect to our physical executory contracts, where we act as a principal, we take title of the commodities and assume the risks and rewards of ownership by receiving the natural gas and using the natural gas in our operations to generate and deliver the power. Where we act as principal, we record settlement of our physical commodity contracts on a gross basis. Where we do not take title of the commodities but receive a net variable payment to convert natural gas into power and steam in a tolling operation, we record the variable payment as revenue but do not record any fuel and purchased energy expense. Our physical commodity contracts are not entered into for the purpose of settling on a net basis with another counterparty.

RMR Contracts, resource adequacy and other ancillary revenues are recognized when contractually earned and consist of revenues received from our customers either at the market price or a contract price.

Leases  — Contracts accounted for as operating leases, such as certain tolling agreements, with minimum lease rentals which vary over time must be levelized. Generally, we levelize these contract revenues on a straight-line basis over the term of the contract.

The total contractual future minimum lease receipts for these contracts are as follows (in millions):

2010	$	186
2011		190
2012		181
2013		146
2014		103
Thereafter		807
Total	$	1,613

Accounting for Derivative Instruments

We enter into a variety of derivative instruments to include both exchange traded and OTC power and natural gas forwards, options as well as instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) and interest rate swaps. The majority of this activity is related to the fuel and power price risk associated with our generation assets and our contractual obligations. 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 the normal purchase normal sale exemption.

Operating revenues, fuel and purchased energy expense and gains and losses on interest rate swaps derived from marketing, hedging and optimization activities that qualify for hedge accounting are recorded in the period and same financial statement line item as the hedged item. We present the cash flows from our derivatives in the same category as the item being hedged within operating activities on our Consolidated Statements of Cash Flows unless they contain an other-than-insignificant financing element in which case their cash flows are classified within financing activities. Hedge accounting requires us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting. For operating revenues, fuel and purchased energy expense and gains and losses on interest rate swaps derived from marketing, hedging and optimization activities that do not qualify for hedge accounting treatment and for certain forward physical PPAs that do not qualify for the normal purchase normal sale exemption under derivative accounting, changes in fair value are recognized currently into earnings as mark-to-market activity.

Accounting for derivatives at fair value requires us to make estimates about future prices during periods for which price quotes are not available from sources external to us, in which case we rely on internally developed price estimates. During periods where external price quotes are not available, we derive such future price estimates based on an extrapolation of prices from periods where external price quotes are available. We perform this extrapolation using liquid and observable market prices and extending those prices to an internally generated long-term price forecast based on a generalized equilibrium model.

We adopted the new accounting requirements related to disclosures about derivative instruments and hedging activities as of January 1, 2009, which required enhanced disclosures about an entity’s derivative and hedging activities to enable investors to better understand their effects on the entity’s financial position, financial performance and cash flows as well as qualitative disclosures about our fair value amounts of gains and losses associated with derivative instruments and disclosures about credit-risk-related contingent features in derivative contracts. See Note 9 for further information regarding our accounting for derivative instruments.

Fuel and Purchased Energy Expense

Fuel and purchased energy expense is composed of the cost of natural gas purchased from third parties for the purposes of consumption in our power plants as fuel expense, and the cost of power and natural gas purchased from third parties for marketing, hedging and optimization activities as well as unrealized mark-to-market gains and losses resulting from general market price movements against certain derivative natural gas contracts that do not qualify for hedge accounting treatment.

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Plant Operating Expense

Plant operating expense primarily includes employee expenses, repairs and maintenance, insurance and property taxes. We recognize expense when the service is performed.

Income Taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying values of existing assets and liabilities and their respective tax basis and tax credit and NOL carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities due to a change in tax rates is recognized in income in the period that includes the enactment date.

We recognize the financial statement effects of a tax position when it is more likely than not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority. We reverse a previously recognized tax position in the first period in which it is no longer more likely than not that the tax position would be sustained upon examination. See Note 11 for a further discussion on our income taxes.

Earnings (Loss) per Share

Basic earnings (loss) per share is calculated using the weighted average shares outstanding during the period and includes restricted stock units for which no future service is required as a condition to the delivery of the underlying common stock. Diluted earnings (loss) per share is calculated by adjusting the weighted average shares outstanding by the dilutive effect of share-based awards using the treasury stock method.

In accordance with GAAP, entities that have entered into a forward contract that requires physical settlement by repurchase of a fixed number of the issuer’s equity shares of common stock in exchange for cash shall exclude the common shares to be redeemed or repurchased when calculating basic and diluted earnings (loss) per share. Our share lending agreement, which terminated in 2007 upon the return to us of all the loaned shares, did not provide for cash settlement, but rather physical settlement was required (i.e., the shares had to be and were returned by the end of the arrangement). Consequently, the loaned shares of common stock subject to the share lending agreement were excluded from our earnings (loss) per share calculation for the year ended December 31, 2007. See Note 12 for a further discussion of our earnings (loss) per share.

Stock-Based Compensation

We have selected the Black-Scholes option-pricing model to estimate the fair value of our employee stock options on the grant date. The Black-Scholes option-pricing model takes into account certain variables, which are further explained in Note 13.

Accounting for Reorganization

During the period December 20, 2005, through January 31, 2008, we conducted our business in the ordinary course as debtors-in-possession under the protection of the Bankruptcy Courts. We emerged from Chapter 11 on January 31, 2008. In accordance with financial reporting by entities in reorganization under the Bankruptcy Code prescribed by GAAP, certain income, expenses, realized gains and losses and provisions for losses that were realized or incurred in our Chapter 11 cases are recorded in reorganization items on our Consolidated Statements of Operations. In connection with our emergence from Chapter 11, we recorded certain “plan effect” adjustments to our Consolidated Balance Sheet as of the Effective Date in order to reflect certain provisions of our Plan of Reorganization. See Note 16 for a further discussion on our emergence from Chapter 11.

New Accounting Standards and Disclosure Requirements

Accounting Standards Codification and GAAP Hierarchy — Effective for interim and annual periods ending after September 15, 2009, the Accounting Standards Codification, or ASC, and related disclosure requirements issued by the Financial Accounting Standards Board, FASB, became the single official source of authoritative, nongovernmental GAAP. The ASC simplifies GAAP, without change, by consolidating the numerous predecessor accounting standards and requirements into logically organized topics. All other literature not included in the ASC is non-authoritative. We adopted the ASC during 2009, which did not have any impact on our results of operations, financial condition or cash flows as it does not represent new accounting literature or requirements; however, it did change our references to authoritative sources of GAAP to the new ASC nomenclature.

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Fair Value Measurements of Non-Financial Assets and Non-Financial Liabilities — Effective for interim and annual periods beginning after November 15, 2008, GAAP includes new standards related to fair value measurements for non-financial assets and liabilities. These new standards do not apply to assets and liabilities that were not previously required to be recorded at fair value, but do apply when other accounting standards require fair value measurements. The new standards also define fair value, establish a framework for measuring fair value under GAAP and enhance disclosures about fair value measurements. We adopted the new standards with respect to non-financial assets and non-financial liabilities as of January 1, 2009, which did not have a material effect on our results of operations, financial position or cash flows; however, adoption may impact measurements of asset impairments and asset retirement obligations if they occur in the future.

Determining Fair Value in Inactive Markets — Effective for interim and annual periods beginning after June 15, 2009, GAAP includes new accounting standards for determining fair value when the volume and level of activity for the asset or liability have significantly decreased and the identifying transactions are not orderly. The new standards apply to all fair value measurements when appropriate. Among other things, the new standards:

• affirm that the objective of fair value, when the market for an asset is not active, is the price that would be received in a sale of the asset in an orderly transaction;

• clarify certain factors and provide additional factors for determining whether there has been a significant decrease in market activity for an asset when the market for that asset is not active;

• provide that a transaction for an asset or liability may not be presumed to be distressed (not orderly) simply because there has been a significant decrease in the volume and level of activity for the asset or liability, rather, a company must determine whether a transaction is not orderly based on the weight of the evidence, and provide a non-exclusive list of the evidence that may indicate that a transaction is not orderly; and

• require disclosure in interim and annual periods of the inputs and valuation techniques used to measure fair value and any change in valuation technique (and the related inputs) resulting from the application of the standard, including quantification of its effects, if practicable.

These new accounting standards must be applied prospectively and retrospective application is not permitted. We adopted these new standards during 2009, which resulted in a clarification of existing accounting guidance with no change to our accounting policies and had no effect on our results of operations, cash flows or financial position. See Note 8 for disclosure of our fair value measurements.

Noncontrolling Interests in Consolidated Financial Statements — Effective for interim and annual periods beginning after December 15, 2008, GAAP includes new accounting standards and disclosure requirements for noncontrolling ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, and changes in a parent’s ownership interest while the parent retains a controlling financial interest in its subsidiary. In addition, the new standards established principles for valuation of retained noncontrolling equity investments and measurement of gain or loss when a subsidiary is deconsolidated as well as disclosure requirements to clearly identify and distinguish between interests of the parent and the interests of the noncontrolling owners. We adopted these new standards as of January 1, 2009, which did not have a material impact on our results of operations, financial position or cash flows; however, adoption did result in the reclassification of minority interest to noncontrolling interest on our Consolidated Balance Sheets and Statements of Operations.

Disclosures About Derivative Instruments and Hedging Activities — Effective for interim and annual periods beginning after November 15, 2008, GAAP includes enhanced disclosure requirements relating to an entity’s derivative and hedging activities to enable investors to better understand their effects on the entity’s financial position, financial performance, and cash flows. We adopted the new disclosure requirements as of January 1, 2009. Adoption resulted in additional disclosures related to our derivatives and hedging activities including additional disclosures regarding our objectives for entering into derivative transactions, increased balance sheet and financial performance disclosures, volume information and credit enhancement disclosures. See Note 9 for our derivative disclosures.

Subsequent Events — Effective for interim and annual periods ending after June 15, 2009, GAAP includes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The new standards do not change the accounting for subsequent events; however, they do require disclosure, on a prospective basis, of the date through which an entity has evaluated subsequent events. We adopted these new standards during 2009, which had no impact on our results of operations, financial condition or cash flows. We have evaluated subsequent events up to February 24, 2010with the exception of the agreement to sell our ownership interest in Blue Spruce and Rocky Mountain as disclosed in Note 6, which is as of November 19, 2010.

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Consolidation of Variable Interest Entities — Effective for interim and annual periods beginning after November 15, 2009, with earlier application prohibited, GAAP includes new standards for determining which enterprise has a controlling financial interest in a VIE and amends guidance for determining whether an entity is a VIE. The new standards will also add reconsideration events for determining whether an entity is a VIE and will require ongoing reassessment of which entity is determined to be the VIE’s primary beneficiary as well as enhanced disclosures about the enterprise’s involvement with a VIE. We are currently assessing the future impact these new standards will have on our results of operations, financial position or cash flows; however, it is possible this new standard could result in the future deconsolidation or consolidation of our VIEs. See Note 4 for a discussion of our VIEs.

Fair Value Measurements and Disclosures — In January 2010, FASB 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 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. Since this update only requires additional disclosures, we do not expect this standard to have a material impact on our results of operations, cash flows or financial position.

3. Property, Plant and Equipment, Net

As of December 31, 2009 and 2008, the components of property, plant and equipment, are stated at cost less accumulated depreciation as follows (in millions):

	2009			2008
Buildings, machinery and equipment	$	13,373		$	13,360
Geothermal properties		1,050			979
Other		232			258
		14,655			14,597
Less: Accumulated depreciation		(3,322	)		(2,932	)
		11,333			11,665
Land		74			76
Construction in progress		176			167
Property, plant and equipment, net	$	11,583		$	11,908

Total depreciation expense, including amortization of leased assets, recorded in income from operations and discontinued operations for the years ended December 31, 2009, 2008 and 2007, was $469 million, $437 million and $472 million, respectively.

We have various debt instruments that are collateralized by certain of our property, plant and equipment. See Note 7 for a detailed discussion of such instruments.

Change in Depreciation Methods, Useful Lives and Salvage Values

During 2009, we reviewed our accounting policies related to depreciation including our estimates of useful lives and salvage values. As further 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 their remaining useful lives and the 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 — Historically, we have 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. Our power plants undergo scheduled and unscheduled outages to replace and repair rotable parts over the course of their useful lives. Our rotable parts generally have shorter useful lives than the remainder of our power plant assets. In conjunction with our recent plant maintenance activities and concurrently with our useful life study, we have created records in sufficient detail to support componentizing our rotable parts for our natural gas-fired power plant assets for purposes of calculating depreciation. We believe that component depreciation method is preferable, since depreciating the individual rotable parts over their individual useful lives would be a more precise method of depreciation compared to historical composite depreciation method.

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As a result, the useful lives of our rotable parts are now generally estimated to range from 3 to 18 years. Furthermore, we have reduced our estimate of salvage value for our rotable parts to 0.15% from 10% of original cost to reflect our expectation with these separable parts. Our change in the method of depreciation for rotable parts is considered a change in accounting estimate inseparable from a change in accounting principle, and will result in changes to our depreciation expense prospectively.

Prior to October 2009, 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. Based in part on the effect to our composite pools resulting from the componentization of our rotable parts, and the results of our useful life study, we have revised the estimated useful lives of our composite pools to 37 years and 47 years for our combined-cycle and simple-cycle power plant assets, respectively. Our change in useful lives is considered a change in accounting estimate and will result in changes to our depreciation expense prospectively.

Straight Line Method for our Geysers Assets — Historically, our Geysers Assets have used units of production 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. We historically viewed the geothermal steam being produced at our Geysers Assets to be a depleting asset. Accordingly, the total expected future generation used to develop our depreciation rate per MWh was limited by our estimate of the geothermal steam produced at our Geysers Assets. Over the past ten years, we have signed long-term contracts with municipalities in proximity to our Geysers Assets which allows us to receive, on average, 15 million gallons of reclaimed wastewater a day which is injected into the reservoir to replenish natural steam withdrawn for the production of power. As a result, steam flow decline rates have become very small. The expectation, as a result of the water injection program, is that the steam reservoir at our Geysers Assets will be able to supply economic quantities of steam for the foreseeable future. Therefore, the total expected future generation used to develop our depreciation rate per MWh is no longer limited by the existence of geothermal steam, but instead is limited by the physical useful life of the Geysers Assets. Accordingly, we have changed our depreciation method from the units of production method to the straight line method of depreciation for our Geysers Assets because we believe the straight line method is preferable since it is more systematic and rational under our circumstances. As a result of this change, and based in part on the results of our separate useful life study, we are now using estimates of the remaining composite useful lives of our Geysers Assets which are 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 will result in changes to depreciation expense prospectively.

The changes described above resulted in an increase in our historical depreciation expense of approximately $28 million related to our natural gas-fired power plants and a decrease in historical depreciation expense of approximately $3 million for our Geysers Assets for a net decrease to our net income attributable to Calpine of approximately $25 million or approximately $(0.05) to our basic and diluted earnings per share for the year ended December 31, 2009.

Buildings, Machinery and Equipment

This component primarily includes power plants and related equipment. Included in buildings, machinery and equipment are assets under capital leases. See Note 7 for further information regarding these assets under capital leases.

Other

This component primarily includes software and emission reduction credits that are power plant specific and not available to be sold.

Capitalized Interest

The total amount of interest capitalized was $8 million, $20 million and $26 million for the years ended December 31, 2009, 2008 and 2007, respectively.

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4. Variable Interest Entities and Unconsolidated Investments

We consolidate all VIEs where we have determined that we are the primary beneficiary. This determination is made at the inception of our involvement with the VIE and, in accordance with GAAP, is updated only in response to a reconsideration event. Beginning on January 1, 2010, new accounting standards will change the approach for the determination of the primary beneficiary and will require us to perform an ongoing reassessment of our VIEs to determine the primary beneficiary, which may result in future deconsolidation or consolidation of our VIEs. We consider both qualitative and quantitative factors to form a conclusion as to whether we, or another interest holder, absorbs a majority of the entity’s risk of expected losses, receives a majority of the entity’s potential for expected residual returns, or both. Our consolidated VIEs are aggregated into the following classifications in order of priority:

• Consolidated VIEs with Purchase Options — Certain of our subsidiaries have 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. For these VIEs, we determined at the time we entered into the contractual arrangement that consolidation was appropriate as exercise of the option was considered unlikely or would not provide the majority of the risk or reward from the project.

• Consolidated 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. Accordingly, we are the primary beneficiary of these VIEs. See Note 7 for further information regarding our project debt and Note 2 for information regarding our restricted cash balances.

• Consolidated Subsidiaries with PPAs — Certain of our 100% owned subsidiaries have PPAs that are deemed to be a form of subordinated financial support and thus constitute a VIE. For all such VIEs, we have determined that we are the primary beneficiary as we retain the primary risk of loss over the life of the project.

• Other Consolidated VIEs — Our other consolidated VIEs primarily consist of monetized assets secured by financing. For each of these arrangements we are the primary beneficiary as we retain both the primary risk of loss and potential for reward associated with the assets of the subsidiary.

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The tables below detail the assets and liabilities (excluding intercompany balances which are eliminated in consolidation) for our VIEs, combined by VIE classification, that were included in our Consolidated Balance Sheets as of December 31, 2009 and 2008 (in millions):

Condensed Combined VIE Assets and Liabilities

	2009
	Purchase Options		Project Debt		PPAs		Other
Assets:
Current assets	$	288	$	396	$	78	$	204
Restricted cash, net of current portion		16		12		17		—
Property, plant and equipment, net		2,560		3,038		1,349		—
Other assets		101		57		38		—
Total assets(1)	$	2,965	$	3,503	$	1,482	$	204
Liabilities:
Current liabilities	$	143	$	97	$	34	$	175
Long-term debt		1,091		1,940		11		—
Long-term derivative liabilities		—		6		—		—
Other liabilities		9		11		8		—
Total liabilities(1)	$	1,243	$	2,054	$	53	$	175

	2008
	Purchase Options		Project Debt		PPAs		Other
Assets:
Current assets	$	224	$	369	$	152	$	103
Restricted cash, net of current portion		3		16		27		111
Property, plant and equipment, net		2,863		2,438		1,413		—
Other assets		94		32		7		4
Total assets(1)	$	3,184	$	2,855	$	1,599	$	218
Liabilities:
Current liabilities	$	204	$	412	$	33	$	142
Long-term debt		1,413		1,313		58		131
Long-term derivative liabilities		11		14		—		—
Other liabilities		10		5		9		—
Total liabilities(1)	$	1,638	$	1,744	$	100	$	273

__________

(1) The assets and liabilities listed above for our VIEs with purchase options may not be indicative of our risk of loss. Some of the above VIEs include sale options that are held by us or purchase options held by others, some are for only a minority interest, some are only for a portion of a VIE’s total assets and liabilities and some are only effective upon the occurrence of an event of default.

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Unconsolidated VIEs and Investments

We do not consolidate OMEC, a VIE where we have determined that we are not the primary beneficiary. We also have a joint venture interest in Greenfield LP and a less-than-majority equity interest in Whitby where we do not have control and therefore do not consolidate. We account for these entities under the equity method of accounting and include our net equity interest in investments on our Consolidated Balance Sheets as we exercise significant influence over their operating and financial policies. Our equity interest in the net (income) loss from our unconsolidated VIE, joint venture and equity interest is recorded in (income) loss from unconsolidated investments in power plants on our Consolidated Statements of Operations.

At December 31, 2009 and 2008, our equity method investments included on our Consolidated Balance Sheets were comprised of the following (in millions):

	Ownership Interest as of December  31, 2009		2009		2008
OMEC		100%	$	144	$	98
Greenfield LP		50%		70		46
Whitby		50%		—		—
Total investments			$	214	$	144

The following details our (income) loss and distributions from unconsolidated investments in power plants for the years ended December 31, 2009, 2008 and 2007 (in millions):

	(Income) Loss from Unconsolidated Investments in Power Plants								Distributions
	2009			2008			2007		2009		2008		2007
OMEC	$	(32	)	$	55		$	9	$	9	$	—	$	—
Greenfield LP		(16	)		5			12		9		24		104
RockGen		—			(9	)		—		—		—		—
Whitby		(2	)		(2	)		—		2		3		—
Auburndale		—			180			—		—		—		—
Total	$	(50	)	$	229		$	21	$	20	$	27	$	104

Our risk of loss related to our unconsolidated VIE, OMEC, is limited to our investment balance and our operational risks during the period we operate OMEC. The debt on the books of our unconsolidated investments is not reflected on our Consolidated Balance Sheets. As of December 31, 2009 and 2008, equity method investee debt was approximately $873 million and $697 million, respectively. Based on our pro rata share of each of the investments, our share of such debt would be approximately $624 million and $477 million as of December 31, 2009 and 2008, respectively.

OMEC  — OMEC, an indirect wholly owned subsidiary, is the owner of the Otay Mesa Energy Center, a 608 MW natural gas-fired power plant in southern San Diego County, California. OMEC began commercial operations on October 3, 2009. OMEC has a ten-year tolling agreement with SDG&E. We do not consolidate OMEC 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 at the end of the tolling agreement. We determined SDG&E has a greater variability of risk compared to us and we are not the primary beneficiary.

OMEC has a $377 million non-recourse project finance facility construction loan, which converted to a term loan on November 13, 2009 and matures in April 2019. Borrowings under the project finance facility are initially priced at LIBOR plus 1.5%. The term loan bears interest at LIBOR plus 1.25%. We contributed $19 million and $9 million for the years ended December 31, 2009 and 2008, respectively, as an additional investment in OMEC.

Greenfield LP — Greenfield LP is a limited partnership between certain subsidiaries of ours and a third party which operates the Greenfield Energy Centre, a 1,005 MW natural gas-fired power plant in Ontario, Canada. We and a third party each hold a 50% joint venture 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 contributed nil and $8 million for the years ended December 31, 2009 and 2008, respectively, as an additional investment in Greenfield LP.

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Whitby  — Represents our 50% investment in Whitby held by our Canadian subsidiaries, which were reconsolidated on the Canadian Effective Date.

RockGen — On December 6, 2007, our subsidiary RockGen, which had leased the RockGen Energy Center from the RockGen Owner Lessors pursuant to a sale and leaseback arrangement, entered into a settlement agreement and a purchase and sale agreement with the RockGen Owner Lessors to purchase the RockGen Energy Center for an allowed general unsecured claim of approximately $145 million. While the allowed claim was approved by the U.S. Bankruptcy Court in December 2007, the purchase agreement was conditional upon certain events before title could transfer to us. All of the conditions were satisfied in January 2008 and the acquisition of RockGen Energy Center assets closed on January 15, 2008.

On January 15, 2008, we closed on our purchase of the RockGen Energy Center assets which terminated the prior sale-leaseback agreement and also required us to reconsider if we were RockGen’s primary beneficiary. RockGen’s PPA with WP&L contained a call option which allowed WP&L and related parties to purchase the RockGen Energy Center assets at a fixed price on May 31, 2009, provided they gave us 180-days prior written notice. The call option effectively created a ceiling value for us and absorbed the majority of the expected change in fair value of the RockGen Energy Center assets and transferred it to WP&L. As a result, we determined that we were not RockGen’s primary beneficiary. Accordingly, we deconsolidated RockGen during the first quarter of 2008, and accounted for our investment in RockGen under the equity method through December 2, 2008.

On December 2, 2008, (180 days prior to May 31, 2009) WP&L’s period to exercise the purchase option expired without providing written notification. This resulted in a reconsideration event and we determined that expiration of the option eliminated the transfer of the risk of loss and potential for future reward to us and that we are RockGen’s primary beneficiary. We reconsolidated RockGen as of December 2, 2008. The expiration of the purchase option also terminated WP&L’s variable interest and RockGen is no longer a VIE. The reconsolidation resulted in the addition to our Consolidated Balance Sheet of $141 million in property, plant and equipment, $11 million in other assets and $2 million in liabilities and removal of $150 million representing our investment balance in RockGen.

Auburndale  — Auburndale was an unconsolidated subsidiary accounted for under the equity method of accounting for the period from August 21, 2008 through the date of its sale on November 21, 2008. Prior to August 21, 2008, we consolidated Auburndale as we determined that we were Auburndale’s primary beneficiary. Pomifer, an unrelated party, held a preferred interest which entitled it to approximately 70% of Auburndale’s cash distributions through 2013. Pomifer also held an option which, upon exercise, entitled Pomifer to an additional 20% of Auburndale’s cash distributions through 2013, as well as certain drag-along rights that would require us to sell our remaining interest in Auburndale should Pomifer sell its interest in Auburndale. On August 21, 2008, Pomifer exercised its option to the additional 20% of cash distributions, which required us, under GAAP, to reconsider whether we remained Auburndale’s primary beneficiary. We determined that we were no longer Auburndale’s primary beneficiary and we deconsolidated Auburndale during the third quarter of 2008. On September 30, 2008, Pomifer notified us of their intent to exercise their drag-along rights. Accordingly, we determined that a sale of our remaining interest was probable. We compared our expected proceeds from such sale to the net book value of our interest in Auburndale at September 30, 2008, to determine if an impairment existed and, as a result, recorded an impairment loss of approximately $180 million, which is included in our (income) loss from unconsolidated investments in power plants on our Consolidated Statement of Operations during the year ended December 31, 2008. We sold our remaining interest in Auburndale on November 21, 2008.

Inland Empire Energy Center Put and Call Options — We hold a call option to purchase the Inland Empire Energy Center development project (a 775 MW natural gas-fired power plant located in California) from GE that may be exercised between years 7 and 14 of the life of the power plant. GE holds a put option whereby they can require us to purchase the power plant, if certain plant performance criteria are met during year 15 of the life of the power plant. We determined that we were not the primary beneficiary of the Inland Empire power plant as we do not absorb the majority of the risk of loss associated with the project due to, but not limited to, the fact that GE will continue to manage and fully fund the operation of the power plant. Additionally, if we purchase the power plant under the call or put options, GE will continue to provide critical power plant maintenance services throughout the remaining estimated useful life of the power plant.

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Significant Subsidiary — OMEC meets the criteria of a significant subsidiary as defined under SEC guidelines based upon the relationship of our equity income from our investment in this subsidiary to our consolidated net income before income taxes. Condensed combined financial statements for our unconsolidated subsidiaries are set forth below (in millions):

Condensed Combined Balance Sheets

of Our Unconsolidated Subsidiaries

December 31, 2009 and 2008

	2009		2008
Assets:
Cash and cash equivalents	$	33	$	39
Current assets		133		91
Property, plant and equipment, net		1,220		1,006
Other assets		54		95
Total assets	$	1,440	$	1,231
Liabilities:
Current maturities of long-term debt	$	37	$	24
Current liabilities		117		97
Long-term debt		836		673
Long-term derivative liabilities		95		154
Other liabilities		47		48
Total liabilities		1,132		996
Member’s interest		308		235
Total liabilities and member’s interest	$	1,440	$	1,231

Condensed Combined Statements of Operations

of Our Unconsolidated Subsidiaries

For the Years Ended December 31, 2009, 2008 and 2007

	2009		2008(1)			2007(1)
Revenues	$	256	$	121		$	42
Operating expenses		195		106			35
Impairment of equity method investment		—		180			—
Income (loss) from operations		61		(165	)		7
Interest (income) expense		2		12			(1	)
Other (income) expense, net		5		58			17
Net income (loss)	$	54	$	(235	)	$	(9	)

__________

(1) Amounts include results from Auburndale and RockGen during the periods they were deconsolidated in 2008. Amounts prior to OMEC’s deconsolidation in the second quarter of 2007 are included in our Consolidated Statements of Operations.

5. Other Assets

As of December 31, 2009 and 2008, the components of other assets were as follows (in millions):

	2009		2008
Prepaid lease, net of current portion	$	127	$	115
Notes receivable, net of current portion		68		83
Deferred financing costs, net of current portion		176		211
Deposits		38		26
Intangible assets, net		74		77
Other		90		104
Other assets	$	573	$	616

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Prepaid Lease, Net of Current Portion — Included in prepaid lease, net of current portion, are operating leases for South Point Energy Center, Gilroy Energy Center and Kennedy International Airport Power Plant at December 31, 2009. At December 31, 2008, operating leases for South Point Energy Center and Gilroy Energy Center were included in prepaid lease, net of current portion.

Notes Receivable, Net of Current Portion — Notes receivable, net of current portion, primarily consists of a secured financing for the sale of a note receivable from PG&E with an original net book value of $157 million in December 2003 for $133 million in cash. We recorded the transaction as a secured financing, with an offsetting note payable of $133 million. The notes receivable balance and note payable balance are both reduced as PG&E makes payments to the buyers of the notes receivable. The $24 million difference between the original $157 million net book value of the notes receivable at the transaction date and the $133 million cash received is recognized as additional interest expense over the repayment term. The fair value of the note receivable as of December 31, 2009 and 2008, was $83 million and $96 million, respectively.

Deferred Financing Costs, Net of Current Portion — Deferred financing costs related to the issuance of our debt. See Note 7 for further discussion of our debt.

Deposits — Deposits include margin deposits as well as other deposits.

Intangible Assets, Net — Intangible assets, net, include lease levelization costs and power sales agreement amounts.

Other — Other consists of our long-term deferred tax asset, project development costs and deferred transmission credits.

6. Asset Sales and Purchase

2008

On January 15, 2008, we purchased the RockGen Energy Center from the RockGen Owner Lessors. RockGen previously leased the RockGen Energy Center from the RockGen Owner Lessors, which are not affiliates of ours, pursuant to a leveraged operating lease. We purchased the RockGen Energy Center for an allowed general unsecured claim of approximately $145 million, plus interest. As a result of the lease termination and related acquisition, we recorded $102 million in reorganization items on our 2007 Consolidated Statement of Operations to expense prepaid lease assets related to the RockGen Energy Center.

On February 14, 2008, we completed the sale of substantially all of the assets comprising the Hillabee development project, a partially completed 774 MW combined-cycle power plant located in Alexander City, Alabama, to CER Generation, LLC for approximately $156 million, plus the assumption of certain liabilities. We recorded a pre-tax gain of approximately $63 million in the first quarter of 2008, which is included in reorganization items on our 2008 Consolidated Statement of Operations.

On March 5, 2008, we completed the sale of substantially all of the assets comprising the Fremont development project, a partially completed 550 MW natural gas-fired power plant located in Fremont, Ohio, to First Energy Generation Corp. for approximately $254 million, plus the assumption of certain liabilities. We recorded a pre-tax gain of approximately $136 million in the first quarter of 2008, which is included in reorganization items on our 2008 Consolidated Statement of Operations.

On August 21, 2008, Pomifer exercised its purchase option to purchase additional cash distributions of 20% through 2013 from Auburndale as further described in Note 4. On September 30, 2008, we received notice that Pomifer had entered into an asset purchase agreement with a third party and that Pomifer intended to exercise its drag-along rights to sell 100% of Auburndale. We recorded an impairment loss of approximately $180 million based upon the anticipated sales proceeds. We sold our remaining interest in Auburndale on November 21, 2008.

The sales of the Hillabee and Fremont development projects and the sale of Auburndale did not meet the criteria for discontinued operations due to our continuing activity in the markets in which these power plants were located; therefore, the results of operations for all periods prior to sale are included in our continuing operations.

2007

On January 16, 2007, we completed the sale of the Aries Power Plant, a 590 MW natural gas-fired power plant in Pleasant Hill, Missouri, to Dogwood Energy LLC, an affiliate of Kelson Holdings, LLC, for $234 million plus certain per diem expenses incurred by us for running the power plant after December 21, 2006, through the closing of the sale. We recorded a pre-tax gain of approximately $78 million included in reorganization items on our Consolidated Statements of Operations. As part of the sale we were also required to use a portion of the proceeds received to repay approximately $159 million principal amount of financing obligations, $8 million in accrued interest, $11 million in accrued swap liabilities and $14 million in debt pre-payment, and make whole premium fees to our project lenders.

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On February 21, 2007, we completed the sale of substantially all of the assets of the Goldendale Energy Center, a 247 MW natural gas-fired power plant located in Goldendale, Washington, to Puget Sound Energy LLC for approximately $120 million, plus the assumption by Puget Sound Energy LLC of certain liabilities. We recorded a pre-tax gain of approximately $31 million included in reorganization items on our 2007 Consolidated Statements of Operations.

On March 22, 2007, we completed the sale of substantially all of the assets of PSM, a designer, manufacturer and marketer of turbine and combustion components, to Alstom Power Inc. for approximately $242 million, plus the assumption by Alstom Power Inc. of certain liabilities. In connection with the sale, we entered into a parts supply and development agreement with PSM whereby we committed to purchase turbine parts and other services totaling approximately $200 million over a five-year period. We recorded a pre-tax gain of $135 million included in reorganization items on our 2007 Consolidated Statements of Operations.

On July 6, 2007, we completed the sale of the Parlin Power Plant, a 118 MW natural gas-fired power plant in Parlin, New Jersey, to EFS Parlin Holdings, LLC, an affiliate of General Electric Capital Corporation, for approximately $3 million in cash, plus the assumption by EFS Parlin Holdings, LLC of certain liabilities and the agreement to waive certain asserted claims against the Parlin Power Plant. We recorded a pre-tax gain of approximately $40 million included in reorganization items on our 2007 Consolidated Statements of Operations.

On September 13, 2007, we completed the sale of our 50% interest in Acadia PP, the owner of the Acadia Energy Center, a 1,212 MW natural gas-fired power plant located near Eunice, Louisiana, to Cajun Gas Energy, L.L.C. for consideration totaling approximately $189 million consisting of $104 million in cash and the payment of $85 million in priority distributions due to Cleco Corp. (the indirect owner, through its wholly owned subsidiary, Acadia Power Holdings, LLC, of the remaining 50% ownership interest in Acadia PP) in accordance with the limited liability company agreement, plus the assumption by Cajun Gas Energy, L.L.C. of certain liabilities. We recorded a pre-tax loss of $6 million, after recording a pre-tax, predominately non-cash impairment charge of approximately $89 million, to record our interest in Acadia PP at fair value less the cost to sell, both charges are included in reorganization items on our Consolidated Statements of Operations. Additionally, in connection with the sale, we entered into a settlement agreement with Cleco Corp., which was approved by the U.S. Bankruptcy Court on May 9, 2007, under which Cleco Corp. received an allowed unsecured claim against us in the amount of $85 million as a result of the rejection by CES of two long-term PPAs for the output of the Acadia Energy Center and our guarantee of those agreements. We recorded expense of $85 million for this allowed claim during the second quarter of 2007, which is included in reorganization items on our 2007 Consolidated Statements of Operations.

The sales of the Aries Power Plant, the Goldendale Energy Center, the Parlin Power Plant and our interest in Acadia PP did not meet the criteria for discontinued operations due to our continuing activity in the markets in which these power plants operate or were located; therefore, the results of operations for all periods prior to sale are included in our continuing operations. Similarly, we have determined that the sale of PSM did not meet the criteria for discontinued operations due to our continuing involvement through the parts supply and development agreement; therefore, the results of operations for all periods prior to sale are included in our continuing operations.

Discontinued Operations

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. 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 outstanding project debt at closing 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. Our results of operations for Blue Spruce and Rocky Mountain are reported as discontinued operations for the years ended December 31, 2009, 2008 and 2007, respectively. However, there was no change to our total consolidated net income and there was no effect on our Consolidated Balance Sheets, Consolidated Statements of Comprehensive Income (Loss) and Stockholders’ Equity (Deficit) or our Consolidated Statements of Cash Flows included in our 2009 Form 10-K. We have not presented our assets and liabilities related to Blue Spruce and Rocky Mountain as assets held for sale as they were not considered by management to be held for sale as of December 31, 2009.

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Rosetta Settlement

On December 1, 2008, the U.S. Bankruptcy Court finalized the settlement with Rosetta for all of our outstanding claims related to our domestic oil and gas assets we sold to Rosetta for $1.1 billion in 2005. Under the settlement, Rosetta paid us $97 million; we completed the transfer of certain other assets; we and Rosetta extended an existing natural gas purchase agreement for an additional ten years; and we and Rosetta executed mutual releases.

The original sale of our domestic oil and gas assets was recorded as discontinued operations on our 2005 Consolidated Statement of Operations. Of the $97 million settlement proceeds received, $79 million was associated with the certain other assets with a remaining net book value of approximately $42 million related to our domestic oil and gas assets we sold to Rosetta in 2005. The resulting $37 million gain is reflected as discontinued operations on our 2008 Consolidated Statement of Operations. The remaining $18 million settlement proceeds received was associated with the agreed upon fraudulent conveyance of $12 million, which is included in reorganization items on our 2008 Consolidated Statement of Operations, and approximately $6 million in revenues collected by Rosetta during the litigation period on assets retained by us.

The table below presents the components of our discontinued operations for the years ended December 31, 2009, 2008 and 2007 (in millions):

	2009		2008		2007
Operating revenues	$	101	$	100	$	101
Income from discontinued operations before taxes		35		59		27
Less:  Income tax expense		—		23		—
Discontinued operations, net of tax	$	35	$	36	$	27

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7. Debt

Our debt at December 31, 2009 and 2008, was as follows (in millions):

	2009		2008
First Lien Credit Facility	$	4,661	$	6,645
First Lien Notes		1,200		—
Commodity Collateral Revolver		100		100
Project financing		1,562		1,525
CCFC New Notes		959		—
CCFC Old Notes and CCFC Term Loans		—		778
Preferred interests		25		335
Notes payable and other borrowings		253		356
Capital lease obligations		699		733
Total debt		9,459		10,472
Less: Current maturities		463		716
Debt, net of current portion	$	8,996	$	9,756

Annual Debt Maturities

Contractual annual principal repayments or maturities of debt instruments as of December 31, 2009, are as follows (in millions):

2010	$	477
2011		642
2012		275
2013		156
2014		4,463
Thereafter		3,508
Total debt		9,521
Less: Discount		62
Total	$	9,459

First Lien Facilities

Upon our emergence from Chapter 11, we converted the approximately $4.9 billion of loans and commitments outstanding under our DIP Facility (including the $1.0 billion revolver) into loans and commitments under our approximately $7.3 billion of First Lien Facilities. Our First Lien Facilities provided for approximately $2.1 billion in senior secured term loans and $300 million in senior secured bridge loans in addition to the loans and commitments that had been available under the DIP Facility. Our First Lien Facilities include:

• Our First Lien Credit Facility, comprised of:

i. approximately $6.0 billion of senior secured term loans;

ii. a $1.0 billion senior secured revolving facility; and

iii. the ability to raise up to $2.0 billion of incremental term loans available on a senior secured basis in order to refinance secured debt of subsidiaires under an "accordion" provision; and

• a bridge facility, which, prior to its repayment as described below, provided for a $300 million senior secured bridge term loan.

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On the Effective Date, we fully drew on our approximately $6.0 billion of senior secured term loans and $300 million bridge facility and we drew approximately $150 million under the $1.0 billion senior secured revolving facility. The proceeds of the drawdowns, above the amounts that had been applied under the DIP Facility, were used to repay a portion of the Second Priority Debt, fund distributions under our Plan of Reorganization to holders of other secured claims and to pay fees, costs, commissions and expenses in connection with our First Lien Facilities and the implementation of our Plan of Reorganization.

The bridge facility was repaid in full on March 6, 2008, in accordance with its terms with proceeds from the sales of the Hillabee and Fremont development project assets. Prior to repayment, borrowings under the bridge facility bore interest at LIBOR plus 2.875% per annum.

On October 2, 2008, we borrowed $725 million under our First Lien Credit Facility revolving facility. The borrowing was made as a base rate loan which initially bore interest at the base rate (5% on date of borrowing) plus 1.875% per annum. Proceeds from the borrowing were invested in money market funds, which are mainly invested in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. government, its agencies or instrumentalities. On September 28, 2009, we repaid $725 million previously drawn under our First Lien Credit Facility revolver from cash on hand.

As of December 31, 2009, under our First Lien Credit Facility, we had approximately $4.7 billion outstanding under the term loan facilities and $206 million of letters of credit issued against the revolver. 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. Our First Lien Credit Facility matures on March 29, 2014.

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 contains restrictions, including limiting our ability to, among other things:

• incur additional indebtedness and issue certain stock;

• make prepayments on or purchase certain indebtedness in whole or in part;

• pay dividends and other distributions with respect to our stock or repurchase our stock or make other restricted payments;

• use money borrowed under our First Lien Credit Facility for non-guarantors (including foreign subsidiaries);

• make certain investments;

• create or incur liens;

• consolidate or merge with another entity, or allow one of our subsidiaries to do so;

• lease, transfer or sell assets and use proceeds of permitted asset leases, transfers or sales;

• pay dividends or make other distributions from certain of our subsidiaries up to Calpine Corporation;

• make capital expenditures beyond specified limits;

• engage in certain business activities;

• enter into certain transactions with our affiliates; and

• acquire power plants or other businesses.

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.

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Amendment of First Lien Credit Facility and Issuance of First Lien Notes due 2017

We executed the First Amendment to Credit Agreement and Second Amendment to Collateral Agency and Intercreditor Agreement dated as of August 20, 2009, which amended both the First Lien Credit Facility Credit Agreement and the First Lien Credit Facility Collateral Agency and Intercreditor Agreement. The amendment provides additional flexibility with our capital structure and First Lien Credit Facility by granting us the option, subject to certain conditions, to buy back debt at a discount using cash on hand via an auction process; to offer first lien bonds in exchange for or to retire First Lien Credit Facility term loans; to issue up to $2.0 billion of first lien bonds in lieu of issuing first lien term loans under the accordion provision of our First Lien Credit Facility; and to extend all or a portion of the revolver and term loan maturities, on revised terms, subject to acceptance by applicable lenders. In addition, the amendment provides for the aggregation of various investment and capital expenditure baskets for covenant purposes.

We subsequently issued approximately $1.2 billion aggregate principal amount of First Lien Notes in a private placement on October 21, 2009. We received no net cash proceeds from the transaction. The offer and sale of our First Lien Notes was consummated as a permitted debt exchange pursuant to our First Lien Credit Facility in exchange for a like principal amount of First Lien Credit Facility term loans. Upon their exchange for First Lien Notes, such term loans were canceled and may not be redrawn. Our First Lien Notes bear interest at 7.25% per annum payable on April 15 and October 15 of each year, beginning on April 15, 2010. Our First Lien Notes will mature on October 15, 2017; however, among other things, prior to October 15, 2012, we may redeem up to 35% of the aggregate principal amount of our First Lien Notes with the net cash proceeds of certain equity offerings, at a price equal to 107.25% of the aggregate principal amount thereof, plus accrued and unpaid interest. Beginning on October 15, 2013, we may redeem all or a portion of our First Lien Notes at a premium as defined in the indenture governing our First Lien Notes, plus accrued and unpaid interest. Our First Lien Notes are guaranteed by each of our current and future domestic subsidiaries that is a borrower or guarantor under our First Lien Credit Facility and 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. Our First Lien Notes are secured equally and ratably with indebtedness under our First Lien Credit Facility 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.

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

• incur or guarantee additional first lien indebtedness;

• enter into certain prohibited commodity hedge agreements;

• enter into sale and leaseback transactions;

• create or incur liens; and

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

In connection with the amendment of our First Lien Credit Facility and issuance of our First Lien Notes, we recorded approximately $25 million in debt extinguishment costs related to the retirement of the term loans under our First Lien Credit Facility and approximately $25 million in new deferred financing costs on our Consolidated Balance Sheet during 2009.

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Project Financing

The components of our project financing are (in millions, except for interest rates):

	Outstanding at December 31,				Weighted Average Effective Interest  Rates(2)
	2009		2008		2009			2008
Bethpage Energy Center 3, LLC due 2020-2025(1)	$	107	$	112		7.0	%		6.9	%
Gilroy Energy Center, LLC due 2011		76		113		7.3			7.3
Blue Spruce due 2017		76		83		4.9			5.8
Riverside Energy Center, LLC due 2011		311		328		7.6			9.3
Rocky Mountain Energy Center, LLC due 2011		140		164		7.7			9.9
Metcalf due 2015		261		264		7.0			7.9
Steamboat due 2017		452		453		6.9			6.5
Deer Park due 2012		128		—		7.5			—
Other		11		8		—			—
Total	$	1,562	$	1,525

__________

(1) Represents a weighted average of first and second lien loans.

(2) Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.

Our project financings are collateralized solely by the capital stock or partnership interests, physical assets, contracts and/or cash flows attributable to the entities that own the power plants. The lenders recourse under these project financings is limited to such collateral.

On November 24, 2009, Steamboat amended and extended the terms of its credit agreement. The Steamboat Amended Credit Facility increases the amount of term loans outstanding by $17 million from $448 million to $465 million. The increase in the borrowing was used to pay accrued and unpaid interest, breakage costs and other fees in connection with closing the Steamboat Amended Credit Facility. The Steamboat Amended Credit Facility also provides for a “security fund” letter of credit facility of up to $11 million and a “DSR” letter of credit facility of up to approximately $23 million. The maturity date of the term loans facilities has been extended from December 2011 to November 24, 2017. The security fund letter of credit facility, matures on November 24, 2017 with the term loans and the DSR letter of credit facility matures on September 29, 2017. We recorded approximately $7 million in new deferred financing costs on our Consolidated Balance Sheet as of December 31, 2009, and approximately $2 million in debt extinguishment costs related to the write-off of the old deferred financing costs on our Consolidated Statement of Operations for the year ended December 31, 2009.

Interest on the term loans is at a base rate or LIBOR (as defined in the Steamboat Amended Credit Facility) as elected by Steamboat plus a rate margin which escalates from 2.875% to 3.375% (less 1% for a base rate loan) during the term of the Steamboat Amended Credit Facility. Principal and interest are due and payable on the last banking day of each calendar quarter. Steamboat may, at its option convert the interest rate on all or a portion of the amounts outstanding under the term loans to the one month, three month or six month LIBOR rate plus the rate margin and may convert any LIBOR rate loan back to a base rate loan. Both the security fund and “DSR” letter of credit facilities incur a commitment fee equal to 1.0% for the average unutilized letters of credit and a letter of credit participation fee equal to the rate margin for the stated amount of the issued letters of credit. Under the Steamboat Amended Credit Facility we are required to hedge a minimum of 75% of our interest rate exposure, and as of December 31, 2009, we have hedged approximately 95% of this interest rate exposure with interest rate swaps. See Note 9 for further discussion regarding our interest rate swaps.

Subject to certain limitations and minimum amounts, Steamboat may elect to permanently reduce the commitment amounts under both the security fund and DSR letter of credit facilities and prepay, without penalty, in whole or in part, the amounts outstanding under the term loans. The Steamboat Amended Credit Facility contains certain restrictive covenants and allows for acceleration of the debt in the event of certain defaults and is secured, subject to certain exceptions and permitted liens, by all real and personal property of Steamboat and its wholly owned subsidiaries, Freeport Energy Center and Mankato Power Plant.

On January 21, 2009, Deer Park, our indirect wholly owned subsidiary, closed on $156 million of senior secured credit facilities, which include a $150 million term facility and a $6 million letter of credit facility. Proceeds received were used to settle an existing commodity contract of approximately $79 million, pay financing and legal fees of approximately $8 million and fund approximately $22 million in restricted cash. The remainder was distributed to Calpine Corporation for general corporate purposes. The senior term loan facility matures on January 21, 2012, and bears interest of LIBOR plus 3.5% or base rate plus 2.5% at Deer Park’s option.

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On June 10, 2008, Metcalf, an indirect wholly owned subsidiary, closed on a $265 million new term loan facility. The proceeds were used to repay Metcalf’s existing $100 million term loan facility and $155 million preferred interests. The new term loan facility, which matures on June 10, 2015, bears interest at Metcalf’s option at LIBOR plus 3.25% or base rate plus 2.25% and is secured by the assets of Metcalf and the sole member interest held by Metcalf’s parent, Metcalf Holdings, LLC. In connection with this refinancing, we recorded $6 million in loss on debt extinguishment, related to the write-off of deferred financing costs of $3 million and prepayment penalties of $3 million, which are recorded in debt extinguishment costs on our 2008 Consolidated Statement of Operations.

On February 1, 2008, Blue Spruce, an indirect wholly owned subsidiary, entered into a $90 million senior term loan. Net proceeds from the senior term loan were used to refinance all outstanding indebtedness under the existing Blue Spruce term loan facility, to pay fees and expenses related to the transaction and for general corporate purposes. The senior term loan carries interest at a base rate plus 0.63% which escalates to 1.50% or LIBOR plus 1.63%, which escalates to 2.50% over the life of the senior term loan and matures December 31, 2017. The senior term loan is secured by the assets of Blue Spruce. In connection with this refinancing, we recorded $7 million in loss on debt extinguishment, related to the write-off of deferred financing costs of $4 million and prepayment penalties of $3 million, which are recorded in discontinued operations on our 2008 Consolidated Statement of Operations.

CCFC New Notes, CCFC Old Notes and CCFC Term Loans

On May 19, 2009, our wholly owned subsidiaries, CCFC and CCFC Finance, issued approximately $1.0 billion aggregate principal amount of CCFC New Notes in a private placement. Interest on the CCFC New Notes accrues at the rate of 8.0% per annum and is payable semi-annually in arrears on each June 1 and December 1, commencing on December 1, 2009. The CCFC New Notes, which mature on June 1, 2016, are guaranteed by two of CCFC’s subsidiaries. The CCFC New Notes and the related guarantees are secured, subject to certain exceptions and permitted liens, by all real and personal property of CCFC and CCFC’s material subsidiaries (including the CCFC Guarantors), consisting primarily of six natural gas power plants as well as the equity interests in CCFC and the CCFC Guarantors. The CCFC New Notes are not guaranteed by Calpine Corporation and are without recourse to Calpine Corporation or any of our other non-CCFC or CCFC Finance subsidiaries or assets. The net proceeds received of $939 million, together with CCFC cash on hand of $271 million, were used to:

• repay the $364 million outstanding under the CCFC Term Loans on May 19, 2009;

• redeem the $415 million outstanding principal amount of CCFC Old Notes on June 18, 2009;

• distribute $327 million to CCFC’s indirect parent, CCFCP, which was used by CCFCP to redeem its $300 million CCFCP Preferred Shares discussed below on or before July 1, 2009; and

• in each case, pay any interest, prepayment penalties and other amounts due through the date of such repayment or redemption.

In connection with the CCFC Refinancing, we recorded $49 million in debt extinguishment costs for the year ended December 31, 2009. Debt extinguishment costs are comprised of $7 million from the write-off of unamortized deferred financing costs and unamortized debt discount, $24 million of prepayment penalties related to redemption of the CCFC Old Notes, $2 million from the write-off of unamortized deferred financing costs and unamortized debt discount and $16 million related to prepayment penalties related to the redemption of the CCFCP Preferred Shares.

We also recorded approximately $21 million in new deferred financing costs on our Consolidated Balance Sheet upon closing the CCFC Refinancing.

The components of the CCFC financing are (in millions, except for interest rates):

	Outstanding at December 31,				Weighted Average Effective Interest  Rates(2)
	2009		2008		2009			2008
CCFC Old Notes (1)	$	—	$	412		—	%		12.6	%
CCFC Term Loans (1)		—		366		—			10.3
CCFC New Notes		959		—		8.9			—
Total CCFC financing	$	959	$	778

__________

(1) The CCFC Old Notes and CCFC Term Loans were repaid with the proceeds from the CCFC New Notes during 2009.

(2) Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.

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Preferred Interests

Our preferred interests meet the criteria of mandatorily redeemable financial instruments and are therefore classified as debt. The components of preferred interests are as follows (in millions, except for interest rates):

	Outstanding at December 31,				Weighted Average Effective Interest  Rates(2)
	2009		2008		2009			2008
Preferred interest in GEC Holdings, LLC due 2011	$	25	$	35		13.9	%		14.8	%
Preferred interest in CCFCP due 2011(1)		—		300		—			13.5
Total preferred interests	$	25	$	335

__________

(1) Amounts were repaid with the proceeds from the CCFC New Notes during 2009.

(2) Our weighted average interest rate calculation includes the amortization of deferred financing costs.

Notes Payable and Other Borrowings

The components of notes payable and other borrowings are (in millions, except for interest rates):

	Outstanding at December 31,				Weighted Average Effective Interest  Rates(2)
	2009		2008		2009			2008
PCF III due 2010(1)	$	84	$	76		11.3	%		10.2	%
PCF due 2010(1)		55		159		9.6			9.6
Gilroy note payable due 2014		77		89		10.6			10.7
Whitby Holdings due 2017		31		26		8.9			9.5
Other		6		6		4.8			6.0
Total notes payable and other borrowings	$	253	$	356

__________

(1) Amounts were repaid from cash on hand on February 1, 2010 and February 5, 2010, for PCF and PCF III, respectively.

(2) Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.

Capital Lease Obligations

The following is a schedule by year of future minimum lease payments under capital leases together with the present value of the net minimum lease payments as of December 31, 2009 (in millions):

2010	$	98
2011		99
2012		96
2013		92
2014		79
Thereafter		802
Total minimum lease payments		1,266
Less: Amount representing interest		567
Present value of net minimum lease payments	$	699

The primary types of property leased by us are power plants and related equipment. The leases generally provide for the lessee to pay taxes, maintenance, insurance, and certain other operating costs of the leased property. The remaining lease terms range up to 39 years (including lease renewal options). Some of the lease agreements contain customary restrictions on dividends, additional debt and further encumbrances similar to those typically found in project financing agreements. As of both December 31, 2009 and 2008, the asset balances for the leased assets totaled approximately $1.3 billion with accumulated amortization of $349 million and $279 million, respectively. See Note 17 for a discussion of capital leases guaranteed by Calpine Corporation.

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Other Financing Agreements

During the first quarter of 2008, we entered into a letter of credit facility related to our subsidiary Calpine Development Holdings, Inc. under which up to $150 million is available for letters of credit. On December 11, 2009, we amended the letter of credit facility to extend the maturity from January 31, 2010 to December 11, 2012, with an option to increase the letters of credit available from $150 million to $200 million by satisfying certain conditions. As of December 31, 2009 and 2008, $116 million and $148 million in letters of credit, respectively, had been issued under this facility.

On July 8, 2008, we entered into the Commodity Collateral Revolver, a two-year, $300 million secured revolving credit facility, which shares the benefits of the collateral subject to the liens under our First Lien Credit Facility ratably with the lenders under our First Lien Credit Facility. At closing, we borrowed an initial advance of $100 million. Amounts borrowed under the Commodity Collateral Revolver were used to collateralize obligations to counterparties under eligible commodity hedge agreements. On August 13, 2009, we terminated $200 million of the remaining availability under the Commodity Collateral Revolver in accordance with its terms as energy commodity prices were not expected to exceed stated thresholds in the near future and it was considered unlikely that any of the $200 million remaining availability would be available to us. The $100 million currently outstanding under the Commodity Collateral Revolver will mature on July 8, 2010, and bears interest at LIBOR plus 2.875% per annum.

On June 25, 2008, we entered into the Knock-in Facility, a 12-month, $200 million unsecured letter of credit facility. Availability of letters of credit for issuance under the Knock-in Facility were up to a total maximum availability of $200 million contingent on natural gas futures contract prices exceeding certain thresholds, with initial availability for up to $50 million. The Knock-in Facility matured on June 30, 2009, and is no longer available.

Letters of Credit Facilities

The table below represents amounts issued under our letter of credit facilities as of December 31, 2009 and 2008 (in millions):

	2009		2008
First Lien Credit Facility	$	206	$	259
Calpine Development Holdings, Inc.		116		148
Knock-in Facility(1)		—		50
Various project financing facilities		90		99
Total	$	412	$	556

__________

(1) The Knock-in Facility matured on June 30, 2009, and is no longer available.

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Fair Value of Debt

We record our debt instruments based on contractual terms, net of any applicable premium or discount. We did not elect to apply the alternative GAAP provisions of the fair value option for recording financial assets and financial liabilities at fair value on our Consolidated Financial Statements. We measured the fair value of our debt instruments as of 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 December 31, 2009 and 2008 (in millions):

	2009				2008
	Fair Value		Carrying Value		Fair Value		Carrying Value
First Lien Credit Facility	$	4,402	$	4,661	$	4,812	$	6,645
First Lien Notes		1,138		1,200		—		—
Commodity Collateral Revolver		94		100		85		100
Project financing		1,542		1,562		1,420		1,525
CCFC New Notes		1,030		959		—		—
CCFC Old Notes and CCFC Term Loans		—		—		727		778
Preferred interests		25		25		305		335
Notes payable and other borrowings		241		253		330		356
Total	$	8,472	$	8,760	$	7,679	$	9,739

8. Fair Value Measurements

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.

Our level 1 fair value derivative instruments primarily consist of natural gas swaps, futures and options traded on the NYMEX.

Our level 2 fair value derivative instruments primarily consist of interest rate swaps and OTC power and natural gas forwards for which market-based pricing inputs are observable. Generally, we obtain our level 2 pricing inputs from markets such as the Intercontinental Exchange. 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.

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.

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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, primarily 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.

The fair value of our derivatives includes consideration of our credit standing, the credit standing of our counterparties and the impact of credit enhancements, if any. We have also recorded credit reserves in the determination of fair value based on our expectation of how market participants would determine fair value. Such valuation adjustments are generally based on market evidence, if available, or our best estimate.

Margin Deposits — Our margin deposits are cash and cash equivalents and are generally classified within level 1 of the fair value hierarchy as the amounts approximate fair value.

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The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2009 and 2008, 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 the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	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(2)		413		—		—		413
Commodity derivative instruments		953		204		71		1,228
Interest rate swaps		—		18		—		18
Total assets	$	2,672	$	222	$	71	$	2,965
Liabilities:
Margin deposits held by us posted by our counterparties(2)	$	9	$	—	$	—	$	9
Commodity derivative instruments		1,096		91		33		1,220
Interest rate swaps		—		337		—		337
Total liabilities	$	1,105	$	428	$	33	$	1,566

	Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2008
	Level 1		Level 2		Level 3		Total
	(in millions)
Assets:
Cash equivalents(1)	$	2,092	$	—	$	—	$	2,092
Margin deposits(2)		653		—		—		653
Commodity derivative instruments		3,263		634		160		4,057
Total assets	$	6,008	$	634	$	160	$	6,802
Liabilities:
Margin deposits held by us posted by our counterparties(2)	$	169	$	—	$	—	$	169
Commodity derivative instruments		3,515		475		55		4,045
Interest rate swaps		—		452		—		452
Total liabilities	$	3,684	$	927	$	55	$	4,666

__________

(1) Amounts represent cash equivalents invested in money market accounts and are included in cash and cash equivalents and restricted cash on our Consolidated Balance Sheets. As of December 31, 2009 and 2008, we had cash equivalents of $770 million and $1,597 million included in cash and cash equivalents and $536 million and $495 million included in restricted cash, respectively.

(2) 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.

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Gains or losses associated with level 3 balances may not necessarily reflect trends occurring in the underlying business. Further, unrealized gains and losses for the period from level 3 items are often offset by unrealized gains and losses on positions classified in levels 1 or 2, as well as positions that have been realized during the period. Certain of our level 3 balances qualify for cash flow hedge accounting for which any unrealized gains and losses are recorded in OCI. Gains and losses for level 3 balances that do not qualify for hedge accounting are recorded in earnings.

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 years ended December 31, 2009 and 2008 (in millions):

	2009			2008
Balance, beginning of period	$	105		$	(23	)(1)
Realized and unrealized gains (losses):
Included in net income(2)		19			57
Included in OCI		(4	)		229
Purchases, issuances and settlements, net		(48	)		(97	)
Transfers in and/or out of level 3(3)		(34	)		(61	)
Balance, end of period	$	38		$	105
Change in unrealized gains relating to instruments still held at end of period(2)	$	19		$	57

__________

(1) Our portfolio of derivative assets and liabilities is adjusted for the day one loss of $(22) million, excluding the tax benefit of $8 million, recognized upon adoption of the new fair value measurement standards on January 1, 2008.

(2) Includes $5 million and $78 million recorded in operating revenues (for power contracts and Heat Rate swaps and options) and $14 million and $(21) million recorded in fuel and purchased energy expense (for natural gas contracts) for the years ended December 31, 2009 and 2008, respectively as shown on our Consolidated Statements of Operations.

(3) We transfer amounts among levels of the fair value hierarchy as of the end of each period.

9. Derivative Instruments

The following tables reflect the amounts that were recorded as derivative assets and liabilities on our Consolidated Balance Sheets at December 31, 2009 and 2008, for our derivative instruments (in millions):

	2009
	Interest Rate Swaps			Commodity Instruments		Total Derivative Instruments
Derivative assets, current	$	—		$	1,119	$	1,119
Long-term derivative assets		18			109		127
Total derivative assets	$	18		$	1,228	$	1,246
Derivative liabilities, current	$	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	)

	2008
	Interest Rate Swaps			Commodity Instruments		Total Derivative Instruments
Derivative assets, current	$	—		$	3,653	$	3,653
Long-term derivative assets		—			404		404
Total derivative assets	$	—		$	4,057	$	4,057
Derivative liabilities, current	$	179		$	3,620	$	3,799
Long-term derivative liabilities		273			425		698
Total derivative liabilities	$	452		$	4,045	$	4,497
Net derivative assets (liabilities)	$	(452	)	$	12	$	(440	)

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Commodity Instruments — We are exposed to changes in prices for the purchase and sale of power, natural gas and other energy commodities. We use derivatives, which include physical commodity contracts and financial commodity instruments such as OTC and exchange traded swaps, futures, options, forward agreements and instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) for the purchase and sale of power, natural gas, and emission allowances to attempt to maximize the risk-adjusted returns by economically hedging a portion of the commodity price risk associated with our assets. These transactions primarily act as fair value and cash flow hedges. 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 floating rate debt to hedge our interest rate risk for potential adverse changes in interest rates. These transactions primarily act as cash flow hedges for our variable rate debt.

As of December 31, 2009, the maximum length of our PPAs extend 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 3 and 16 years, respectively.

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. Unless these instruments settle by means of the physical delivery of a commodity, revenues and expenses derived from these instruments that qualify for hedge accounting are recorded in the period and same financial statement line item as the hedged item. 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 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), fuel and purchased energy expense (for natural gas contracts) 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. If the hedging instrument is terminated or de-designated prior to the occurrence of the hedged forecasted transaction, the gain or loss associated with 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.

Fair Value Hedges — Changes in fair value of derivatives designated as fair value hedges and the corresponding changes in the fair value of the hedged risk attributable to a recognized asset or liability, or unrecognized firm commitment are recorded in earnings. If the fair value hedge is effective, the amounts recorded will offset in earnings. If the underlying asset, liability or firm commitment being hedged is disposed of or otherwise terminated, the gain or loss associated with the underlying hedged item is recognized currently in earnings. If the hedging instrument is terminated or de-designated prior to the settlement of the hedged asset, liability or firm commitment, the carrying amount of the hedged item is adjusted by any gain or loss from the hedging instrument and remains until the hedged item is recognized in earnings. We had no fair value hedges at December 31, 2009; however, we had one fair value hedge at December 31, 2008 related to PCF.

Derivatives Not Designated as Hedging Instruments — Along with our portfolio of hedging instruments, 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 hedge accounting guidelines or qualify under the hedge accounting guidelines and the hedge accounting designation has not been elected, such as commodity futures, forwards, options, fixed for floating swaps and instruments that settle on power price to natural gas price relationships (Heat Rate swaps and options). 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) and interest expense (for interest rate swaps).

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Derivatives Included on Our Consolidated Balance Sheet

The following table presents the fair values of our net derivative instruments recorded on our Consolidated Balance Sheet by hedge type and location at December 31, 2009 (in millions):

	Fair Value of  Derivative Assets(1)		Fair Value of  Derivative Liabilities(2)
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

__________

(1) Included in derivative assets on our Consolidated Balance Sheet as of December 31, 2009.

(2) Included in derivative liabilities on our Consolidated Balance Sheet as of December 31, 2009.

We execute forward physical and financial commodity purchase and sales agreements to hedge our exposure to underlying commodity risk. Through hedging and optimization activities it is not uncommon for us to purchase and sell forward natural gas and power in both the physical and financial markets. As of 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):

Derivative Instruments	Notional Volumes
Power (MWh)		(52	)
Natural gas (MMBtu)		78
Interest rate swaps	$	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. The aggregate fair value of our derivative liabilities with credit-contingent provisions as of December 31, 2009, was $156 million for which we have posted collateral of $5 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. However, if our credit rating were downgraded, we estimate that any additional collateral would not be material and that no counterparty could request immediate, full settlement.

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Derivatives Included on Our Consolidated Statements of Operations, OCI and AOCI

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 cash flow hedge accounting treatment, or on our Consolidated 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 Statements of Operations for the years ended December 31, 2009, 2008 and 2007 (in millions):

	2009			2008			2007
Realized gain (loss)
Interest rate swaps	$	(32	)	$	(9	)	$	3
Commodity derivative instruments(1)		37			(146	)		40
Total realized gain (loss)	$	5		$	(155	)	$	43
Unrealized gain (loss)(2)
Interest rate swaps	$	8		$	(11	)	$	(15	)
Commodity derivative instruments		79			35			(35	)
Total unrealized gain (loss)	$	87		$	24		$	(50	)
Total mark-to-market activity	$	92		$	(131	)	$	(7	)

__________

(1) Balance includes a non-cash gain from amortization of prepaid power sales agreements of approximately nil, $40 million and $54 million for the years ended December 31, 2009, 2008 and 2007, respectively.

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

	2009			2008			2007
Power contracts included in operating revenues	$	7		$	232		$	252
Natural gas contracts included in fuel and purchased energy expense		109			(343	)		(247	)
Interest rate swaps included in interest expense		(24	)		(20	)		(12	)
Total mark-to-market activity	$	92		$	(131	)	$	(7	)

The following table details the effect of our net derivative instruments that qualified for hedge accounting treatment on our Consolidated Statements of Operations and OCI, and the ineffectiveness related to our hedging instruments for the year ended December 31, 2009 (in millions):

	Gain (Loss) Recognized in OCI (Effective Portion)			Gain (Loss) Reclassified from OCI into Income (Effective Portion)(3)			Gain (Loss) Reclassified from OCI into Income (Ineffective Portion)
Commodity derivative instruments	$	(280	)	$	549	(1)	$	—	(2)
Interest rate swaps included in interest expense		125			(214	)		—
Total	$	(155	)	$	335		$	—

__________

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

(2) The ineffective portion of gains (losses) reclassified from AOCI into income on commodity hedging instruments was $2 million and $(2) million for the years ended December 31, 2008 and 2007, respectively.

(3) Cumulative net cash flow hedge losses included in AOCI were $261 million and $149 million at December 31, 2009 and 2008, respectively.

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Assuming constant December 31, 2009 power and natural gas prices and interest rates, we estimate that pre-tax net losses of $94 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 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 into earnings (positive or negative) will be for the next 12 months.

10. 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 would share the benefits of the collateral subject to such first priority liens ratably with the lenders under our First Lien Credit Facility.

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 December 31, 2009 and 2008 (in millions):

	2009		2008
Margin deposits(1)	$	413	$	653
Natural gas and power prepayments		34		60
Total margin deposits and natural gas and power prepayments with our counterparties(2)	$	447	$	713
Letters of credit issued	$	353	$	455
First priority liens under power and natural gas agreements(3)		—		—
First priority liens under interest rate swap agreements		333		477
Total letters of credit and first priority liens with our counterparties	$	686	$	932
Margin deposits held by us posted by our counterparties(1)(4)	$	9	$	169
Letters of credit posted with us by our counterparties		70		95
Total margin deposits and letters of credit posted with us by our counterparties	$	79	$	264

__________

(1) Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated Balance Sheets.

(2) $426 million and $693 million were included in margin deposits and other prepaid expense on our Consolidated Balance Sheets at December 31, 2009 and 2008, respectively, and $21 million and $20 million were included in other assets at December 31, 2009 and 2008, respectively.

(3) The fair value of our commodity derivative instruments collateralized by first priority liens included assets of $123 million and $201 million at December 31, 2009 and 2008, respectively; therefore, there was no collateral exposure at December 31, 2009 and 2008.

(4) Included in other current liabilities on our Consolidated 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.

11. Income Taxes

Income Tax Expense (Benefit)

The jurisdictional components of income (loss) from continuing operations before income tax expense (benefit) and discontinued operations, attributable to Calpine, for the years ended December 31, 2009, 2008 and 2007, are as follows (in millions):

	2009		2008			2007
U.S.	$	116	$	(52	)	$	2,133
International		13		(30	)		(13	)
Total	$	129	$	(82	)	$	2,120

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The components of income tax expense (benefit) from continuing operations for the years ended December 31, 2009, 2008 and 2007, consisted of the following (in millions):

	2009			2008			2007
Current:
Federal	$	(2	)	$	3		$	(25	)
State		(2	)		3			11
Foreign		3			(66	)		(15	)
Total current		(1	)		(60	)		(29	)
Deferred:
Federal		13			3			(449	)
State		4			1			(68	)
Foreign		(1	)		—			—
Total deferred		16			4			(517	)
Total income tax expense (benefit)	$	15		$	(56	)	$	(546	)

For the years ended December 31, 2009, 2008 and 2007, our income tax rates did not bear a customary relationship to statutory income tax rates, primarily as a result of the impact of our valuation allowance, state income taxes and changes in unrecognized tax benefits. A reconciliation of the federal statutory rate of 35% to our effective rate from continuing operations for the years ended December 31, 2009, 2008 and 2007, is as follows:

	2009			2008			2007
Federal statutory tax expense (benefit) rate		35.0	%		(35.0	)%		35.0	%
State tax expense (benefit), net of federal benefit		1.0			6.1			(2.6	)
Depletion in excess of basis		—			(8.9	)		—
Valuation allowances		(139.2	)		236.8			6.2
Foreign taxes		(9.2	)		(57.6	)		1.6
Non-deductible reorganization items		1.3			(86.6	)		(66.1	)
Income from cancellation of indebtedness		69.0			32.0			—
Intraperiod allocation pursuant to OCI		45.4			(90.9	)		—
Bankruptcy settlement		—			(67.7	)		—
Change in unrecognized tax benefits		1.4			4.3			(1.9	)
Permanent differences and other items		6.9			(0.8	)		2.0
Effective income tax expense (benefit) rate		11.6	%		(68.3	)%		(25.8	)%

Deferred Tax Assets and Liabilities

The components of the deferred income taxes, net of current portion as of December 31, 2009 and 2008, are as follows (in millions):

	2009			2008
Deferred tax assets:
NOL and credit carryforwards	$	3,209		$	3,310
Taxes related to risk management activities and derivatives		81			10
Reorganization items and impairments		571			583
Foreign capital losses		68			51
Other differences		10			6
Deferred tax assets before valuation allowance		3,939			3,960
Valuation allowance		(2,572	)		(2,685	)
Total deferred tax assets		1,367			1,275
Deferred tax liabilities: property, plant and equipment		(1,417	)		(1,352	)
Net deferred tax liability		(50	)		(77	)
Less: Current portion deferred tax asset (liability)		(8	)		1
Less: Non-current deferred tax asset		12			15
Deferred income taxes, net of current portion	$	(54	)	$	(93	)

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For federal income tax reporting purposes, our consolidated GAAP financial 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. 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 December 31, 2009, the CCFC group did not have a valuation allowance recorded against its deferred tax assets due to management’s assessment that the CCFC group would more likely than not utilize its NOLs prior to their expiration.

In accordance with GAAP, intraperiod tax allocation provisions require allocation of a tax benefit to continuing operations due to current gains in OCI and discontinued operations. We have recorded a tax expense of $43 million included in our income before discontinued operations on our 2009 Consolidated Statement of Operations, with an offsetting $43 tax benefit in OCI and $0 tax benefit in income from discontinued operations. We recorded a tax benefit of $99 million included in our loss before discontinued operations on our 2008 Consolidated Statement of Operations, with an offsetting $76 million tax expense in OCI and a $23 million tax expense in income from discontinued operations, both of which are reflected in deferred tax benefit.

NOL Carryforwards —Our carryforwards consist primarily of federal NOL carryforwards of approximately $7.5 billion, which expire between 2021 and 2029, and state NOL carryforwards of approximately $4.6 billion, which expire between 2010 and 2029. The NOL carryforwards available are subject to limitations on their annual usage. This includes an NOL carryforward of approximately $513 million for the CCFC group. Under federal and applicable state income tax laws, a corporation is generally permitted to deduct from taxable income in any year NOLs carried forward from prior years subject to certain time limitations as prescribed by the taxing authorities. In addition, we have approximately $1.1 billion in foreign NOLs, substantially all of which are offset with a full valuation allowance.

Under federal income tax law, our NOL carryforwards can be utilized to reduce future taxable income subject to certain limitations, including if we were to undergo an ownership change as defined by Section 382 of the IRC. We experienced an ownership change on the Effective Date as a result of the cancellation of our old common stock and the distribution of our new common stock pursuant to our Plan of Reorganization. However, this ownership change and 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. Additionally, as of December 31, 2009, approximately $2.0 billion of our $7.5 billion NOLs are not limited under Section 382 of the IRC. When considering our annual Section 382 limitations in addition to our NOLs that are not limited, our total unlimited NOLs available to offset future income are approximately $3.9 billion, as of December 31, 2009. However, 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, including the $2.0 billion of NOLs that are not currently limited by Section 382 of the IRC.

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 IRC. We believe, as of the filing of our 2009 Form 10-K, we have experienced declines in our stock price of more than 35% from our Emergence Date Market Capitalization. While we don’t 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 they 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.

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Valuation Allowance — GAAP requires that we consider all available evidence, both positive and negative, and tax planning strategies to determine whether, based on the weight of that evidence, a valuation allowance is needed to reduce the value of deferred tax assets. Future realization of the tax benefit of an existing deductible temporary difference or carryforward ultimately depends on the existence of sufficient taxable income of the appropriate character within the carryback or carryforward periods available under the tax law. Due to our history of losses, we were unable to assume future profits; however, at December 31, 2007, we were able to consider available tax planning strategies due to our expected emergence from Chapter 11. 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.

As of December 31, 2009, we have provided a valuation allowance of approximately $2.6 billion on certain federal, state and foreign tax jurisdiction deferred tax assets 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. The net change in our valuation allowance was a decrease of $113 million for the year ended December 31, 2009, and an increase of $284 million and $80 million for the years ended December 31, 2008 and 2007, respectively; all primarily related to our estimates of our ability to utilize our NOL carryforwards.

Canadian Tax Audits — In September 2009, we received notice from the Canadian Revenue Authority, or CRA, of their intent to conduct a limited scope income tax audit on four of our Canadian subsidiaries for the tax years ending 2005 – 2008. We have timely responded to their request for information and the CRA has not provided us with a timetable for their completion of the audit. At this time, we are unable to determine the likelihood that the outcome could have a material adverse impact to us.

Unrecognized Tax Benefits

As of December 31, 2009, we had unrecognized tax benefits of $98 million. If recognized, $41 million of our unrecognized tax benefits could impact the annual effective tax rate and $57 million related to deferred tax assets, of which, $48 million could be offset against the recorded valuation allowance and $9 million could reduce our deferred tax assets resulting in no impact to our effective tax rate. We also had accrued interest and penalties of $17 million for income tax matters as of December 31, 2009. The amount of unrecognized tax benefits increased by $8 million for the year ended December 31, 2009, primarily as a result of an increase of approximately $11 million for withholding taxes and foreign exchange losses and reductions of approximately $1 million due to cash settlements and $2 million in other non-cash settlements with various state taxing authorities.

A reconciliation of the beginning and ending amounts of our unrecognized tax benefits for the years ended December 31, 2009 and 2008, is as follows (in millions):

	2009			2008			2007
Balance, beginning of period	$	(90	)	$	(173	)	$	(240	)
Increases related to prior year tax positions		(11	)		(2	)		(28	)
Decreases related to prior year tax positions		2			6			8
Increases related to current year tax positions		—			(7	)		—
Settlements		1			84			87
Decrease related to lapse of statute of limitations		—			2			—
Balance, end of period	$	(98	)	$	(90	)	$	(173	)

We believe it is reasonably possible that a decrease of up to $1 million in unrecognized tax benefits related primarily to state tax exposures could be recorded within the next 12 months as a result of settlements with the tax authorities. We remain subject to 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 our significant NOLs, any adjustment to our federal returns would likely result in a reduction of deferred tax assets rather than a cash payment of income taxes.

12. Earnings (Loss) per Share

Pursuant to our Plan of Reorganization, all shares of our common stock outstanding prior to the Effective Date were canceled and the issuance of 485 million new shares of reorganized Calpine Corporation common stock was authorized to resolve allowed unsecured claims. A portion of the 485 million authorized shares was immediately distributed, and the remainder was reserved for distribution to holders of certain disputed claims that, although allowed as of the Effective Date, 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

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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 (loss) per common share computations for the years ended December 31, 2009, 2008 and 2007, are as follows (shares in thousands):

	2009		2008		2007
Diluted weighted average shares calculation:
Weighted average shares outstanding (basic)		485,659		485,054		479,235
Share-based awards		660		492		243
Weighted average shares outstanding (diluted)		486,319		485,546		479,478

We excluded the following items from diluted earnings (loss) per common share for the years ended December 31, 2009, 2008 and 2007 (shares in thousands):

	2009		2008		2007
Share-based awards(1)		13,158		7,259		17,315
Common stock warrants(1)(2)		—		29,158		—
Convertible Senior Notes(3)		—		—		399,914
Deutsche Bank AG London loaned shares(4)		—		—		17,401

__________

(1) Excluded from diluted weighted average shares outstanding as these share-based awards are anti-dilutive in accordance with the calculation under the treasury stock method prescribed by GAAP or because our closing stock price had not reached the price at which the shares vest.

(2) Pursuant to our Plan of Reorganization, holders of allowed interests (primarily holders of our old common stock canceled on the Effective Date) received a pro rata share of warrants to purchase approximately 48.5 million shares of our new, reorganized Calpine Corporation common stock at $23.88 per share. Warrants for 21,499 shares of common stock were exercised prior to expiration. The remaining warrants expired unexercised on August 25, 2008.

(3) Excluded from diluted weighted average shares outstanding as the conversion rights were terminated upon our Chapter 11 filings.

(4) Excluded from basic and diluted weighted average shares outstanding as the share lending agreement with Deutsche Bank AG London required physical settlement of these common shares.

Although earnings (loss) per share information for the years ended December 31, 2007, is presented, it is not comparable to the information presented for the years ended December 31, 2009 and 2008, due to the changes in our capital structure on the Effective Date, which also included termination of all outstanding convertible securities.

13. Stock-Based Compensation

Calpine Equity Incentive Plans

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 stock-based awards. Under the MEIP and DEIP there are 14,833,000 shares and 167,000 shares, respectively, of our common stock available 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. In addition, employment inducement options to purchase a total of 4,636,734 shares were granted outside of the Calpine Equity Incentive Plans in connection with our hiring of a new Chief Executive Officer and a new Chief Legal Officer in August 2008, and a new Chief Commercial Officer in September 2008. No grants of options or shares of restricted stock were made outside of the Calpine Equity Incentive Plans during the year ended December 31, 2009. Each of the employment inducement options vests over a period of five years, contains a contractual term of seven years and is subject to forfeiture under certain circumstances, including termination of employment prior to vesting.

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We use the Black-Scholes option-pricing model to estimate the fair value of our employee stock options on the grant date, which takes into account the exercise price and expected term of the stock option, the current price of the underlying stock and its expected volatility, expected dividends on the stock, and the risk-free interest rate for the expected term of the stock option as of the grant date. For our restricted stock and restricted stock units, we use our closing stock price on the date of grant, or the last trading day preceding the grant date for restricted stock granted on non-trading days, as the fair value for measuring compensation expense. Stock-based compensation expense is recognized over the period in which the related employee services are rendered. The service period is generally presumed to begin on the grant date and end when the equity award is fully vested. Stock options granted to our retirement eligible employees are fully vested on the date of retirement and therefore, compensation cost for those options is recognized on the date of grant. Restricted stock granted to our retirement eligible employees are cancelled on the date of retirement. 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 (income) recognized was $38 million, $50 million and $(1) million for the years ended December 31, 2009, 2008 and 2007, 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 years ended December 31, 2009, 2008 and 2007. At December 31, 2009, there was unrecognized compensation cost of $29 million related to options, $11 million related to restricted stock and nil related to restricted stock units, which is expected to be recognized over a weighted average period of 1.9 years for options, 1.7 years for restricted stock and 0.4 years for restricted stock units. We issue new shares from our reserves set aside for the Calpine Equity Incentive Plans and employment inducement options when stock options are exercised and for other stock-based awards.

A summary of all of our non-qualified stock option activity for the Calpine Equity Incentive Plans for the year ended December 31, 2009, is as follows:

	Number of Options		Weighted Average Exercise Price		Weighted Average Remaining Term (in years)		Aggregate Intrinsic Value (in millions)
Outstanding — December 31, 2008		12,840,754	$	19.72		7.5	$	—
Granted		929,651	$	9.46
Exercised		—	$	—
Forfeited		259,775	$	17.70
Expired		278,111	$	17.29
Outstanding — December 31, 2009		13,232,519	$	19.09		6.6	$	2
Exercisable — December 31, 2009		4,115,177	$	18.71		7.0	$	—
Vested and expected to vest — December 31, 2009		13,082,032	$	19.14		6.6	$	2

The total intrinsic value of our employee stock options exercised was nil for which we received approximately $1 million in cash proceeds during the year ended December 31, 2007, and there were no employee stock options exercised during the years ended December 31, 2009 and 2008.

The fair value of options granted during the years ended December 31, 2009 and 2008, was determined on the grant date using the Black-Scholes pricing model. Certain assumptions were used in order to estimate fair value for options as noted in the following table. No options were granted during the year ended December 31, 2007.

	2009			2008
Expected term (in years)(1)		6.0 – 6.5			5.0 –  6.1
Risk-free interest rate(2)		2.3 – 2.9	%		1.0 –  3.3	%
Expected volatility(3)		52.1 – 73.0	%		34.8 –  98.0	%
Dividend yield(4)		—			—
Weighted average grant-date fair value (per option)	$	5.67		$	6.48

__________

(1) Expected term calculated using the simplified method prescribed by the SEC.

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

(3) For the year ended December 31, 2009, we calculated volatility using the implied volatility of our exchange traded stock options. For the year ended December 31, 2008, we calculated volatility using the weighted average implied volatility of our industry peers’ 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 year ended December 31, 2009, is as follows:

	Number of Restricted Stock Awards		Weighted Average Grant-Date Fair Value
Nonvested — December 31, 2008		1,742,242	$	16.69
Granted		1,470,358	$	9.49
Forfeited		260,092	$	13.57
Vested		905,909	$	16.60
Nonvested — December 31, 2009		2,046,599	$	11.95

The total fair value of our restricted stock that vested during the years ended December 31, 2009 and 2008, was $8 million and $3 million, respectively, and no restricted stock or restricted stock units vested during the year ended December 31, 2007.

14. Defined Contribution Plans

We maintain two defined contribution savings plans that are intended to be tax exempt under Sections 401(a) and 501(a) of the IRC. Our non-union plan generally covers employees who are not covered by a collective bargaining agreement, and our union plan covers employees who are covered by a collective bargaining agreement. We recorded expenses for these plans of $9 million, $10 million and $9 million for the years ending December 31, 2009, 2008 and 2007, respectively.

Beginning January 1, 2008, the employer profit sharing contribution of 3% was eliminated and the employer matching contribution was increased to 100% of the first 5% of compensation a participant defers for the non-union plan. Beginning January 1, 2007, the employee deferral limits were increased from 60% to 75% of compensation under both plans.

15. Capital Structure

Common Stock

Pursuant to our Plan of Reorganization, all shares of our common stock outstanding prior to the Effective Date were canceled, and we authorized the issuance of 485 million new shares of reorganized Calpine Corporation common stock. As of December 31, 2009, approximately 440 million shares have been distributed to holders of allowed unsecured claims and approximately 45 million shares remain in reserve for distribution to holders of disputed claims whose claims ultimately become allowed. See Note 16 for further discussion of the shares of reorganized Calpine Corporation common stock.

Our authorized common stock consists of 1.4 billion shares of Calpine Corporation common stock. Common stock issued as of December 31, 2009 and 2008, was 443,325,827 shares and 429,025,057 shares, respectively, at a par value of $0.001 per share. Common stock outstanding as of December 31, 2009 and 2008, was 442,998,255 and 428,960,025, respectively.

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The table below summarizes our common stock activity since our emergence from Chapter 11 on the Effective Date. All shares of our common stock outstanding prior to the Effective Date were canceled and common stock activity prior to the Effective Date is not presented below as it is no longer meaningful.

	Shares Issued		Shares Held in Treasury			Shares Held in Reserve			Inter- Creditor Disputes			Total
Implementation of our Plan of Reorganization		410,992,508		—			64,255,231			9,752,261			485,000,000
Resolution of claims		16,093,028		—			(16,093,028	)		—			—
Exercise of warrants		21,499		—			—			—			21,499
Restricted stock, net of forfeitures		1,739,522		—			—			—			1,739,522
Vested restricted stock		178,500		(65,032	)		—						113,468
Balance at December 31, 2008		429,025,057		(65,032	)		48,162,203			9,752,261			486,874,489
Resolution of claims/inter-creditor disputes		13,167,420		—			(3,415,159	)		(9,752,261	)		—
Restricted stock, net of forfeitures		230,161		—			—			—			230,161
Vested restricted stock		903,189		(262,540	)		—			—			640,649
Balance at December 31, 2009		443,325,827		(327,572	)		44,747,044			—			487,745,299

Treasury Stock

As of December 31, 2009 and 2008, we had treasury stock of 327,572 shares and 65,032 shares, respectively, with a cost of $3 million and $1 million, respectively, which consists of our common stock withheld to satisfy federal, state and local income tax withholding requirements for employee restricted stock awards that vested in 2009 and 2008.

16. Our Emergence from Chapter 11

Summary of Proceedings

Summary of Proceedings and General Bankruptcy Matters — From the Petition Date through the Effective Date, we operated as a debtor-in-possession under the protection of the U.S. Bankruptcy Court following filings by Calpine Corporation and 274 of its wholly owned U.S. subsidiaries of voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. In addition, during that period, 12 of our Canadian subsidiaries that had filed for creditor protection under the CCAA also operated as debtors-in-possession under the jurisdiction of the Canadian Court.

During the pendency of our Chapter 11 cases through the Effective Date, pursuant to automatic stay provisions under the Bankruptcy Code and orders granted by the Canadian Court, all actions to enforce or otherwise effect repayment of liabilities preceding the Petition Date as well as all pending litigation against the Calpine Debtors generally were stayed. Following the Effective Date, actions to enforce or otherwise effect repayment of liabilities preceding the Petition Date, as well as pending litigation against the Calpine 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.

Plan of Reorganization — On June 20, 2007, the U.S. Debtors filed the Debtors’ Joint Plan of Reorganization and related Disclosure Statement, which were subsequently amended on each of August 27, September 18, September 24, September 27 and December 13, 2007. On December 19, 2007, we filed the Sixth Amended Joint Plan of Reorganization. As a result of the modifications to our Plan of Reorganization as well as settlements reached by stipulation with certain creditors, all classes of creditors entitled to vote ultimately voted to approve our Plan of Reorganization. Our Plan of Reorganization, established the total enterprise value of the reorganized U.S. Debtors for purposes of our Plan of Reorganization at $18.95 billion and provided for the amendment and restatement of our certificate of incorporation and the adoption of the Calpine Equity Incentive Plans. Our Plan of Reorganization also provided for the treatment of claims against and interests in the U.S. Debtors. Allowed administrative, tax and secured claims generally have been or are being paid in cash and cash equivalents or, with respect to certain secured claims, had the collateral securing such claims returned to the secured creditor. Allowed unsecured claims generally have been or are being paid with a distribution of common stock. Pursuant to our Plan of Reorganization, 485 million shares of common stock were authorized to be issued to settle such claims.

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Through the filing of our 2009 Form 10-K, approximately 440 million shares have been distributed to holders of allowed unsecured claims and approximately 45 million shares remain in reserve for distribution to holders of disputed claims whose claims ultimately become allowed. We estimate that the number of shares reserved is sufficient to satisfy the U.S. Debtors’ obligations under our Plan of Reorganization even if all disputed unsecured claims ultimately become allowed. As disputed claims are resolved, the claimants receive distributions of shares from the reserve on the same basis as if such distributions had been made on or about the Effective Date. 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. Accordingly, resolution of these claims could have a material effect on creditor recoveries under our Plan of Reorganization as the total number of shares of common stock that remain available for distribution upon resolution of disputed claims is limited pursuant to our Plan of Reorganization. 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. 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 preferential lien rights to the assets of Calpine Generating Company, LLC (a wholly owned indirect subsidiary of ours consisting of 13 natural gas-fired power plants) that have priority over our other debt securing these assets. No assurances can be given that settlements may not be materially higher or lower than confirmed in our Plan of Reorganization or than we originally estimated.

Pursuant to our Plan of Reorganization, we were also authorized to issue up to 15 million shares under the Calpine Equity Incentive Plans, and as of December 31, 2009, approximately 11.7 million share-based awards, net of forfeitures, had been issued under the Calpine Equity Incentive Plans. Holders of allowed interests in Calpine Corporation (primarily holders of Calpine Corporation common stock existing as of the Petition Date) received a pro rata share of warrants to purchase approximately 48.5 million shares of reorganized Calpine Corporation common stock at $23.88 per share. Warrants for 21,499 shares of common stock were exercised prior to expiration. The remaining unexercised warrants expired on August 25, 2008. Proceeds received of approximately $1 million from the exercise of the warrants were recorded as additional paid-in capital.

Our common stock is listed on the NYSE. Our common stock began “when issued” trading on the NYSE under the symbol “CPN-WI” on January 16, 2008, and began “regular way” trading on the NYSE under the symbol “CPN” on February 7, 2008. Our authorized equity consists of 1.5 billion shares comprising 1.4 billion shares of common stock, par value $.001 per share, and 100 million shares of preferred stock which preferred stock may be issued in one or more series, with such voting rights and other terms as our Board of Directors determines.

In connection with the consummation of our Plan of Reorganization, we closed on our approximately $7.3 billion of First Lien Facilities, comprising the approximately $4.9 billion of outstanding loan amounts and commitments under the DIP Facility (including the $1.0 billion revolver), which were converted into exit financing under our First Lien Credit Facility, approximately $2.1 billion of additional term loan facilities under our First Lien Credit Facility and $300 million of term loans under the bridge facility. Amounts drawn under our First Lien Facilities at closing were used to fund cash payment obligations under our Plan of Reorganization including the repayment of a portion of the Second Priority Debt and the payment of administrative claims and other pre-petition claims, as well as to pay fees and expenses in connection with our First Lien Facilities and for working capital and general corporate purposes. The bridge facility was repaid in full on March 6, 2008, in accordance with its terms.

In connection with our emergence from Chapter 11, we recorded certain “plan effect” adjustments to our Consolidated Balance Sheet as of the Effective Date in order to reflect certain provisions of our Plan of Reorganization. These adjustments included the distribution of approximately $4.1 billion in cash and the authorized issuance of 485 million shares of reorganized Calpine Corporation common stock primarily for the discharge of LSTC, repayment of the Second Priority Debt and for various other administrative and other post- petition claims. As a result, our equity increased by approximately $8.9 billion. We borrowed approximately $6.4 billion under our First Lien Facilities, which was used to repay the outstanding term loan balance of $3.9 billion (excluding the unused portion under the $1.0 billion revolver) under our DIP Facility. The remaining net proceeds of approximately $2.5 billion were used to fund cash payment obligations under our Plan of Reorganization including the repayment of a portion of the Second Priority Debt and the payment of administrative claims.

CCAA Proceedings — Upon the application of the Canadian Debtors and other deconsolidated foreign entities, on February 8, 2008, the Canadian Court ordered and declared that the unsecured notes issued by ULC I were canceled and discharged on February 4, 2008; the Canadian Debtors had completed all distributions previously ordered in full satisfaction of the pre-filing claims against them; the Canadian Debtors had otherwise fully complied with all orders of the Canadian Court; and the proceedings under the CCAA were terminated, including the stay of proceedings.

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Applicability of Fresh Start Accounting

At the Effective Date, we did not meet the requirements under GAAP to adopt fresh start accounting because the reorganization value of our assets exceeded the total of post-petition liabilities and allowed claims.

U.S. Debtors Condensed Combined Financial Statements

Basis of Presentation — The U.S. Debtors’ Condensed Combined Financial Statements exclude the financial statements of our consolidated subsidiaries and affiliates that were not U.S. Debtors. Transactions and balances of receivables and payables between U.S. Debtors were eliminated in consolidation.

Condensed combined financial statements of the U.S. Debtors are set forth below (in millions):

Condensed Combined Statement of Operations

For the Year Ended December 31, 2007

	2007
Total revenue	$	7,440
Total cost of revenue		7,174
Operating (income) expense(1)		(39	)
Income from operations		305
Interest expense		1,606
Other (income) expense, net		(118	)
Reorganization items, net		(3,240	)
Income before income taxes		2,057
Income tax benefit		(346	)
Net income	$	2,403

__________

(1) Includes equity in income (loss) of affiliates.

Condensed Combined Statement of Cash Flows

For the Year Ended December 31, 2007

	2007
Net cash provided by (used in):
Operating activities	$	(93	)
Investing activities		504
Financing activities		404
Net increase in cash and cash equivalents		815
Cash and cash equivalents, beginning of period		883
Cash and cash equivalents, end of period	$	1,698
Net cash paid for reorganization items included in operating activities	$	126
Net cash received from reorganization items included in investing activities	$	(576	)
Net cash paid for reorganization items included in financing activities	$	74

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Interest Expense — We recorded $135 million in post-petition interest from January 1, 2008, through the Effective Date. As our Plan of Reorganization was confirmed on December 19, 2007, we recorded interest expense in December 2007 for allowed claims under our Plan of Reorganization of $347 million related to post-petition interest on LSTC incurred from the Petition Date through December 31, 2007. This amount represents non-cash value to be satisfied through distributions of shares of Calpine Corporation’s reorganized common stock. Prior to recording the post-petition interest on LSTC in December 2007, interest expense related to pre-petition LSTC was reported only to the extent that it was paid during the pendency of our Chapter 11 cases or was permitted by the Cash Collateral Order or other orders of the U.S. Bankruptcy Court. Contractual interest (at non-default rates) owed to unrelated parties on pre-petition LSTC not reflected on our Consolidated Financial Statements was $157 million for the year ended December 31, 2007. Additionally, we made periodic cash adequate protection payments to the holders of Second Priority Debt; originally payments were made only through June 30, 2006, but, by order entered December 28, 2006, the U.S. Bankruptcy Court modified the Cash Collateral Order to provide for periodic adequate protection payments on a quarterly basis to the holders of the Second Priority Debt through December 31, 2007. Upon confirmation of our Plan of Reorganization, the obligations to the holders of the Second Priority Debt were fully satisfied. Therefore, we have reported the full amount of the adequate protection payments as interest expense on our Consolidated Statements of Operations together with the remaining contractual interest through December 31, 2007, on the Second Priority Debt.

Reorganization Items

Reorganization items represent the direct and incremental costs related to our Chapter 11 cases. These include professional and trustee fees, pre-petition liability claim adjustments and losses that are probable and can be estimated, net of interest income earned on accumulated cash during the Chapter 11 process and net of gains on the sale of assets or resulting from certain settlement agreements related to our restructuring activities. We expect to continue to pay professional and trustee fees related to our Chapter 11 cases through 2010 and thereafter until the claims resolution process is completed and our Chapter 11 case is formally dismissed by the U.S. Bankruptcy Court; however, we do not expect such fees to be material in the future and do not anticipate that we will separately report future fees as reorganization items on our Consolidated Statements of Operations beginning in 2010.

The table below lists the significant components of reorganization items for the years ended December 31, 2009, 2008 and 2007 (in millions):

	2009			2008			2007
Provision for expected allowed claims	$	(2	)	$	(95	)	$	(3,687	)
Professional and trustee fees		1			85			217
Gains on asset sales		—			(206	)		(285	)
Asset impairments		—			—			120
Gain on reconsolidation of Canadian Debtors and other deconsolidated foreign entities		—			(71	)		—
DIP Facility and First Lien Facilities financing and CalGen Secured Debt repayment costs		—			(4	)		202
Interest (income) on accumulated cash		—			(7	)		(59	)
Other		—			(4	)		234
Total reorganization items	$	(1	)	$	(302	)	$	(3,258	)

Provision for Expected Allowed Claims — Represents the change in our estimate of the expected allowed claims. During the year ended December 31, 2008, our provision for expected allowed claims consisted primarily of a $62 million credit related to the settlement of claims with the Canadian Debtors and other deconsolidated foreign entities, a $12 million credit related to our settlement with Rosetta and a $34 million credit for RockGen from a prior period which we determined was not material to any period. During the year ended December 31, 2007, our provision for expected allowed claims consisted primarily of a credit of $4.1 billion resulting from the Canadian Settlement Agreement.

Gains on Asset Sales — Represents gains on the sales of the Hillabee and Fremont development project assets for the year ended December 31, 2008. See Note 6 for further discussion of our sales of Hillabee and Fremont. The sales of these assets and utilization of the sales proceeds to repay our $300 million bridge facility were part of our Plan of Reorganization and are included in reorganization items even though the sales closed subsequent to the Effective Date. The amounts recorded for the year ended December 31, 2007, primarily represent the gains recorded on the sales of the assets of Aries Power Plant, Goldendale Energy Center and PSM.

Asset Impairments — Impairment charges for the year ended December 31, 2007, primarily relate to recording our interest in Acadia PP at fair value less costs to sell.

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Other — Other reorganization items consist primarily of adjustments for foreign exchange rate changes on LSTC denominated in a foreign currency and governed by foreign law, employee severance and emergence incentive costs during the year ended December 31, 2007.

17. Commitments and Contingencies

Long-Term Service Agreements

As of December 31, 2009, the total estimated commitments for LTSAs associated with turbines installed or in storage were approximately $84 million. These commitments are payable over the terms of the respective agreements, which range from 1 to 7 years. LTSA future commitment estimates are based on the stated payment terms in the contracts at the time of execution and are subject to an annual inflationary adjustment. Certain of these agreements have terms that allow us to cancel the contracts for a fee. If we cancel such contracts, the estimated commitments remaining for LTSAs would be reduced. We had no LTSA cancellation charges for the years ended December 31, 2009, 2008 and 2007.

Power Plant Operating Leases

We have entered into certain long-term operating leases for power plants, extending through 2049, including renewal options. Some of the lease agreements provide for renewal options at fair value, and some of the agreements contain customary restrictions on dividends, additional debt and further encumbrances similar to those typically found in project finance agreements. Payments on our operating leases, which may contain escalation clauses or step rent provisions, are recognized on a straight-line basis. Certain capital improvements associated with leased power plants may be deemed to be leasehold improvements and are amortized over the shorter of the term of the lease or the economic life of the capital improvement. Future minimum lease payments under these leases are as follows (in millions):

	Initial Year	2010		2011		2012		2013		2014		Thereafter		Total
Watsonville	1995	$	1	$	—	$	—	$	—	$	—	$	—	$	1
Greenleaf	1998		7		7		7		7		3		—		31
KIAC	2000		25		25		24		24		24		119		241
South Point	2001		10		67		5		5		5		216		308
Total		$	43	$	99	$	36	$	36	$	32	$	335	$	581

During the years ended December 31, 2009, 2008 and 2007, rent expense for power plant operating leases amounted to $47 million, $46 million and $54 million, respectively. As of December 31, 2009, we guarantee $308 million of the total future minimum lease payments of our consolidated subsidiaries.

Production Royalties and Leases

We are committed under numerous geothermal leases and right-of-way, easement and surface agreements. The geothermal leases generally provide for royalties based on production revenue with reductions for property taxes paid. The right-of-way, easement and surface agreements are based on flat rates or adjusted based on Consumer Price Index changes and are not material. Under the terms of most geothermal leases, the royalties accrue as a percentage of power revenues. Certain properties also have net profits and overriding royalty interests that are in addition to the land base lease royalties. Some lease agreements contain clauses providing for minimum lease payments to lessors if production temporarily ceases or if production falls below a specified level.

Production royalties for natural gas-fired and geothermal power plants for the years ended December 31, 2009, 2008 and 2007, were $22 million, $33 million and $27 million, respectively.

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Office and Equipment Leases

We lease our corporate, regional and satellite offices, as well as some of our office equipment, under noncancellable operating leases extending through 2014. Future minimum lease payments under these leases are as follows (in millions):

2010	$	15
2011		13
2012		12
2013		11
2014		1
Thereafter		—
Total	$	52

Lease payments are subject to adjustments for our pro rata portion of annual increases or decreases in building operating costs. During the years ended December 31, 2009, 2008 and 2007, rent expense for noncancellable operating leases was $12 million, $14 million and $10 million, respectively.

Natural Gas Purchases

We enter into natural gas purchase contracts of various terms with third parties to supply natural gas to our natural gas-fired cogeneration projects. The majority of our purchases are made in the spot market or under index-priced contracts. At December 31, 2009, we had future commitments of approximately $4.7 billion of notional volume for natural gas purchases under contracts with terms from 1 to 16 years, and one contract with a term of 31 years.

Guarantee Commitments

As part of our normal business operations, we enter into various agreements providing, or otherwise arranging, financial or performance assurance to third parties on behalf of our subsidiaries in the ordinary course of such subsidiaries’ respective business. Such arrangements include guarantees, standby letters of credit and surety bonds for power and natural gas purchase and sale arrangements and contracts associated with the development, construction, operation and maintenance of our fleet of power plants. These arrangements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended commercial purposes.

At December 31, 2009, guarantees of subsidiary debt, standby letters of credit and surety bonds to third parties and guarantees of subsidiary operating lease payments and their respective expiration dates were as follows (in millions):

Guarantee Commitments	2010		2011		2012		2013		2014		Thereafter		Total
Guarantee of subsidiary debt(1)	$	73	$	72	$	70	$	66	$	54	$	647	$	982
Standby letters of credit(2)(4)		384		28		—		—		—		—		412
Surety bonds(3)(4)(5)		—		—		—		—		—		4		4
Guarantee of subsidiary operating lease payments(4)		10		67		5		5		5		216		308
Total	$	467	$	167	$	75	$	71	$	59	$	867	$	1,706

__________

(1) Represents Calpine Corporation guarantees of certain power plant capital leases and related interest. All guaranteed capital leases are recorded on our Consolidated Balance Sheets.

(2) The standby letters of credit disclosed above represent those disclosed in Note 7.

(3) The majority of surety bonds do not have expiration or cancellation dates.

(4) These are off balance sheet obligations.

(5) As of December 31, 2009, $4 million of cash collateral is outstanding related to these bonds.

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We routinely arrange for the issuance of letters of credit and various forms of surety bonds to third parties in support of our subsidiaries’ contractual arrangements of the types described above and may guarantee the operating performance of some of our partially owned subsidiaries up to our ownership percentage. The letters of credit issued under various credit facilities support CES risk management and other operational and construction activities. In the event a subsidiary were to fail to perform its obligations under a contract supported by such a letter of credit or surety bond, and the issuing bank or surety were to make payment to the third party, we would be responsible for reimbursing the issuing bank or surety within an agreed timeframe, typically a period of one to ten days. To the extent liabilities are incurred as a result of activities covered by letters of credit or the surety bonds, such liabilities are included on our Consolidated Balance Sheets.

In connection with our purchase and sale agreements, we have frequently provided for indemnification by each of the purchaser and the seller, and/or their respective parent, to the counterparty for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party. These indemnification obligations generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or impossible to quantify at the time of the consummation of a particular transaction.

Additionally, we and our subsidiaries from time to time assume other indemnification obligations in conjunction with transactions other than purchase or sale transactions. These indemnification obligations generally have a discrete term and are intended to protect our counterparties against risks that are difficult to predict or impossible to quantify at the time of the consummation of a particular transaction, such as the costs associated with litigation that may result from the transaction.

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 GAAP. Where we have determined an unfavorable outcome is probable and is reasonably estimable, we have accrued for potential litigation losses. During the pendency of our Chapter 11 cases through the Effective Date, pursuant to automatic stay provisions under the Bankruptcy Code and orders granted by the Canadian Court, all actions to enforce or otherwise effect repayment of liabilities preceding the Petition Date, as well as all pending litigation against the Calpine Debtors, generally were stayed. Following the Effective Date, pending actions to enforce or otherwise effect repayment of liabilities preceding 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. See Note 16 for information regarding our emergence from our Chapter 11 and our CCAA proceedings. In addition to the Chapter 11 cases and CCAA proceedings (in connection with which certain of the matters described below arose), and the other 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.

Hawaii Structural Ironworkers Pension Fund v. Calpine, et al. — This case was filed in San Diego County Superior Court on March 11, 2003, and later transferred, on a defense motion, to Santa Clara County Superior Court. Defendants in this case are Calpine Corporation, Peter Cartwright, Ann B. Curtis, John Wilson, Kenneth Derr, George Stathakis, Credit Suisse First Boston LLC, Banc of America Securities LLC, Deutsche Bank Securities, Inc. and Goldman Sachs & Co. The Hawaii Structural Ironworkers Pension Trust Fund alleges that the prospectus and registration statement for an April 2002 offering of Calpine Corporation securities contained false or misleading statements. The action was temporarily stayed during Calpine Corporation’s Chapter 11 filings.

On December 19, 2007, Calpine Corporation entered into an agreement with the Hawaii Structural Ironworkers Pension Trust Fund to allow the action to proceed to the extent there was insurance coverage available to Calpine Corporation.

The parties attended mediation on June 1, 2009, and settlement discussions continued thereafter. On October 12, 2009, the parties executed a Stipulation of Settlement, which settled the matter for $43 million contingent upon court approval. Pursuant to the December 19, 2007 agreement, Calpine Corporation’s portion of the settlement is to be satisfied solely from applicable insurance coverage and will not require cash payment from Calpine. Preliminary approval of the class action settlement was granted by Santa Clara Superior Court on October 26, 2009, and final approval was ordered by the Santa Clara Superior Court on February 3, 2010. We now consider this matter closed.

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

The case was temporarily stayed during our Chapter 11 case; however, we and the Pit River Tribe filed a stipulation to lift the automatic stay. On November 5, 2006, the U.S. Court of Appeals for the Ninth Circuit issued a decision granting the plaintiffs relief by holding that the BLM had not complied with the National Environmental Policy Act, and other procedural requirements and, therefore, held that the lease extensions were invalid. The U.S. Court of Appeals for the Ninth Circuit remanded the matter back to the U.S. District Court to implement its decision. On December 22, 2008, the U.S. District Court ruled that the lease extension for the two Fourmile Hill leases and the approval to construct a proposed 49.9 MW Fourmile Hill power plant should be remanded to the federal agencies for curative action. The Pit River Tribe timely appealed the Court’s December 22, 2008 order. Briefing of the appeal is complete and we were granted our motion for an expedited hearing. The U.S. Court of Appeals for the Ninth Circuit hearing on the merits of the Pit River Tribe’s appeal is scheduled to be heard on March 10, 2010.

Appeal of Confirmation Order — Several parties filed appeals in the U.S. District Court for the Southern District of New York seeking reconsideration of the Confirmation Order of the U.S. Bankruptcy Court, despite the effectiveness of our Plan of Reorganization. On June 6, 2008, the U.S. District Court for the Southern District of New York entered an order denying the appeals, finding that all of the appeals were equitably moot. One of the shareholders (Mr. Felluss) filed a motion for reconsideration, which was denied on June 24, 2008. On July 3, 2008, Mr. Felluss filed a notice of appeal with the Second Circuit. In addition, on August 8, 2008, Mr. Felluss filed a motion with the Second Circuit seeking to stay the expiration of the warrants that had been issued pursuant to our Plan of Reorganization and were scheduled to expire August 25, 2008; the Second Circuit denied that motion on August 27, 2008. Mr. Felluss’ appeal was heard by the Second Circuit on November 10, 2009, and denied by Summary Order on November 25, 2009. On December 25, 2009, Mr. Felluss filed a petition for rehearing with the Second Circuit. On January 11, 2010, the Second Circuit denied the petition. Unless Mr. Felluss files a petition for review with the U.S. Supreme Court in the next 90 days, we will consider this matter closed.

Environmental Matters

We are subject to complex and stringent environmental laws and regulations related to the operation of our power plants. On occasion, we may incur environmental fees, penalties and fines associated with the normal operation of our power plants. We do not, however, have environmental violations or other matters that would have a material impact on our financial condition, results of operations or cash flows or that would significantly change our operations. A summary of our larger environmental matters are as follows:

Texas City and Clear Lake Environmental Matters — As part of an internal review of our Texas City and Clear Lake power plants, we determined that these power plants were in violation of the requirements of the Acid Rain Program found in Title 40 of the U.S. Federal Code of Regulations, Parts 72-78. We self-reported the excess emissions to the Texas Commission on Environmental Quality, or TCEQ, and the EPA, and paid the appropriate fees. Compliance agreements between each power plant and the TCEQ were executed on September 26, 2008, and limit enforcement by the TCEQ. The EPA does have authority and discretion to issue substantial fines that could be material; however, based on the circumstances and on consideration of recent cases addressed by the agencies involved, we do not believe that the maximum penalty will be assessed or that penalties, if any, resulting from these matters will have a material adverse effect on our business, financial condition or results of operations.

San Diego Air Pollution Control District — The San Diego Air Pollution Control District issued OMEC a notice of violation on August 28, 2009, for failing to install an auxiliary boiler required by the permit issued by the San Diego Air Pollution Control District. OMEC entered into a compliance agreement on September 18, 2009, under which it paid the San Diego Air Pollution Control District a civil penalty, made a contribution to the San Diego Air Pollution Control District’s Air Quality Improvement Trust Fund, and agreed to install an auxiliary boiler by November 30, 2009 and to install control system software to reduce emissions occurring during gas turbine startup. As of December 31, 2009, we have satisfied all of the terms of the compliance agreement and consider this matter closed.

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Other Contingencies

Lyondell Bankruptcy — On January 6, 2009, Lyondell Chemical Co. and certain of its subsidiaries, including Houston Refining LP, filed for protection under Chapter 11 in the U.S. Bankruptcy Court. Channel Energy Center, a 608 MW natural gas-fired cogeneration power plant located in Houston, Texas, leases its project site from Houston Refining LP and is granted certain easements in, over, under and on the site pursuant to the lease. Channel Energy Center provides power and steam to Houston Refining LP pursuant to a power services agreement and, pursuant to a power plant services agreement, provides clarified water and treated water to Houston Refining LP. Channel Energy Center is provided with raw water, refinery gas and certain other power plant services by Houston Refining LP.

The Lyondell debtors may exercise their right under the Bankruptcy Code to reject the lease, the power services agreement and/or the power plant services agreement. The potential damages to us if any or all of these agreements are rejected are uncertain and would represent an unsecured bankruptcy claim with Lyondell. To the extent that any such damages would be recoverable under the laws of the State of Texas, the governing law under the agreements, they would be treated as an unsecured claim against the Lyondell debtors in bankruptcy. The percentage of recovery on unsecured claims in the Lyondell bankruptcy is unknown at this time, but is expected to be low.

We continue to monitor this matter closely and will seek vigorously to protect our rights under our various agreements with the Lyondell debtors.

18. Segment and Significant Customer Information

We are an independent wholesale power company. We own and operate natural gas-fired and geothermal power plants in North America and have a significant presence in the major competitive power markets in the U.S., including California and Texas. 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, Southeast and North (including Canada). 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, RGGI compliance 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 revenue. Commodity Margin is a key operational measure reviewed by our chief operating decision maker to assess the performance of our segments.

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Our West segment information has been recast to exclude the results from Blue Spruce and Rocky Mountain, which are presented as discontinued operations. During the first quarter of 2009, we began assessing the performance of our regional segments to include the allocation (based upon each regional segment’s MWh) of revenues and expenses from our fuel management, Turbine Maintenance Group and certain non-region specific natural gas marketing and optimization and other corporate activities, which had formerly been separately reported as our “Other” segment. Additionally, we have modified our definition of Commodity Margin to include cash settlements from our marketing, hedging and optimization activities that were previously included in mark-to-market activity. Our 2008 and 2007 segment information has been reclassified to conform to the current year presentation. Financial data for our segments were as follows (in millions):

	Year Ended December 31, 2009
	West		Texas			Southeast			North		Consolidation and Elimination			Total
Revenues from external customers	$	3,311	$	1,816		$	778		$	558	$	—		$	6,463
Intersegment revenues		28		63			97			16		(204	)		—
Total operating revenues	$	3,339	$	1,879		$	875		$	574	$	(204	)	$	6,463
Commodity Margin	$	1,245	$	644		$	304		$	268	$	—		$	2,461
Add: Mark-to-market commodity activity, net and other revenue(1)		143		(40	)		(5	)		46		(44	)		100
Less:
Plant operating expense		408		232			134			91		3			868
Depreciation and amortization expense		185		125			79			66		(8	)		447
Other cost of revenue(2)		61		13			10			30		(32	)		82
Gross profit		734		234			76			127		(7	)		1,164
Other operating expenses		53		68			29			1		—			151
Income from operations		681		166			47			126		(7	)		1,013
Interest expense, net of interest income															799
Debt extinguishment costs and other (income) expense, net															90
Income before reorganization items, income taxes and discontinued operations															124
Reorganization items															(1	)
Income before income taxes and discontinued operations														$	125

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	Year Ended December 31, 2008
	West			Texas		Southeast			North			Consolidation and Elimination			Total
Revenues from external customers	$	4,143		$	3,806	$	1,245		$	643		$	—		$	9,837
Intersegment revenues		49			252		229			25			(555	)		—
Total operating revenues	$	4,192		$	4,058	$	1,474		$	668		$	(555	)	$	9,837
Commodity Margin	$	1,155		$	726	$	264		$	279		$	—		$	2,424
Add: Mark-to-market commodity activity, net and other revenue(1)		(31	)		195		36			(40	)		(28	)		132
Less:
Plant operating expense		406			267		128			108			(19	)		890
Depreciation and amortization expense		173			124		69			56			(6	)		416
Other cost of revenue(2)		71			12		59			26			(21	)		147
Gross profit		474			518		44			49			18			1,103
Other operating expenses		154			91		212			12			—			469
Income (loss) from operations		320			427		(168	)		37			18			634
Interest expense, net of interest income																998
Debt extinguishment costs and other (income) expense, net																21
Loss before reorganization items, income taxes and discontinued operations																(385	)
Reorganization items																(302	)
Loss before income taxes and discontinued operations															$	(83	)

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	Year Ended December 31, 2007
	West		Texas		Southeast			North		Consolidation and Elimination			Total
Revenues from external customers	$	3,548	$	2,665	$	1,036		$	620	$	—		$	7,869
Intersegment revenues		50		15		144			12		(221	)		—
Total operating revenues	$	3,598	$	2,680	$	1,180		$	632	$	(221	)	$	7,869
Commodity Margin	$	1,071	$	505	$	256		$	278	$	—		$	2,110
Add: Mark-to-market commodity activity, net and other revenue(1)		52		57		14			2		(48	)		77
Less:
Plant operating expense		320		193		133			88		(11	)		723
Depreciation and amortization expense		192		123		79			55		(3	)		446
Other cost of revenue(2)		68		9		35			69		(1	)		180
Gross profit		543		237		23			68		(33	)		838
Other operating expenses		93		62		35			30		(30	)		190
Income (loss) from operations		450		175		(12	)		38		(3	)		648
Interest expense, net of interest income														1,927
Debt extinguishment costs and other (income) expense, net														(141	)
Loss before reorganization items, income taxes and discontinued operations														(1,138	)
Reorganization items														(3,258	)
Income before income taxes and discontinued operations													$	2,120

__________

(1) Mark-to-market commodity activity represents the unrealized portion of our mark-to-market activity, net, as well as a non-cash gain from amortization of prepaid power sales agreements included in operating revenues and fuel and purchased energy expense on our Consolidated Statements of Operations.

(2) Excludes $5 million of RGGI compliance costs for the year ended December 31, 2009, and nil for the years ended December 31, 2008 and 2007, respectively, which were included as a component of Commodity Margin, and includes operating asset impairments of $4 million, $33 million and $44 million for the years ended December 31, 2009, 2008 and 2007, respectively.

Significant Customer

We did not have a customer that accounted for more than 10% of our annual consolidated revenues for the years ended December 31, 2009 and 2008. For the year ended December 31, 2007, we had one significant customer that accounted for more than 10% of our annual consolidated revenues: CDWR. CDWR revenues were $1.1 billion for the year ended December 31, 2007. Our receivables from CDWR were $95 million as of December 31, 2007. CDWR revenues were attributable to our West segment.

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19. Quarterly Consolidated Financial Data (unaudited)

Our quarterly operating results have been recast to present our results from Blue Spruce and Rocky Mountain as discontinued operations. Our quarterly operating results have fluctuated in the past and may continue to do so in the future as a result of a number of factors, including, but not limited to, our restructuring activities including asset sales, the completion of development projects, the timing and amount of curtailment of operations under the terms of certain PPAs, the degree of risk management and marketing, hedging and optimization activities, and variations in levels of production. Furthermore, the majority of the dollar value of capacity payments under certain of our PPAs are received during the months of May through October.

	Quarter Ended
	December 31			September 30		June 30			March 31
	(in millions, except per share amounts)
2009
Operating revenues	$	1,544		$	1,822	$	1,445		$	1,652
Gross profit		229			480		189			266
Income from operations		197			423		159			234
Income (loss) before discontinued operations attributable to Calpine		(44	)		227		(89	)		20
Discontinued operations, net of tax		1			11		11			12
Net income (loss) attributable to Calpine	$	(43	)	$	238	$	(78	)	$	32
Basic earnings (loss) per common share:
Income (loss) before discontinued operations attributable to Calpine	$	(0.09	)	$	0.47	$	(0.18	)	$	0.04
Discontinued operations, net of tax, attributable to Calpine		0.00			0.02		0.02			0.03
Net income (loss) attributable to Calpine	$	(0.09	)	$	0.49	$	(0.16	)	$	0.07
Diluted earnings (loss) per common share:
Income (loss) before discontinued operations attributable to Calpine	$	(0.09	)	$	0.47	$	(0.18	)	$	0.04
Discontinued operations, net of tax, attributable to Calpine		0.00			0.02		0.02			0.03
Net income (loss) attributable to Calpine	$	(0.09	)	$	0.49	$	(0.16	)	$	0.07
2008
Operating revenues	$	1,942		$	3,165	$	2,804		$	1,926
Gross profit (loss)		166			519		461			(43	)
Income (loss) from operations(1)		54			258		418			(96	)
Income (loss) before discontinued operations attributable to Calpine		(135	)		129		193			(213	)
Discontinued operations, net of tax, attributable to Calpine		26			7		4			(1	)
Net income (loss) attributable to Calpine	$	(109	)	$	136	$	197		$	(214	)
Basic earnings (loss) per common share:
Income (loss) before discontinued operations attributable to Calpine	$	(0.27	)	$	0.27	$	0.40		$	(0.44	)
Discontinued operations, net of tax, attributable to Calpine		0.05			0.01		0.01			—
Net income (loss) attributable to Calpine	$	(0.22	)	$	0.28	$	0.41		$	(0.44	)
Diluted earnings (loss) per common share:
Income (loss) before discontinued operations attributable to Calpine	$	(0.27	)	$	0.27	$	0.40		$	(0.44	)
Discontinued operations, net of tax, attributable to Calpine		0.05			0.01		0.01			—
Net income (loss) attributable to Calpine	$	(0.22	)	$	0.28	$	0.41		$	(0.44	)

__________

(1) As a result of the anticipated sale of Auburndale during 2008, we recorded an impairment loss of approximately $180 million, which is included in income from operations on our 2008 Consolidated Statements of Operations. See Notes 4 and 6 for more information.

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