UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

____________________

Form 10-K

[X]	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2011
[    ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to

Commission File No. 001-12079

______________________

Calpine Corporation

(A Delaware Corporation)

I.R.S. Employer Identification No. 77-0212977

717 Texas Avenue, Suite 1000, Houston, Texas 77002

Telephone: (713) 830-2000

Not Applicable

(Former Address)

Securities registered pursuant to Section 12(b) of the Act:

Calpine Corporation Common Stock, $0.001 Par Value

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.     Yes [X]     No [    ]

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.     Yes [    ]     No [X]

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes [X]     No [    ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).     Yes [X]     No [    ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.     [    ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer, “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer [X]	Accelerated filer  [    ]
Non-accelerated filer  [    ]	Smaller reporting company  [    ]
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).     Yes [    ]     No [X]

State the aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2011, the last business day of the registrant’s most recently completed second fiscal quarter: approximately $4,491 million.

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.    Yes [X]     No [    ]

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: Calpine Corporation: 481,338,627 shares of common stock, par value $0.001, were outstanding as of February 7, 2012.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved.

Designated portions of the Proxy Statement relating to the 2012 Annual Meeting of Shareholders are incorporated by reference into Part III (Items 11, 12, 13, 14 and portions of Item 10)

CALPINE CORPORATION AND SUBSIDIARIES

FORM 10-K

ANNUAL REPORT

For the Year Ended December 31, 2011

TABLE OF CONTENTS

		Page
	PART I
Item 1.	Business	3
Item 1A.	Risk Factors	33
Item 1B.	Unresolved Staff Comments	46
Item 2.	Properties	46
Item 3.	Legal Proceedings	46
Item 4.	Removed and Reserved	46
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	47
Item 6.	Selected Financial Data	49
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	50
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	90
Item 8.	Financial Statements and Supplementary Data	90
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	90
Item 9A.	Controls and Procedures	90
Item 9B.	Other Information	91
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	92
Item 11.	Executive Compensation	93
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	93
Item 13.	Certain Relationships and Related Transactions, and Director Independence	93
Item 14.	Principal Accounting Fees and Services	93
	PART IV
Item 15.	Exhibits, Financial Statement Schedule	94
Signatures		101
Power of Attorney		102
Index to Consolidated Financial Statements		103

i

DEFINITIONS

As used in this Report, the following abbreviations and terms have the meanings as listed below. Additionally, the terms “Calpine,” “we,” “us” and “our” refer to Calpine Corporation and its consolidated subsidiaries, unless the context clearly indicates otherwise. The term “Calpine Corporation” refers only to Calpine Corporation and not to any of its subsidiaries. Unless and as otherwise stated, any references in this Report to any agreement means such agreement and all schedules, exhibits and attachments in each case as amended, restated, supplemented or otherwise modified to the date of filing this Report.

ABBREVIATION	DEFINITION
2017 First Lien Notes	The $1.2 billion aggregate principal amount of 7.25% senior secured notes due 2017, issued October 21, 2009, in exchange for a like principal amount of term loans under the First Lien Credit Facility
2019 First Lien Notes	The $400 million aggregate principal amount of 8.0% senior secured notes due 2019, issued May 25, 2010
2020 First Lien Notes	The $1.1 billion aggregate principal amount of 7.875% senior secured notes due 2020, issued July 23, 2010
2021 First Lien Notes	The $2.0 billion aggregate principal amount of 7.50% senior secured notes due 2021, issued October 22, 2010
2023 First Lien Notes	The $1.2 billion aggregate principal amount of 7.875% senior secured notes due 2023, issued January 14, 2011
AB 32	California Assembly Bill 32
Adjusted EBITDA	EBITDA as adjusted for the effects of (a) impairment charges, (b) major maintenance expense, (c) operating lease expense, (d) unrealized gains or losses on commodity derivative mark-to-market activity, (e) adjustments to reflect only the Adjusted EBITDA from our unconsolidated investments, (f) stock-based compensation expense, (g) gains or losses on sales, dispositions or retirements of assets, (h) non-cash gains and losses from foreign currency translations, (i) gains or losses on the repurchase or extinguishment of debt, (j) Conectiv acquisition-related costs, (k) Adjusted EBITDA from our discontinued operations and (l) other extraordinary, unusual or non-recurring items
AOCI	Accumulated Other Comprehensive Income
Average availability	Represents the total hours during the period that our plants were in-service or available for service as a percentage of the total hours in the period
Average capacity factor, excluding peakers	A measure of total actual generation as a percent of total potential generation. It is calculated by dividing (a) total MWh generated by our power plants, excluding peakers, by (b) the product of multiplying (i) the average total MW in operation, excluding peakers, during the period by (ii) the total hours in the period
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, formerly an indirect, wholly owned subsidiary that owned Blue Spruce Energy Center, a 310 MW natural gas-fired, peaker power plant located in Aurora, Colorado, which was sold on December 6, 2010

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ABBREVIATION	DEFINITION
Broad River	Broad River Energy Center, an 847 MW natural gas-fired, peaker power plant located in Gaffney, South Carolina
Btu	British thermal unit(s), a measure of heat content
CAA	Federal Clean Air Act, U.S. Code Title 42, Chapter 85
CAIR	Clean Air Interstate Rule
CAISO	California Independent System Operator
CalGen	Calpine Generating Company, LLC, an indirect, wholly owned subsidiary
CalGen Third Lien Debt	Together, the $680 million Third Priority Secured Floating Rate Notes Due 2011, issued by CalGen and CalGen Finance Corp.; and the $150 million 11.5% Third Priority Secured Notes Due 2011, issued by CalGen and CalGen Finance Corp., in each case repaid on March 29, 2007
Calpine BRSP	Calpine BRSP, LLC
Calpine Equity Incentive Plans	Collectively, the Director Plan and the Equity Plan, which provide for grants of equity awards to Calpine employees and non-employee members of Calpine’s Board of Directors
Cap-and-trade	A government imposed emissions reduction program that would place a cap on the amount of emissions that can be emitted from certain sources, such as power plants. In its simplest form, the cap amount is set as a reduction from the total emissions during a base year and for each year over a period of years the cap amount would be reduced to achieve the targeted overall reduction by the end of the period. Allowances or credits for emissions in an amount equal to the cap would be issued or auctioned to companies with facilities, permitting them to emit up to a certain amount of emissions during each applicable period. After allowances have been distributed or auctioned, they can be transferred or traded
CARB	California Air Resources Board
CCFC	Calpine Construction Finance Company, L.P., an indirect, wholly owned subsidiary
CCFC Finance	CCFC Finance Corp.
CCFC Guarantors	Hermiston Power LLC and Brazos Valley Energy LLC, wholly owned subsidiaries of CCFC
CCFC Notes	The $1.0 billion aggregate principal amount of 8.0% Senior Secured Notes due 2016 issued May 19, 2009, by CCFC and CCFC Finance
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, in each case, on June 18, 2009
CCFC Refinancing	The issuance of the CCFC 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

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ABBREVIATION	DEFINITION
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
CDHI	Calpine Development Holdings, Inc., an indirect, wholly owned subsidiary
CEHC	Conectiv Energy Holding Company, LLC, a wholly owned subsidiary of Conectiv
CES	Calpine Energy Services, L.P.
CFTC	U.S. Commodities Futures Trading Commission
Chapter 11	Chapter 11 of the U.S. Bankruptcy Code
CO2	Carbon dioxide
COD	Commercial operations date
Cogeneration	Using a portion or all of the steam generated in the power generating process to supply a customer with steam for use in the customer's operations
Commodity expense	The sum of our expenses from fuel and purchased energy expense, fuel transportation expense, transmission expense and cash settlements from our marketing, hedging and optimization activities including natural gas transactions hedging future power sales that are included in our mark-to-market activity in fuel and purchased energy expense, but excludes the unrealized portion of our mark-to-market activity
Commodity Margin	Non-GAAP financial measure that includes power and steam revenues, sales of purchased power and physical natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, RGGI compliance and other environmental costs, and cash settlements from our marketing, hedging and optimization activities including natural gas transactions hedging future power sales that are included in mark-to-market activity, but excludes the unrealized portion of our mark-to-market activity and other revenues
Commodity revenue	The sum of our revenues from power and steam sales, sales of purchased power and physical natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue, and cash settlements from our marketing, hedging and optimization activities that are included in our mark-to-market activity in operating revenues, but excludes the unrealized portion of our mark-to-market activity
Company	Calpine Corporation, a Delaware corporation, and its subsidiaries
Conectiv	Conectiv, LLC, a wholly owned subsidiary of PHI
Conectiv Acquisition	The acquisition of all of the membership interests in CEHC pursuant to the Conectiv Purchase Agreement on July 1, 2010, whereby we acquired all of the power generation assets of Conectiv from PHI, which included 18 operating power plants and York Energy Center that was under construction and achieved COD on March 2, 2011, with 4,491 MW of capacity
Conectiv Purchase Agreement	Purchase Agreement by and among PHI, Conectiv, CEHC and NDH dated as of April 20, 2010
Corporate Revolving Facility	The $1.0 billion aggregate amount revolving credit facility credit agreement, dated as of December 10, 2010, among Calpine Corporation, Goldman Sachs Bank USA, as administrative agent, Goldman Sachs Credit Partners L.P., as collateral agent, the lenders party thereto and the other parties thereto
CPUC	California Public Utilities Commission
Creed	Creed Energy Center, LLC

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ABBREVIATION	DEFINITION
Director Plan	The Amended and Restated Calpine Corporation 2008 Director Incentive Plan
Dodd-Frank Act	The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
EBITDA	Earnings before interest, taxes, depreciation and amortization
Effective Date	January 31, 2008, the date on which the conditions precedent enumerated in the Plan of Reorganization were satisfied or waived and the Plan of Reorganization became effective
EIA	Energy Information Administration of the U.S. Department of Energy
Emergence Date Market Capitalization	The weighted average trading price of Calpine Corporation’s common stock over the 30-day period following the date on which it emerged from Chapter 11 bankruptcy protection, as defined in and calculated pursuant to Calpine Corporation’s amended and restated certificate of incorporation and reported in its Current Report on Form 8-K filed with the SEC on March 25, 2008
EPA	U.S. Environmental Protection Agency
Equity Plan	The Amended and Restated Calpine Corporation 2008 Equity Incentive Plan
ERCOT	Electric Reliability Council of Texas
EWG(s)	Exempt wholesale generator(s)
Exchange Act	U.S. Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FDIC	U.S. Federal Deposit Insurance Corporation
FERC	U.S. Federal Energy Regulatory Commission
First Lien Credit Facility	Credit Agreement, dated as of January 31, 2008, as amended by the First Amendment to Credit Agreement and Second Amendment to Collateral Agency and Intercreditor Agreement, dated as of August 20, 2009, among Calpine Corporation, as borrower, certain subsidiaries of the Company named therein, as guarantors, the lenders party thereto, Goldman Sachs Credit Partners L.P., as administrative agent and collateral agent, and the other agents named therein
First Lien Notes	Collectively, the 2017 First Lien Notes, the 2019 First Lien Notes, the 2020 First Lien Notes, the 2021 First Lien Notes and the 2023 First Lien Notes
FRCC	Florida Reliability Coordinating Council
Freestone	Freestone Energy Center, a 994 MW natural gas-fired, combined-cycle power plant located near Fairfield, Texas
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(s)	Greenhouse gas(es), primarily carbon dioxide (CO2), and including methane (CH4), nitrous oxide (N2O), sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs) and perfluorocarbons (PFCs)

v

ABBREVIATION	DEFINITION
Gilroy	Calpine Gilroy Cogen, L.P.
Goose Haven	Goose Haven Energy Center, LLC
Greenfield LP	Greenfield Energy Centre LP, a 50% partnership interest between certain of our subsidiaries and a third party which operates the Greenfield Energy Centre, a 1,038 MW natural gas-fired, combined-cycle power plant in Ontario, Canada
Heat Rate(s)	A measure of the amount of fuel required to produce a unit of power
Hg	Mercury
IOUs	Investor Owned Utilities
IRC	Internal Revenue Code
ISO(s)	Independent System Operator(s)
ISO-NE	ISO New England
ISRA	Industrial Site Recovery Act
KWh	Kilowatt hour(s), a measure of power produced, purchased or sold
LIBOR	London Inter-Bank Offered Rate
Los Esteros Project Debt	Credit Agreement dated August 23, 2011, between Los Esteros Critical Energy Facility, LLC, as borrower, and the lenders named therein
LTSA(s)	Long-Term Service Agreement(s)
Mankato	Mankato Energy Center, a 375 MW natural gas-fired, combined-cycle power plant located in Mankato, Minnesota
Market Capitalization	As of any date, Calpine Corporation’s then market capitalization calculated using the rolling 30-day weighted average trading price of Calpine Corporation’s common stock, as defined in and calculated in accordance with the Calpine Corporation amended and restated certificate of incorporation
Market Heat Rate(s)	The regional power price divided by the corresponding regional natural gas price
MISO	Midwest ISO
MRO	Midwest Reliability Organization
MW	Megawatt(s), a measure of plant capacity
MWh	Megawatt hour(s), a measure of power produced, purchased or sold
NAAQS	National Ambient Air Quality Standards
NDH	New Development Holdings, LLC, an indirect, wholly owned subsidiary

vi

ABBREVIATION	DEFINITION
NDH Project Debt	The $1.3 billion senior secured term loan facility and the $100 million revolving credit facility issued on July 1, 2010, under the credit agreement, dated as of June 8, 2010, among NDH, as borrower, Credit Suisse AG, as administrative agent, collateral agent, issuing bank and syndication agent, Credit Suisse Securities (USA) LLC, Citigroup Global Markets Inc. and Deutsche Bank Securities Inc., as joint book-runners and joint lead arrangers, Credit Suisse AG, Citibank, N.A., and Deutsche Bank Trust Company Americas, as co-documentation agents and the lenders party thereto repaid on March 9, 2011
New Term Loan	The $360 million first lien senior secured term loan, dated June 17, 2011, among Calpine Corporation, as borrower, and the lenders party hereto, and Morgan Stanley Senior Funding, Inc., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent
NERC	North American Electric Reliability Council
NOL(s)	Net operating loss(es)
NOX	Nitrogen oxides
NPCC	Northeast Power Coordinating Council
NYISO	New York ISO
NYMEX	New York Mercantile Exchange
NYSE	New York Stock Exchange
OCI	Other Comprehensive Income
OMEC	Otay Mesa Energy Center, LLC, an indirect, wholly owned subsidiary that owns the Otay Mesa Energy Center, a 608 MW natural gas-fired, combined-cycle power plant located in San Diego county, California
OTC	Over-the-Counter
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
PHI	Pepco Holdings, Inc.
PJM	Pennsylvania-New Jersey-Maryland Interconnection
Plan of Reorganization	Sixth Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the Bankruptcy Code filed by the U.S. Debtors with the U.S. Bankruptcy Court on December 19, 2007, as amended, modified or supplemented through the filing of this Report
PPA(s)	Any term power purchase agreement or other contract for a physically settled sale (as distinguished from a financially settled future, option or other derivative or hedge transaction) of any power product, including power, capacity and/or ancillary services, in the form of a bilateral agreement or a written or oral confirmation of a transaction between two parties to a master agreement, including sales related to a tolling transaction in which the purchaser provides the fuel required by us to generate such power and we receive a variable payment to convert the fuel into power and steam

vii

ABBREVIATION	DEFINITION
PUCT	Public Utility Commission of Texas
PUHCA 2005	U.S. Public Utility Holding Company Act of 2005
PURPA	U.S. Public Utility Regulatory Policies Act of 1978
QF(s)	Qualifying facility(ies), which are cogeneration facilities and certain small power production facilities eligible to be “qualifying facilities” under PURPA, provided that they meet certain power and thermal energy production requirements and efficiency standards. QF status provides an exemption from PUHCA 2005 and grants certain other benefits to the QF
REC(s)	Renewable energy credit(s)
Report	This Annual Report on Form 10-K for the year ended December 31, 2011, filed with the SEC on February 9, 2012
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
RFC	Reliability First Corporation
RGGI	Regional Greenhouse Gas Initiative
Risk Management Policy	Calpine's policy applicable to all employees, contractors, representatives and agents which defines the risk management framework and corporate governance structure for commodity risk, interest rate risk, currency risk and other risks
RMR Contract(s)	Reliability Must Run contract(s)
Rocky Mountain	Rocky Mountain Energy Center, LLC, formerly an indirect, wholly owned subsidiary that owned Rocky Mountain Energy Center, a 621 MW natural gas-fired, combined-cycle power plant located in Keenesburg, Colorado, which was sold on December 6, 2010
RPS	Renewable Portfolio Standards
RTO(s)	Regional Transmission Organization(s)
Russell City Project Debt	Credit Agreement dated June 24, 2011, between Russell City Energy Company, LLC, as borrower, and the lenders named therein
SEC	U.S. Securities and Exchange Commission
Second Circuit	U.S. Court of Appeals for the Second Circuit
Securities Act	U.S. Securities Act of 1933, as amended
SERC	Southeastern Electric Reliability Council
SO2	Sulfur dioxide
South Point	South Point Energy Center, a 530 MW natural gas-fired, combined-cycle power plant located in Mohave Valley, Arizona
Spark Spread(s)	The difference between the sales price of power per MWh and the cost of fuel to produce it
SPP	Southwest Power Pool

viii

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
Term Loan	The $1.3 billion first lien senior secured term loan, dated March 9, 2011, among Calpine Corporation, as borrower, and the lenders party hereto, and Morgan Stanley Senior Funding, Inc., as administrative agent, Goldman Sachs Credit Partners L.P., as collateral agent, Citibank, N.A., Credit Suisse Securities (USA) LLC and Deutsche Bank Securities Inc., as co-documentation agents and Goldman Sachs Bank USA as syndication agent
TRE	Texas Regional Entity
ULC I	Calpine Canada Energy Finance ULC
ULC II	Calpine Canada Energy Finance II ULC
U.S. Bankruptcy Court	U.S. Bankruptcy Court for the Southern District of New York
U.S. Debtor(s)	Calpine Corporation and each of its subsidiaries and affiliates that filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court, which matter was jointly administered in the U.S. Bankruptcy Court under the caption In re Calpine Corporation, et al., Case No. 05-60200 (BRL) and was dismissed on December 19, 2011
U.S. GAAP	Generally accepted accounting principles in the U.S.
VAR	Value-at-risk
VIE(s)	Variable interest entity(ies)
WECC	Western Electricity Coordinating Council
Whitby	Whitby Cogeneration Limited Partnership, a 50% partnership interest between certain of our subsidiaries and a third party which operates the Whitby 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada
York Energy Center	565 MW dual fuel, combined-cycle generation power plant (formerly known as the Delta Project) located in Peach Bottom Township, Pennsylvania, included in the Conectiv Acquisition, which achieved COD on March 2, 2011

ix

Forward-Looking Statements

In addition to historical information, this Report contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act, and Section 21E of the Exchange Act. Forward-looking statements may appear throughout this report, including without limitation, the “Management's Discussion and Analysis” section. We use words such as “believe,” “intend,” “expect,” “anticipate,” “plan,” “may,” “will,” “should,” “estimate,” “potential,” “project” and similar expressions to identify forward-looking statements. Such statements include, among others, those concerning our expected financial performance and strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. You are cautioned that any such forward-looking statements are not guarantees of future performance and that a number of risks and uncertainties could cause actual results to differ materially from those anticipated in the forward-looking statements. Such risks and uncertainties include, but are not limited to:

• Financial results that may be volatile and may not reflect historical trends due to, among other things, fluctuations in prices for commodities such as natural gas and power, changes in U.S. macroeconomic conditions, fluctuations in liquidity and volatility in the energy commodities markets and our ability to hedge risks;

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

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

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

• Risks associated with the continued economic and financial conditions affecting certain countries in Europe including financial institutions located within those countries and their ability to fund their financial commitments;

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

• Risks related to our geothermal resources, including the adequacy of our steam reserves, unusual or unexpected steam field well and pipeline maintenance requirements, variables associated with the injection of wastewater to the steam reservoir and potential regulations or other requirements related to seismicity concerns that may delay or increase the cost of developing or operating geothermal resources;

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

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

• Future capacity revenues may not occur at expected levels;

• Natural disasters, such as hurricanes, earthquakes and floods, acts of terrorism or cyber attacks that may impact our power plants or the markets our power plants serve and our corporate headquarters;

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

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

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

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

• Other risks identified in this Report.

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

Where You Can Find Other Information

Our website is www.calpine.com. Information contained on our website is not part of this Report. Information that we furnish or file with the SEC, including our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to or exhibits included in these reports are available for download, free of charge, on our website soon after such reports are filed with or furnished with the SEC. Our SEC filings, including exhibits filed therewith, are also

1

available at the SEC’s website at www.sec.gov. You may obtain and copy any document we furnish or file with the SEC at the SEC’s public reference room at 100 F Street, NE, Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the SEC’s public reference facilities by calling the SEC at 1-800-SEC-0330. You may request copies of these documents, upon payment of a duplicating fee, by writing to the SEC at its principal office at 100 F Street, NE, Room 1580, Washington, D.C. 20549.

2

PART I

Item 1. Business

BUSINESS AND STRATEGY

Business

We aspire to be recognized as the premier independent wholesale power producer in the U.S. We seek to achieve this objective by delivering long-term shareholder value, operational excellence, effectively executing our hedging strategy, focusing on our customer origination program and completing on schedule and on budget, our growth capital projects. We are the largest independent wholesale power company in the U.S. measured by power produced. We own and operate primarily natural gas-fired and geothermal power plants in North America and have a significant presence in major competitive wholesale power markets in California, Texas and the Mid-Atlantic region of the U.S. Since our inception in 1984, we have been a leader in environmental stewardship. We have invested in clean power generation to become a recognized leader in developing, constructing, owning and operating an environmentally responsible portfolio of power plants. Our portfolio is primarily comprised of two types of power generation technologies: natural gas-fired combustion turbines, which are primarily efficient 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 20% of all renewable energy in the state of California during 2010. 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 and power marketers. We purchase natural gas and fuel oil as fuel for our power plants and engage in related natural gas transportation and storage transactions. We also purchase electric transmission rights to deliver power to our customers. Additionally, consistent with our Risk Management Policy, we enter into natural gas and power physical and financial contracts to hedge certain business risks and optimize our portfolio of power plants.

Our portfolio, including partnership interests, includes 93 power plants, including 2 under construction, located throughout 20 states in the U.S. and Canada, with an aggregate generation capacity of 28,155 MW and 584 MW under construction. Our generation capacity includes 77 natural gas-fired power plants, 15 geothermal plants and 1 photovoltaic solar plant. We are one of the largest consumers of natural gas in North America and in 2011 we consumed 715 Bcf (billion cubic feet) or approximately 9% of the total estimated natural gas consumed for power generation in the U.S. We believe that having scale and geographic diversity is important in our business. Scale provides us the opportunity to have meaningful regulatory input, an ability to leverage our procurement negotiations for better price, terms and conditions on our goods and services and allows us to develop and offer a wide array of products and services to our customers. Geographic diversity helps us manage price fluctuations across our different markets.

The environmental profile of our power plants reflects our commitment to environmental leadership and stewardship. We have invested the necessary capital to develop a power generation portfolio that has substantially lower air pollutant emissions compared to our competitors’ power plants using other fossil fuels, such as coal. In addition, we strive to preserve our nation’s valuable water and land resources. To condense steam, our combined-cycle power plants use cooling towers 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. We believe that we will be less adversely impacted by cap-and-trade limits, carbon taxes or required environmental upgrades as a result of future potential regulation or legislation addressing GHG, other air pollutant emissions, as well as water use or emissions, than compared to our competitors who use other fossil fuels or older, less efficient technologies.

We remain focused on creating long-term shareholder value through making effective capital allocation decisions, 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 and optimize our various physical assets and contractual obligations, we will continue to execute commodity hedging agreements within the guidelines of our Risk Management Policy.

We sell a substantial portion of our power and other products under PPAs with a duration greater than one year. The contracted sale of power, steam and capacity from our cogeneration power plants, combustion turbine power plants and geothermal power plants, as well as the sale of renewable energy credits, or RECs, from our geothermal and solar power plants, provide a stable source of revenue. Our portfolio also affords us the flexibility to sell power and other products forward for shorter terms or

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on a merchant basis into the spot markets, where we are able to realize attractive pricing particularly during peak demand periods. Additionally, we sell capacity or similar products to retail power providers, utilities, municipalities and others required to acquire capacity and similar products by regulatory or market rules, and we sell ancillary services to independent system operators and utilities to support power transmission system reliability.

Our principal offices are located in Houston, Texas with regional offices in Dublin, California and Wilmington, Delaware, an engineering, construction and maintenance services office in Pasadena, Texas and government affairs offices in Washington D.C., Sacramento, California and Austin, Texas. We operate our business through a variety of divisions, subsidiaries and affiliates.

Strategy

Our goal is to be recognized as the premier independent power company in the U.S. as measured by our employees, shareholders, customers and regulators as well as the communities in which our facilities are located. We seek to achieve sustainable growth through financially disciplined power plant development, construction, acquisition, operation and ownership. Our strategy to achieve this is reflected in the five major initiatives described below:

1. Premier Operating Company — Our objective is to be the “best-in-class” in regards to certain operational performance metrics, such as safety, availability, reliability, efficiency and cost management.

• Throughout 2011, our plant operating personnel achieved the first quartile performance for employee lost time incident rate for fossil fuel electric power generation companies with 1,000 or more employees.

• We produced over 94 billion KWh in 2011.

• Our entire fleet achieved a forced outage factor of 2.5%.

• We achieved 98.4% fleet-wide starting reliability in 2011.

• During 2011, our Turbine Maintenance Group completed 16 major inspections and 15 hot gas path inspections.

• For the past eleven consecutive years, our Geysers Assets have reliably generated approximately 6 million MWh per year and, in 2011, achieved an exceptional availability factor of approximately 98%.

2. Focus on Enhancing Shareholder Value — We continue to make significant progress to maintain financially disciplined growth, to enhance shareholder value through our capital allocation and share repurchases and to set the foundation for continued growth and success. Given our strong cash flow from operations, we are committed to remaining financially disciplined in our capital allocation decisions. The year ended December 31, 2011 was marked by the following accomplishments:

• Our total shareholder return for 2011 was 22.4% (measured by the year over year change in our stock price).

• On August 23, 2011, we announced that our Board of Directors had authorized the repurchase of up to $300 million in shares of our common stock. Through the filing of this Report, a total of 8,524,576 shares of our outstanding common stock have been repurchased under this program for approximately $124 million at an average price paid of $14.60 per share.

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

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

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• On June 24, 2011, we closed on the approximately $845 million Russell City Project Debt to fund the construction of Russell City Energy Center and on August 23, 2011, we closed on the $373 million Los Esteros Project Debt to fund the upgrade of our Los Esteros Critical Energy Facility.

• During the fourth quarter of 2011, the U.S. Bankruptcy Court issued an order dismissing the Chapter 11 cases that remained open against the U.S. Debtors; thus, all matters related to our voluntary petitions for relief under Chapter 11 of the Bankruptcy Code filed in 2005 and 2006 are resolved and closed.

3. Leader in Environmental Responsibility — Our focus is to utilize our modern, efficient fleet to deliver low environmental impact energy solutions relative to other fossil fuel generation as part of our commitment to environmental stewardship. Some examples that demonstrate this commitment include:

• We continue to actively participate in legislative and regulatory processes addressing environmental concerns and support legislative and regulatory action to address best available control technology, cross-state air pollution, once-through cooling water systems, climate change, GHG and other air emissions from fossil fuel generation. We intend to leverage our baseload geothermal expertise to grow our renewable energy portfolio.

• Our strong and continuing commitment to environmental responsibility and leadership is exemplified by our development of the Russell City Energy Center which is under construction and intended to become the first power plant in the U.S. with a federal limit on GHG emissions. Russell City Energy Center will be designed to operate in a way that produces 25% fewer GHG emissions than the CPUC standard. The power plant will use 100% reclaimed water from the City of Hayward’s Water Pollution Control Facility for cooling and boiler makeup, which will prevent nearly four million gallons of wastewater per day from being discharged into the San Francisco Bay. We initiated and agreed to accept the GHG permit limit and designed the plant to benefit local water resources.

4. Focus on Leveraging our Three Scale Regions — Our goal is to continue to grow our presence in core markets with an emphasis on expansions or upgrades of existing power plants. We intend to take advantage of favorable opportunities to continue to design, develop, acquire, construct and operate the next generation of highly efficient, operationally flexible and environmentally responsible power plants where such investment meets our rigorous financial hurdles, particularly if power contracts and financing are available and attractive returns are expected. Likewise, we will actively seek divestiture opportunities on our non-core assets if those opportunities meet our financial expectations. In addition, we believe that upgrades and expansions to our current assets offer proven and financially disciplined opportunities to improve our operations, capacity and efficiencies. Our significant projects under construction, growth initiatives and upgrades are discussed below.

PJM:

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

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

◦ Garrison (Delaware): Actively permitting 618 MW of new combined-cycle capacity at a development site secured by a lease option with the City of Dover. PJM's system impact study for the first phase (309 MW) and the feasibility study for the second phase (309 MW) have been completed. Both studies are being reviewed internally. Environmental permitting, site development planning and development engineering are underway.

◦ Edge Moor (Delaware): A nominal 300 MW combined-cycle development project located at our Edge Moor facility which will leverage existing infrastructure. PJM is currently conducting a system impact study which will provide a detailed report on the project's interconnection costs.

West:

• Russell City Energy Center — The Russell City Energy Center is under construction and continues to move forward with expected COD in 2013. Upon completion, this project will bring on line approximately 429 MW of net interest baseload capacity (464 MW with peaking capacity) representing our 75% share. We are in possession of all required approvals and permits, and we closed on construction financing on June 24, 2011. Upon completion, the Russell City Energy Center is contracted to deliver its full output to PG&E under a ten-year PPA.

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• Los Esteros — During 2009, we and PG&E negotiated a new PPA to replace the existing California Department of Water Resources contract and facilitate the upgrade of our Los Esteros Critical Energy Facility from a 188 MW simple-cycle generation power plant to a 308 MW combined-cycle generation power plant, which will also increase the efficiency and environmental performance of the power plant by lowering the Heat Rate. The ten-year PPA and related agreements with PG&E have received all of the necessary approvals and licenses, which are now effective. The California Energy Commission has renewed our license and emission limits, which is final. The Bay Area Air Quality Management District issued its renewal of the Authority to Construct. We began construction in the second quarter of 2011 and obtained construction financing on August 23, 2011. We expect COD in 2013.

• Geysers Assets Expansion — We continue to look to expand our production from our Geysers Assets. Beginning in the fourth quarter of 2009, we conducted an exploratory drilling program, which effectively proved the commercial viability of the steam field in the northern part of our Geysers Assets. We have received Conditional Use Permits from Sonoma County and are pursuing the additional required permitting. We are pursuing commercial arrangements which will need to be in place prior to commencing expansion activities. We continue to believe our northern Geysers Assets have potential for development. In the meantime, we have connected certain test wells to our existing power plants to capture incremental production from those wells, while continuing with the permitting process, baseline engineering work and sales efforts for an expansion.

ERCOT:

• Channel and Deer Park Expansions — We continue to evaluate the ERCOT market for expansion opportunities based on tightening reserve margins and potential impact of EPA regulations on generation in Texas. At both our Deer Park and Channel Energy Centers, we have the ability to install an additional combustion turbine generator and connect to the existing steam turbine generator to expand the capacity of these facilities and to improve the overall efficiency. In September 2011, we filed an air permit application with the Texas Commission on Environmental Quality (“TCEQ”) and the EPA to expand the Deer Park Energy Center by approximately 275 MW. In November 2011, we filed similar permits with the TCEQ and the EPA to expand the Channel Energy Center by approximately 275 MW.

All Markets:

• Turbine Upgrades — We continue to move forward with our turbine upgrade program. Through December 31, 2011, we have completed the upgrade of ten Siemens and five GE turbines and have agreed to upgrade approximately six additional Siemens and GE turbines (and may upgrade additional turbines in the future). Our turbine upgrade program is expected to increase our generation capacity in total by approximately 275 MW. This upgrade program began in the fourth quarter of 2009 and is scheduled through 2014. The upgraded turbines have been operating with Heat Rates consistent with expectations.

5. Customer-Oriented Origination Business — We continue to focus on providing products and services that are beneficial to our customers.     A summary of certain significant contracts entered into or approved in 2011 is as follows:

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

• We have entered into a new tolling agreement with Southern California Edison to provide 750 MW of power generated by our Pastoria Energy Center which will commence in 2013, and we executed a new resource adequacy contract with the same counterparty for 715 MW from our Pastoria Energy Center which will commence in 2014.

• We have entered into a PPA with Tampa Electric Company for the full output of our Auburndale Peaking Energy Center which commenced in November 2011 and will run through December 2016.

THE MARKET FOR POWER

Our Power Markets and Market Fundamentals

The power industry represents one of the largest industries in the U.S. and impacts nearly every aspect of our economy, with an estimated end-user market of approximately $373 billion in power sales in 2011 according to the EIA. Historically, vertically integrated power utilities with monopolies over franchised territories dominated the power generation industry in the U.S. Over the last 25 years, industry trends and regulatory initiatives, culminating with the deregulation trend of the late 1990’s and early 2000’s, provided opportunities for independent wholesale power producers to compete to provide power. Although different regions of the country have very different models and rules for competition, the markets in which we operate have some form of wholesale market competition. California (included in our West segment), Texas and the Mid-Atlantic (included in our North segment), which are three of our largest markets, have emerged as among the most competitive wholesale power markets in the U.S. We also operate, to a lesser extent, in the competitive ISO-NE, NYISO and MISO markets. We produce several products for sale to our customers.

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• First, we produce power for sale to utilities, municipalities, retail power providers, independent electric system operators, large end-use industrial or agricultural customers or power marketers. Our power sales occur in several different product categories including baseload (around the clock generation), intermediate (generation typically more expensive than baseload and utilized during higher demand periods to meet shifting demand needs), and peaking capacity (most expensive variable cost and utilized during the highest demand periods), for which the latter is provided by some of our stand alone peaker power plants/units and from our combined-cycle power plants by using technologies such as steam injection or duct firing additional burners in the heat recovery steam generators. Many of our units have operated more frequently as baseload units at times when low natural gas prices have driven their production costs below those of some competing coal-fired units.

• Second, our cogeneration power plants produce steam for sale to customers for use in industrial or heating, ventilation and air conditioning operations.

• Third, we provide capacity for sale to retail power providers. In various markets, retail power providers are required to demonstrate adequate resources to meet their power sales commitments. To meet this obligation, they procure a market product known as capacity. Most electricity market administrators have acknowledged that an energy only market does not provide sufficient revenues to enable existing merchant generators to recover all of their costs or to encourage new generating capacity to be constructed. Capacity auctions have been implemented in the northeast, the Mid-Atlantic and some mid-west regional markets to address this issue. California has a bilateral capacity program. Texas does not presently have a capacity market.

• Fourth, we provide ancillary service products to wholesale power markets. These products include the right for the purchaser to call on our generation to provide flexibility to the market and support operation of the electric grid. As an example, we are sometimes paid to reserve a portion of some capacity at some of our power plants that could be deployed quickly should there be an unexpected increase in load or to assure reliability due to fluctuations in the supply of power from variable renewable resources such as wind and solar generation.

• Fifth, we sell RECs from our Geysers Assets in northern California, as well as from our small solar power plant in New Jersey. California has an RPS that requires load serving entities to have RECs for a certain percentage of their demand for the purpose of guaranteeing a certain level of renewable generation in the state. Because geothermal is a renewable source of energy, we receive a REC for each MWh we produce and are able to sell our RECs to load serving entities. New Jersey has a solar specific RPS which enables us to sell RECs from our Vineland Solar Energy Center.

In addition to the five products above, we are buyers and sellers of environmental allowances and credits, including those under RGGI, the federal Acid Rain and Clean Air Interstate Rule programs and emission reduction credits under the federal Nonattainment New Source Review program. We also participate in CO2 emissions credit markets related to California’s AB 32 GHG reduction program.

Although all of the products mentioned above contribute to our financial performance and are the primary components of our Commodity Margin, the most important is our sale of wholesale power. We utilize long-term customer contracts for our power and steam sales where possible. For power that is not sold under customer contracts, the short-term and spot market supply and demand fundamentals determine the sale price for our power.

For sales of power from our natural gas-fired fleet into the short-term or spot markets, we attempt to maximize our operations when the market Spark Spread is positive. Assuming economic behavior by market participants, generating units generally are dispatched in order of their variable costs, with lower cost units being dispatched first and units with higher costs dispatched as demand, or “load,” grows beyond the capacity of the lower cost units. For this reason, in a competitive market, the price of power typically is related to the variable operating costs of the marginal generator, which is the last unit to be dispatched in order to meet demand. The market factors that most significantly impact our operations are reserve margins, the price and supply of natural gas and competing fuels such as coal and oil, weather patterns and natural events, our operating Heat Rate and Availability, and regulatory and environmental pressures as further discussed below.

Reserve Margins

Reserve margin, a measure of how much excess generation capacity is present in a market, is a key indicator of the competitive conditions in the markets in which we operate. For example, a reserve margin of 15% indicates that supply is 115% of expected peak power demand under normal weather conditions. Holding other factors constant, lower reserve margins typically lead to higher power prices because the less efficient capacity in the region is needed more often to satisfy power demand. Markets with tight demand and supply conditions often display price spikes and improved bilateral contracting opportunities. Typically, the market price impact of reserve margins, as well as other supply/demand factors, is reflected in the Market Heat Rate calculated as the local market power price divided by the local natural gas price.

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During the last decade, the supply and demand fundamentals in many regional markets were negatively impacted by the combination of new generation coming on line and a general decline in weather normalized load growth rates due to the economic recession. Although uncertainty exists and there are key regional differences at a macro level, continued economic recovery and thus, corresponding load recovery, with the lack of broad new power plant investments in our key markets should lead to lower reserve margins and higher market Heat Rates. Reserve margins by NERC regional assessment area for each of our segments are listed below:

	2011(1)
West:
WECC	35.1	%
Texas:
TRE	17.5	%
North:
NPCC	28.1	%
MISO	24.0	%
PJM	32.3	%
Southeast:
SERC	28.4	%
SPP	27.9	%
FRCC	24.7	%

___________

(1) Data source is EIA

The Price and Supply of Natural Gas

Our fuel requirements are predominantly met with natural gas. We have approximately 725 MW of capacity from our Geysers Assets and our expectation is that the steam reservoir at our Geysers Assets will be able to supply economic quantities of steam for the foreseeable future as our steam flow decline rates have become very small over the past several years. We also have approximately 371 MW of capacity from power plants where we purchase fuel oil to meet these generation requirements if required, but do not expect fuel oil requirements to be material to our portfolio of power plant assets. Additionally, we have 4 MW of capacity from solar power generation technology with no fuel requirement.

We procure natural gas from multiple suppliers and transportation sources. Although availability is generally not an issue, localized shortages (especially in extreme weather conditions), transportation availability and supplier financial stability issues can and do occur.

Lower gas prices over the past three years have had a significant impact on power markets. Beginning in 2009, there was a significant decrease in NYMEX Henry Hub natural gas prices from a range of $6/MMBtu — $13/MMBtu during 2008 to an average natural gas price of $4.16, $4.38, and $4.03 during 2009, 2010 and 2011, respectively. Natural gas prices in some parts of the country for parts of 2009, 2010 and 2011 were low enough that modern combined-cycle natural gas-fired generation became less expensive on a marginal basis than coal-fired generation. The result was that natural gas displaced coal as a less expensive generation resource resulting in what the industry describes as coal-to-gas switching.

Although some of this lower pricing dynamic can be attributed to the economic recession, the availability of non-conventional natural gas supplies, in particular shale natural gas, has also kept natural gas prices low. Access to significant deposits of shale natural gas has altered the natural gas supply landscape in the U.S. and could have a longer-term and profound impact on both the outright price of natural gas and the historical regional natural gas price relationships (basis differentials). The U.S. Department of Energy estimates that shale natural gas production has the potential of 3 trillion to 4 trillion cubic feet per year and may be sustainable for decades with enough natural gas to supply the U.S. for the next 90 years. Accordingly, there is an emerging view that lower priced natural gas will be available for the medium to long-term future.

The relative price of natural gas can have varying results on our Commodity Margin and liquidity. The impact of changes in natural gas prices differs according to the time horizon and regional market conditions and depends on our hedge levels and other factors discussed below.

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Much of our generating capacity is located in California (included in our West segment), Texas and the Mid-Atlantic (included in our North segment) where natural gas-fired units set power prices during most hours or most “peak” hours. “Peak” hours are generally considered between the hours of 7:00 a.m. and 11:00 p.m., with the remaining hours considered “off-peak.” In California and Texas, natural gas-fired units set prices during most hours, although incremental renewable generation and coal-to-gas switching have moderated this dynamic somewhat in off-peak hours over the last year. In the Mid-Atlantic, natural gas-fired units set prices during most peak hours. Outside of our California, Texas and Mid-Atlantic markets, coal-fired power plants tend to set power prices more often.

When natural gas is the price-setting fuel, which is often the case in Texas, California and the Mid-Atlantic, increases in natural gas prices may increase our unhedged Commodity Margin because our combined-cycle power plants in those markets are more fuel-efficient than conventional natural gas-fired technologies and peaker power plants. Conversely, decreases in natural gas prices tend to decrease our unhedged Commodity Margin. In these instances, our cost of production advantage relative to less efficient natural gas-fired generation is diminished on an absolute basis.

Natural gas-fired combined-cycle units in many markets are now frequently cheaper to dispatch than coal-fired power plants. When coal-fired electricity production costs exceed natural gas-fired production costs, coal-fired units tend to set power prices. In these hours, lower natural gas prices tend to increase our Commodity Margin, since our production costs fall while power prices remain constant (depending on our hedge levels and holding other factors constant).

Where we operate under long-term contracts, changes in natural gas prices can have a neutral impact on us in the short-term. This tends to be the case where we have entered into tolling agreements under which the customer provides the natural gas and we convert it to power for a fee, or where we enter into indexed-based agreements with a contractual Heat Rate at or near our actual Heat Rate for a monthly payment.

Changes in natural gas prices may also affect our liquidity. During periods of high or volatile natural gas prices, we could be required to post additional cash collateral or letters of credit.

Over the long-term, we expect lower natural gas prices to increase coal-to-gas switching, thus enhancing the competitiveness of our modern natural gas fleet and making investments in coal less attractive. Despite these short-term dynamics, over the long run, we expect lower natural gas prices to enhance the competitiveness of our modern, natural gas-fired fleet by making investment in other technologies such as coal, nuclear, or renewables less economic.

Weather Patterns and Natural Events

Weather could have a significant short-term impact on supply and demand for power and natural gas. Historically, demand for and the price of power is higher in the summer and winter seasons when temperatures are more extreme, and therefore, our unhedged revenues and Commodity Margin could be negatively impacted by relatively cool summers or mild winters. Additionally, a disproportionate amount of our total revenue is usually realized during the summer months of our third fiscal quarter. We expect this trend to continue in the future as U.S. demand for power generally peaks during this time.

Operating Heat Rate and Availability

Our fleet is modern and more efficient than the average generation fleet; accordingly, we run more and earn incremental margin in markets where less efficient natural gas units frequently set the power price. In such cases, our unhedged Commodity Margin is positively correlated with how much more efficient our fleet is than our competitors’ fleets and with higher natural gas prices. Efficient operation of our fleet creates the opportunity to capture Commodity Margin. However, unplanned outages during periods when Commodity Margin is positive can result in a loss of that opportunity. We measure our fleet performance based on our operating Heat Rate and availability factors. The higher our availability factor, the better positioned we are to capture Commodity Margin. The lower our operating Heat Rate compared to the Market Heat Rate, the more favorable the impact on our Commodity Margin.

Regulatory and Environmental Pressures

We believe that, on a net basis, we will be favorably impacted by regulatory factors including those described below, given the characteristics of our power plant portfolio:

• An increase in power generated from renewable sources could lead to an increased need for flexible power that many of our power plants provide to protect the reliability of the grid; however, risks also exist that renewables have the ability to lower overall wholesale prices which could negatively impact us. Significant economic and reliability concerns for renewable generation have slowed their growth in 2011 and 2010 compared to 2009, but we expect that renewable market penetration will continue to be assisted by state-level renewable portfolio standards.

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• Environmental pressures continue to increase for coal-fired power generation as state and federal agencies enact rules to reduce air emissions of certain pollutants such as SO2, NOX, GHG, Hg and acid gases, restrict the use of once-through cooling, and provide for stricter standards for managing coal combustion residuals. Some of the regions in which we operate include older, less efficient fossil-fuel power plants that emit much higher amounts of GHG, SO2, NOX, Hg and acid gases, which we anticipate will be negatively impacted by future air emissions, water and waste regulations and legislation. The estimated capacity for fossil-fueled plants which are older than 50 years by NERC region are as follows:

West:
WECC	7,307	MW
Texas:
TRE	3,562	MW
North:
NPCC	6,381	MW
MRO	4,597	MW
RFC	27,612	MW
Southeast:
SERC	28,051	MW
SPP	4,781	MW
FRCC	1,211	MW
Total	83,502	MW

• Utilities are increasingly focused on demand side management – managing the level and timing of power usage through load curtailment, dispatching generators located at commercial or industrial sites, and “smart grid” technologies that may improve the efficiencies, dispatch usage and reliability of electric grids. Scrutiny of demand side resources has increased in recent months as system operators evaluate their reliability (especially at high levels of penetration) and environmental authorities grapple with the implications of relying on smaller, less environmentally efficient generation sources during periods of peak demand when air quality is already challenged.

• Environmental permitting requirements for new power plants and transmission lines are becoming increasingly onerous.

We believe these trends are positive for our fleet. For a discussion of federal, state and regional legislative and regulatory initiatives and how they might affect us, see “— Governmental and Regulatory Matters.”

It is very difficult to predict the continued evolution of our markets due to the uncertainty of the following:

• number of market participants;

• amount of power available in the market;

• fluctuations in power supply due to planned and unplanned outages of generators;

• fluctuations in power demand due to weather and other factors;

• cost of fuel, which could be impacted by the efficiency of generation technology and fluctuations in fuel supply or interruptions in natural gas transportation;

• relative ease or difficulty of developing, permitting and constructing new power plants;

• availability and cost of power transmission;

• potential growth of demand side management;

• creditworthiness and other risks associated with counterparties;

• bidding behavior of market participants;

• regulatory and ISO guidelines and rules;

• structure of commercial products; and

• ability to optimize the market’s mix of alternative sources of power such as renewable and hydroelectric power.

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Competition

Wholesale power generation is a capital-intensive, commodity-driven business with numerous industry participants. We compete against other independent power producers, power marketers and trading companies, including those owned by financial institutions, retail load aggregators, municipalities, retail power providers, cooperatives and regulated utilities to supply power and power-related products to our customers in major markets in the U.S. and Canada. In addition, in some markets, we compete against some of our customers.

In less regulated markets, such as California, Texas and the Mid-Atlantic, our natural gas-fired power plants compete directly with all other sources of power. The EIA estimates that in 2011, 24% of the power generated in the U.S. was fueled by natural gas and that approximately 62% of power generated in the U.S. was produced by coal and nuclear facilities, which generated approximately 43% and 19%, respectively. The EIA estimates that the remaining 14% of power generated in the U.S. was fueled by hydroelectric, fuel oil and other energy sources. 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. The federal government is expected to continue to take further action on many air pollutant emissions such as NOX, SO2, Hg and acid gases as well as on once-through cooling and coal ash disposal. Although we cannot predict the ultimate effect any future environmental legislation or regulations will have on our business, as a clean energy provider, we believe that we are well positioned for almost any increase in environmental rule stringency. 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.”

As environmental regulations evolve, the proportion of power generated by natural gas and other low emissions resources is expected to increase because older coal-fired power plants will likely have to install costly emission control devices, limit their operations or be retired. Meanwhile, the federal government and many states are considering or have already mandated that certain percentages of power delivered to end users in their jurisdictions be produced from renewable resources, such as geothermal, wind and solar energy.

Competition from other sources of power, such as nuclear energy and renewables, is expected to increase in the future, but at a lower rate than had been expected in 2008 or 2009. The nuclear incident in March 2011 at the Fukushima Daiichi nuclear power plant introduced substantial uncertainties around new nuclear power plant development in the U.S. In addition, the combination of emerging air emissions regulations, federal and state financial incentives and RPS requirements for renewables and their impact of expected increased investment in cleaner sources of generation will be somewhat counteracted by a lower natural gas price environment, which, should it persist, makes new investment in these types of power generation generally uneconomical. Thus, it is doubtful that generation from new nuclear power plants and renewable sources will be available in the quantities needed to meet future energy demand. Beyond economic issues, there are concerns over the reliability and adequacy of transmission infrastructure to transmit certain renewable generation from its source to where it is needed. Consequently, longer-term, natural gas is likely still needed as baseload and “back-up” generation.

We believe our ability to compete will be driven by the extent to which we are able to accomplish the following:

• maintain excellence in operations;

• achieve and maintain a lower cost of production, primarily by maintaining unit availability and efficiency;

• benefit from future environmental regulation and legislation;

• accurately assess and effectively manage our risks; and

• provide reliable service to our customers.

MARKETING, HEDGING AND OPTIMIZATION ACTIVITIES

Our hedging strategy and commercial efforts attempt to maximize our risk adjusted Commodity Margin by leveraging our knowledge, experience and fundamental views on natural gas and power. We actively manage our commodity price risk with a variety of tools, including PPAs and other long-term contracts for the sale of power and steam. We also pursue other long-term sales opportunities, as well as shorter term market transactions, including bilateral originated sales contracts, and purchase and sale of exchange-traded instruments. We actively monitor risks such as Market Heat Rate and natural gas price exposure, as well as other risks related to the value of our generation such as capacity and geographic locational risk in both power and natural gas, REC and emission credit pricing. The relative quantity of our products hedged or sold under longer term contracts is determined by the availability of forward product sales opportunities and our view of the attractiveness of the pricing available for forward sales or through hedging. It is our strategy to seek stronger bilateral relationships under long-term contracts with load serving entities that can benefit us and our customers.

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The majority of our marketing, hedging and optimization activities are related to risk exposures that arise from our ownership and operation of power plants. We are one of the largest consumers of natural gas in the U.S. having consumed approximately 715 Bcf during 2011. Most of the power generated by our power plants is sold to entities such as utilities, municipalities and cooperatives, as well as to retail power providers, commercial and industrial end users, financial institutions, power trading and marketing companies and other third parties. We enter into physical and financial purchase and sale transactions as part of our marketing, hedging and optimization activities. We actively seek to manage and limit the commodity risks of our portfolio, utilizing multiple strategies of buying and selling power, natural gas and Heat Rate contracts to manage our Spark Spread and products that manage geographic price differences (basis differential). We have approximately 371 MW of capacity from power plants that have flexibility as to fuel source where we purchase fuel oil to meet these generation requirements if required; however, we have not currently entered into any hedging or optimization transactions for our fuel oil requirements as we do not expect fuel oil requirements to be material to us, but may elect to do so in the future.

Along with our portfolio of hedging transactions, we enter into power and natural gas positions that often act as economic hedges to our asset portfolio, but do not qualify for or we elect not to designate 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) or instruments that settle on power price relationships between delivery points. While our selling and purchasing of power and natural gas is mostly physical in nature, we also engage in marketing, hedging and optimization activities, particularly in natural gas, that are financial in nature. We use derivative instruments, which include physical commodity contracts and financial commodity instruments such as OTC and exchange traded swaps, futures, options, forward agreements and instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) for the purchase and sale of power, natural gas, and emission allowances to manage commodity price risk and to maximize the risk-adjusted returns from our power and natural gas assets. We conduct these hedging and optimization activities within a structured risk management framework based on controls, policies and procedures. We monitor these activities through active and ongoing management and oversight, defined roles and responsibilities, and daily risk measurement and reporting. Additionally, we seek to manage the associated risks through diversification, by controlling position sizes, by using portfolio position limits, and by entering into offsetting positions that lock in a margin. We also are exposed to commodity price movements (both profits and losses) in connection with these transactions. These positions are included in and subject to our consolidated risk management portfolio position limits and controls structure. Changes in fair value of commodity positions that do not qualify for or we do not elect either hedge accounting or the normal purchase normal sale exemption are recognized currently in earnings within operating revenues in the case of power transactions, and within fuel and purchased energy expense, in the case of natural gas transactions. Our future hedged status, and marketing and optimization activities are subject to change as determined by our commercial operations group, Chief Risk Officer, Risk Management Committee of senior management and Board of Directors.

We have economically hedged a portion of our expected generation and natural gas portfolio mostly through power and natural gas forward physical and financial transactions; however, we remain susceptible to significant price movements for 2012 and beyond. By entering into these transactions, we are able to economically hedge a portion of our Spark Spread at pre-determined generation and price levels. We use a combination of PPAs and other hedging instruments to manage our variability in future cash flows. At December 31, 2011, the maximum length of time that our PPAs extended was approximately 23 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 12 years, respectively.

We have historically used interest rate swaps to adjust the mix between our fixed and variable rate debt. To the extent eligible, our interest rate swaps have been designated as cash flow hedges, and changes in fair value are recorded in OCI to the extent they are effective with gains and losses reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The reclassification of unrealized losses from AOCI into income and the changes in fair value and settlements subsequent to the reclassification date of the interest rate swaps formerly hedging our First Lien Credit Facility is presented separately from interest expense as loss on interest rate derivatives on our Consolidated Statements of Operations. On January 14, 2011, we repaid the remaining balance under the First Lien Credit Facility term loans with the proceeds received from the issuance of the 2023 First Lien Notes and the unrealized losses related to these interest rate swaps of approximately $91 million previously recorded in AOCI were reclassified out of AOCI and into income as additional loss on interest rate derivatives during 2011. In addition, we reclassified approximately $17 million in unrealized losses in AOCI to loss on interest rate derivatives during 2011 resulting from the repayment of project debt in June 2011. During 2010, we reclassified approximately $206 million out of AOCI and into income as additional loss on interest rate derivatives related to interest rate swaps formerly hedging our First Lien Credit Facility term loans.

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We have VAR limits that govern the overall risk of our portfolio of power plants, energy contracts, financial hedging transactions and other contracts. Our VAR limits, transaction approval limits and other risk related controls, are dictated by our Risk Management Policy which is approved by our Board of Directors and by our Risk Management Committee comprised of members of our senior management and administered by our Chief Risk Officer and his organization. The Chief Risk Officer’s organization is segregated from the commercial operations unit and reports directly to our Audit Committee and Chief Executive Officer. Our Risk Management Policy is primarily intended to provide us with a degree of protection from significant downside energy commodity price exposure to our cash flows.

Seasonality and weather can have a significant impact on our results of operations and are also considered in our hedging and optimization activities. Most of our power plants are located in regional power markets where the greatest demand for power occurs during the summer months, which is our fiscal third quarter. Depending on existing contract obligations and forecasted weather and power demands, we may maintain either a larger or smaller open position on fuel supply and committed generation during the summer months in order to protect and enhance our Commodity Margin accordingly.

SEGMENT AND SIGNIFICANT CUSTOMER INFORMATION

See Note 16 of the Notes to Consolidated Financial Statements for a discussion of financial information by reportable segment and sales in excess of 10% of our annual consolidated revenues to one of our customers.

DESCRIPTION OF OUR POWER PLANTS

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Power Plants in Operation at December 31, 2011

We own 93 power plants, including 2 under construction, with an aggregate generation capacity of approximately 28,155 MW and 584 MW under construction.

Natural Gas-Fired Fleet

Our natural gas-fired power plants primarily utilize two types of design: 3,515 MW of simple-cycle combustion turbines and 23,043 MW of combined-cycle combustion turbines and a small portion from natural gas-fired steam turbines. Simple-cycle combustion turbines burn natural gas or oil to spin a single electric generator to produce power. A combined-cycle unit combusts fuel like a simple-cycle combustion turbine and the exhaust heat is captured by a boiler to create steam which can then spin a steam turbine. Simple-cycle turbines are easier to maintain, but combined-cycle turbines operate with much higher efficiency. Our “all in” Steam Adjusted Heat Rate for 2011 for the power plants we operate was 7,412 Btu/KWh which results in a power conversion efficiency of approximately 46%. The power conversion efficiency is a measure of how efficiently a fossil fuel power plant converts thermal energy to electrical energy. Our “all in” Steam Adjusted Heat Rate includes all fuel required to dispatch our power plants including “start-up” and “shut-down” fuel, as well as all non-steady state operations. Once our power plants achieve steady state operations, our combined-cycle power plants achieve an average power conversion efficiency of approximately 50%. Additionally, we also sell steam from our combined heat and power plants, which improves our power conversion efficiency in steady state operations from these power plants to an average of approximately 53%. Due to our modern combustion turbine fleet, our power conversion efficiency is significantly better than that of older technology natural gas-fired power plants and coal-fired power plants, which typically have power conversion efficiencies that range from 31% to 36%.

Each of our power plants currently in operation is capable of producing power for sale to a utility, another third-party end user or an intermediary such as a marketing company. At some of our power plants we also produce thermal energy (primarily steam and chilled water), which can be sold to industrial and governmental users.

Our natural gas fleet is relatively young with a weighted average age, based upon MW capacities in operation, of approximately twelve years. Taken as a portfolio, our natural gas power plants are among the most efficient in converting natural gas to power and emit far fewer pollutants than most typical utility fleets. The age, scale, efficiency and cleanliness of our power plants is a unique profile in the independent power sector.

The majority of the combustion turbines in our fleet are one of four technologies: GE 7FA, GE LM6000, Siemens 501FD or Siemens V84.2 turbines. We maintain our fleet through a regular and rigorous maintenance program. As units reach certain targets recommended by the original equipment manufacturer, which are typically based upon service hours or number of starts, we perform the maintenance that is required for that unit at that stage in its life cycle. Our large fleet of similar technologies has enabled us to build significant technical and engineering experience with these units. We leverage this experience by performing much of our major maintenance ourselves with our Turbine Maintenance Group subsidiary.

Geothermal Fleet

Our Geysers Assets are a 725 MW fleet of 15 operating power plants in northern California. Geothermal power is considered a renewable energy because the steam harnessed to power our turbines is produced inside the Earth and does not require burning fuel. The steam is produced below the Earth’s surface from reservoirs of hot water, both naturally occurring and injected. The steam is piped directly from the underground production wells to the power plants and used to spin turbines to make power. For the past eleven consecutive years, our Geysers Assets have continued to generate approximately 6 million MWh per year. Unlike other renewable resources such as wind or sunlight, which depend on intermittent sources to generate power, making them less reliable, geothermal power provides a consistent source of energy as evidenced by our Geysers Assets’ availability record of approximately 98% in 2011.

We inject water back into the steam reservoir, which extends the useful life of the resource and helps to maintain the output of our Geysers Assets. The water we inject comes from the condensate associated with the steam extracted to generate power, wells and creeks, as well as water purchase agreements for reclaimed wastewater. We receive and inject an average of approximately 18 million gallons of reclaimed wastewater per day into the geothermal steam reservoir at The Geysers where the water is naturally heated by the Earth, creating additional steam to fuel our Geysers Assets. Approximately 14 million gallons per day is received from the Santa Rosa Geysers Recharge Project, developed by us and the City of Santa Rosa, which was previously being discharged into the Russian River and we receive, on average, approximately 4 million gallons a day from The Lake County Recharge Project from Lake County. As a result, MWh production has been approximately flat. We expect that, as a result of the water injection program, the reservoir at our Geysers Assets will be able to supply economic quantities of steam for the foreseeable future.

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We periodically review our geothermal studies to help us assess the economic life of our geothermal reserves. Our most recent geothermal reserve study was conducted in 2011. Our evaluation of our geothermal reserves, including our review of any applicable independent studies conducted, indicates that our Geysers Assets should continue to supply sufficient steam to generate positive cash flows at least through 2068. In reaching this conclusion, our evaluation, consistent with the due diligence study of 2011, assumes that defined “proved reserves” are those quantities of geothermal energy which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions, operating methods, and government regulations.

We lease the geothermal steam fields from which we extract steam for our Geysers Assets. We have leasehold mineral interests in 110 leases comprising approximately 29,019 acres of federal, state and private geothermal resource lands in The Geysers region of northern California. Our leases cover one contiguous area of property that comprises approximately 45 square miles in the northwest corner of Sonoma County and southeast corner of Lake County. The approximate breakout by volume of steam removed under the above leases for the year ended 2011 is:

• 29% related to leases with the federal government via the Office of Natural Resources Revenue (formerly, the Minerals Management Service),

• 27% related to leases with the California State Lands Commission, and

• 44% related to leases with private landowners/leaseholders.

In general, our geothermal leases grant us the exclusive right to drill for, produce and sell geothermal resources from these properties and the right to use the surface for all related purposes. Each lease requires the payment of annual rent until commercial quantities of geothermal resources are established. After such time, the leases require the payment of minimum advance royalties or other payments until production commences, at which time production royalties are payable on a monthly basis from 10 to 31 days (depending upon the lease terms) following the close of the production month. Such royalties and other payments are payable to landowners, state and federal agencies and others, and vary widely as to the particular lease. In general, royalties payable are calculated based upon a percentage of total gross revenue received by us associated with our geothermal leases. Each lease’s royalty calculation is based upon its percentage of revenue as calculated by its steam generated to the total steam generated by our Geysers Assets as a whole.

Our geothermal leases are generally for initial terms varying from 10 to 20 years or for so long as geothermal resources are produced and sold. A few of our geothermal leases were signed in excess of 30 years ago. Our federal leases are, in general, for an initial 10-year period with renewal clauses for an additional 40 years for a maximum of 50 years. The 50-year term expires in 2024 for the majority of our federal leases. However, our federal leases allow for a preferential right to renewal for a second 40-year term on such terms and conditions as the lessor deems appropriate if, at the end of the initial 40-year term, geothermal steam is being produced or utilized in commercial quantities. The majority of our other leases run through the economic life of our Geysers Assets and provide for renewals so long as geothermal resources are being produced or utilized, or are capable of being produced or utilized, in commercial quantities from the leased land or from land unitized with the leased land. Although we believe that we will be able to renew our leases through the economic life of our Geysers Assets on terms that are acceptable to us, it is possible that certain of our leases may not be renewed, or may be renewable only on less favorable terms.

In addition, we hold 40 geothermal leases comprising approximately 43,840 acres of federal geothermal resource lands in the Glass Mountain area in northern California, which is separate from The Geysers region. Four test production wells were drilled prior to our acquisition of these leases and we have drilled one test well since their acquisition, which produced commercial quantities of steam during flow tests. However, the properties subject to these leases have not been developed and there can be no assurance that these leases will ultimately be developed. We are currently involved in litigation concerning our Glass Mountain leases. See Note 15 of the Notes to Consolidated Financial Statements for a description of litigation relating to our Glass Mountain area leases.

Other Power Generation Technologies

Across the fleet, we also have a variety of older, less efficient technologies including approximately 868 MW of capacity from our power plants acquired in the Conectiv Acquisition which have conventional steam turbine technology. We also have approximately 4 MW of capacity from solar power generation technology at our Vineland Solar Energy Center in New Jersey.

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Table of Operating Power Plants and Projects Under Construction

Set forth below is certain information regarding our operating power plants and projects under construction at December 31, 2011.

SEGMENT / Power Plant	NERC Region	U.S. State or Canadian Province	Technology	Calpine Interest Percentage		Calpine Net Interest Baseload (MW)(1)(3)	Calpine Net Interest With Peaking (MW)(2)(3)	2011 Total MWh Generated(4)
WEST
Geothermal
McCabe #5 & #6	WECC	CA	Geothermal	100	%	78	78	684,076
Ridge Line #7 & #8	WECC	CA	Geothermal	100	%	69	69	631,318
Calistoga	WECC	CA	Geothermal	100	%	66	66	522,265
Eagle Rock	WECC	CA	Geothermal	100	%	66	66	569,986
Quicksilver	WECC	CA	Geothermal	100	%	53	53	383,283
Cobb Creek	WECC	CA	Geothermal	100	%	52	52	425,984
Lake View	WECC	CA	Geothermal	100	%	52	52	430,864
Sulphur Springs	WECC	CA	Geothermal	100	%	51	51	422,585
Socrates	WECC	CA	Geothermal	100	%	50	50	372,387
Big Geysers	WECC	CA	Geothermal	100	%	48	48	468,186
Grant	WECC	CA	Geothermal	100	%	43	43	309,729
Sonoma	WECC	CA	Geothermal	100	%	42	42	304,220
West Ford Flat	WECC	CA	Geothermal	100	%	24	24	221,138
Aidlin	WECC	CA	Geothermal	100	%	17	17	132,180
Bear Canyon	WECC	CA	Geothermal	100	%	14	14	102,764
Natural Gas-Fired
Delta Energy Center	WECC	CA	Natural Gas	100	%	835	857	4,163,744
Pastoria Energy Center	WECC	CA	Natural Gas	100	%	750	729	2,911,112
Hermiston Power Project	WECC	OR	Natural Gas	100	%	566	635	1,155,893
Otay Mesa Energy Center	WECC	CA	Natural Gas	100	%	513	608	2,061,805
Metcalf Energy Center	WECC	CA	Natural Gas	100	%	564	605	1,588,552
Sutter Energy Center	WECC	CA	Natural Gas	100	%	542	578	952,805
Los Medanos Energy Center	WECC	CA	Natural Gas	100	%	518	572	2,692,583
South Point Energy Center	WECC	AZ	Natural Gas	100	%	520	530	805,650
Los Esteros Critical Energy Facility(5)	WECC	CA	Natural Gas	100	%	—	188	66,547
Gilroy Energy Center	WECC	CA	Natural Gas	100	%	—	141	31,853
Gilroy Cogeneration Plant	WECC	CA	Natural Gas	100	%	109	130	42,998
King City Cogeneration Plant	WECC	CA	Natural Gas	100	%	120	120	601,960
Greenleaf 1 Power Plant	WECC	CA	Natural Gas	100	%	50	50	209,154
Greenleaf 2 Power Plant	WECC	CA	Natural Gas	100	%	49	49	300,444
Wolfskill Energy Center	WECC	CA	Natural Gas	100	%	—	48	9,889
Yuba City Energy Center	WECC	CA	Natural Gas	100	%	—	47	14,753
Feather River Energy Center	WECC	CA	Natural Gas	100	%	—	47	13,056
Creed Energy Center	WECC	CA	Natural Gas	100	%	—	47	4,889
Lambie Energy Center	WECC	CA	Natural Gas	100	%	—	47	5,500
Goose Haven Energy Center	WECC	CA	Natural Gas	100	%	—	47	5,773
Riverview Energy Center	WECC	CA	Natural Gas	100	%	—	47	11,279
King City Peaking Energy Center	WECC	CA	Natural Gas	100	%	—	44	4,796
Agnews Power Plant	WECC	CA	Natural Gas	100	%	28	28	187,034
Subtotal						5,889	6,919	23,823,034

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SEGMENT / Power Plant	NERC Region	U.S. State or Canadian Province	Technology	Calpine Interest Percentage		Calpine Net Interest Baseload (MW)(1)(3)	Calpine Net Interest With Peaking (MW)(2)(3)	2011 Total MWh Generated(4)
TEXAS
Deer Park Energy Center	TRE	TX	Natural Gas	100	%	830	1,001	5,602,160
Baytown Energy Center	TRE	TX	Natural Gas	100	%	782	842	4,240,920
Pasadena Power Plant	TRE	TX	Natural Gas	100	%	763	781	3,898,928
Freestone Energy Center	TRE	TX	Natural Gas	75	%	779	746	3,202,932
Magic Valley Generating Station	TRE	TX	Natural Gas	100	%	662	692	3,748,570
Channel Energy Center	TRE	TX	Natural Gas	100	%	463	608	2,742,657
Brazos Valley Power Plant	TRE	TX	Natural Gas	100	%	520	606	2,325,886
Corpus Christi Energy Center	TRE	TX	Natural Gas	100	%	426	500	2,545,531
Texas City Power Plant	TRE	TX	Natural Gas	100	%	400	453	1,451,866
Clear Lake Power Plant	TRE	TX	Natural Gas	100	%	344	400	821,766
Hidalgo Energy Center	TRE	TX	Natural Gas	79	%	392	374	1,970,402
Freeport Energy Center(6)	TRE	TX	Natural Gas	100	%	210	236	1,514,635
Subtotal						6,571	7,239	34,066,253
NORTH
Bethlehem Energy Center	RFC	PA	Natural Gas	100	%	1,037	1,130	4,105,331
Hay Road Energy Center	RFC	DE	Natural Gas	100	%	1,030	1,130	3,919,934
Edge Moor Energy Center	RFC	DE	Natural Gas	100	%	—	725	662,886
Riverside Energy Center	MRO	WI	Natural Gas	100	%	518	603	859,844
York Energy Center	RFC	PA	Natural Gas	100	%	519	565	1,300,635
Westbrook Energy Center	NPCC	ME	Natural Gas	100	%	543	543	2,655,159
Greenfield Energy Centre(7)	NPCC	ON	Natural Gas	50	%	422	519	1,549,488
RockGen Energy Center	MRO	WI	Natural Gas	100	%	—	503	180,909
Zion Energy Center	RFC	IL	Natural Gas	100	%	—	503	111,224
Mankato Power Plant	MRO	MN	Natural Gas	100	%	280	375	339,617
Cumberland Energy Center	RFC	NJ	Natural Gas	100	%	—	191	57,234
Deepwater Energy Center	RFC	NJ	Natural Gas	100	%	—	158	47,252
Kennedy International Airport Power Plant	NPCC	NY	Natural Gas	100	%	110	121	547,446
Sherman Avenue Energy Center	RFC	NJ	Natural Gas	100	%	—	92	33,494
Bethpage Energy Center 3	NPCC	NY	Natural Gas	100	%	60	80	218,715
Middle Energy Center	RFC	NJ	Oil	100	%	—	77	2,204
Carll's Corner Energy Center	RFC	NJ	Natural Gas	100	%	—	73	13,783
Cedar Energy Center	RFC	NJ	Oil	100	%	—	68	1,773
Mickleton Energy Center	RFC	NJ	Natural Gas	100	%	—	67	1,790
Missouri Avenue Energy Center	RFC	NJ	Oil	100	%	—	60	2,134
Bethpage Power Plant	NPCC	NY	Natural Gas	100	%	55	56	101,804
Christiana Energy Center	RFC	DE	Oil	100	%	—	53	188
Bethpage Peaker	NPCC	NY	Natural Gas	100	%	—	48	70,917
Stony Brook Power Plant	NPCC	NY	Natural Gas	100	%	45	47	275,170
Tasley Energy Center	RFC	VA	Oil	100	%	—	33	459
Whitby Cogeneration(8)	NPCC	ON	Natural Gas	50	%	25	25	201,893
Delaware City Energy Center	RFC	DE	Oil	100	%	—	23	41
West Energy Center	RFC	DE	Oil	100	%	—	20	164
Bayview Energy Center	RFC	VA	Oil	100	%	—	12	1,973
Crisfield Energy Center	RFC	MD	Oil	100	%	—	10	427
Vineland Solar Energy Center	RFC	NJ	Solar	100	%	—	4	4,841
Subtotal						4,644	7,914	17,268,729

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SEGMENT / Power Plant	NERC Region	U.S. State or Canadian Province	Technology	Calpine Interest Percentage		Calpine Net Interest Baseload (MW)(1)(3)	Calpine Net Interest With Peaking (MW)(2)(3)	2011 Total MWh Generated(4)
SOUTHEAST
Oneta Energy Center	SPP	OK	Natural Gas	100	%	980	1,134	2,915,991
Broad River Energy Center	SERC	SC	Natural Gas	100	%	—	847	741,260
Morgan Energy Center	SERC	AL	Natural Gas	100	%	720	807	3,446,638
Decatur Energy Center	SERC	AL	Natural Gas	100	%	782	795	4,451,786
Columbia Energy Center	SERC	SC	Natural Gas	100	%	455	606	150,550
Osprey Energy Center	FRCC	FL	Natural Gas	100	%	537	599	2,444,365
Carville Energy Center	SERC	LA	Natural Gas	100	%	449	501	2,255,911
Hog Bayou Energy Center	SERC	AL	Natural Gas	100	%	235	237	717,022
Santa Rosa Energy Center	SERC	FL	Natural Gas	100	%	235	225	380,130
Pine Bluff Energy Center	SERC	AR	Natural Gas	100	%	184	215	1,433,118
Auburndale Peaking Energy Center	FRCC	FL	Natural Gas	100	%	—	117	45,802
Subtotal						4,577	6,083	18,982,573
Total operating power plants (92)						21,681	28,155	94,140,589
Projects under construction
Russell City Energy Center (9)	WECC	CA	Natural Gas	75	%	429	464	n/a
Los Esteros Critical Energy Facility (Upgrade)(5)	WECC	CA	Natural Gas	100	%	120	120	n/a
Total operating power plants and projects						22,230	28,739

___________

(1) Natural gas-fired fleet capacities are derived on as-built as-designed outputs, including upgrades, based on site specific annual average temperatures and average process steam flows for cogeneration power plants, as applicable. Geothermal capacities are derived from historical generation output and steam reservoir modeling under average ambient conditions (temperatures and rainfall).

(2) Natural gas-fired fleet peaking capacities are primarily derived on as-built as-designed peaking outputs based on site specific average summer temperatures and include power enhancement features such as heat recovery steam generator duct-firing, gas turbine power augmentation and/or other power augmentation features. For certain power plants with definitive contracts, capacities at contract conditions have been included. Oil-fired capacities reflect capacity test results.

(3) These outputs do not factor in the typical MW loss and recovery profiles over time, which natural gas-fired turbine power plants display associated with their planned major maintenance schedules.

(4) MWh generation is shown here as our net operating interest.

(5) Los Esteros Critical Energy Facility is currently under construction to upgrade from a 188 MW simple-cycle generation power plant to a 308 MW combined-cycle generation power plant.

(6) Freeport Energy Center is owned by Calpine; however, it is contracted and operated by The Dow Chemical Company.

(7) Calpine holds a 50% partnership interest in Greenfield Energy Centre through its subsidiaries; however, it is operated by a third party.

(8) Calpine holds a 50% partnership interest in Whitby Cogeneration through its subsidiaries; however, it is operated by Atlantic Packaging Products Ltd.

(9) Calpine holds a 75% majority interest in Russell City Energy Center.

We provide operations and maintenance services for all but three of the power plants in which we have an interest. Such services include the operation of power plants, geothermal steam fields, wells and well pumps and natural gas pipelines. We also supervise maintenance, materials purchasing and inventory control, manage cash flow, train staff and prepare operations and maintenance manuals for each power plant that we operate. As a power plant develops an operating history, we analyze its operation and may modify or upgrade equipment, or adjust operating procedures or maintenance measures to enhance the power plant’s

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reliability or profitability. Although we do not operate the Freeport Energy Center, our Turbine Maintenance Group performs all major maintenance services for this plant under a contract with The Dow Chemical Company through April 2032.

Certain power plants in which we have an interest have been financed primarily with project financing that is structured to be serviced out of the cash flows derived from the sale of power (and, if applicable, thermal energy and capacity) produced by such power plants and generally provide that the obligations to pay interest and principal on the loans are secured 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 under these project financings generally have no recourse for repayment against us or any of our assets or the assets of any other entity other than foreclosure on pledges of stock or partnership interests and the assets attributable to the entities that own the power plants. However, defaults under some project financings may result in cross-defaults to certain of our other debt and debt instruments, including our First Lien Notes, Term Loan, New Term Loan and Corporate Revolving Facility. Acceleration of the maturity of a project financing following a default may also result in a cross-acceleration of such other debt.

Substantially all of the power plants in which we have an interest are located on sites which we own or lease on a long-term basis.

EMISSIONS AND OUR ENVIRONMENTAL PROFILE

Our environmental record has been widely recognized. We were an EPA Climate Leaders Partner with a stated goal to reduce GHG emissions, we became the first power producer to earn the distinction of Climate Action Leader^TM, and we have certified our GHG emissions inventory with the California Climate Action Registry every year since 2003. In 2010, our emissions of GHG amounted to about 42 million tons.

Natural Gas-Fired Generation

Our natural gas-fired, primarily combined-cycle fleet consumes significantly less fuel to generate power than conventional boiler/steam turbine power plants and emits fewer air pollutants per MWh of power produced as compared to coal-fired or oil-fired power plants. All of our power plants have air emissions controls and most have selective catalytic reduction to further reduce emissions of nitrogen oxides, a precursor of atmospheric ozone. In addition, we have implemented a program of proprietary operating procedures to reduce natural gas consumption and further lower air pollutant emissions per MWh of power generated. The table below summarizes approximate air pollutant emission rates from our natural gas-fired, combined-cycle power plants compared to the average emission rates from U.S. coal-, oil- and natural gas-fired power plants as a group, based on the most recent statistics available to us.

	Air Pollutant Emission Rates — Pounds of Pollutant Emitted Per MWh of Power Generated
Air Pollutants	Average U.S. Coal-, Oil-, and Natural Gas-Fired Power Plant(1)	Calpine Natural  Gas-Fired, Combined-Cycle Power Plant(2)	Advantage Compared to Average U.S. Coal-, Oil-, and Natural Gas-Fired Power Plant
Nitrogen Oxide, NOx	1.94	0.14	92.8%
Acid rain, smog and fine particulate formation
Sulfur Dioxide, SO2	4.20	0.0064	99.8%
Acid rain and fine particulate formation
Mercury Compounds(3)	0.000030	—	100%
Neurotoxin
Carbon Dioxide, CO2	1,858	904	51.3%
Principal GHG—contributor to climate change

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(1) The average U.S. coal-, oil- and natural gas-fired power plants' emission rates were obtained from the U.S. Department of Energy’s Electric Power Annual Report for 2010. Emission rates are based on 2010 emissions and net generation. The U.S. Department of Energy has not yet released 2011 information.

(2) Our natural gas-fired, combined-cycle power plant estimated emission rates are based on our 2010 emissions and power generation data from our natural gas-fired combined-cycle power plants (excluding combined heat power plants) as measured under the EPA reporting requirements.

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(3) The U.S. coal-, oil- and natural gas-fired power plant air emissions of mercury compounds were obtained from the U.S. EPA Toxics Release Inventory for 2010. Emission rates are based on 2010 emissions and net generation from U.S. Department of Energy’s Electric Power Annual Report for 2010.

Geothermal Generation

Our 725 MW fleet of geothermal power plants utilizes a natural, renewable energy source, steam from the Earth’s interior, to generate power. Since these power plants do not burn fossil fuel, they are able to produce power with negligible CO2 (the principal GHG), NOX and SO2 emissions. Compared to the average U.S. coal-, oil- and natural gas-fired power plant, our Geysers Assets emit 99.9% less NOX, 100% less SO2 and 96.8% less CO2. There are 18 active geothermal power plants located in The Geysers region of northern California. We own and operate 15 of them. We recognize the importance of our Geysers Assets and we are committed to extending and expanding this renewable geothermal resource through the addition of new steam wells and wastewater recharge projects where clean, reclaimed wastewater from local municipalities is recycled into the geothermal resource where it is converted by the Earth’s heat into steam for power production.

Water Conservation and Reclamation

We have also invested substantially in technologies and systems that reduce the impact of our operations on water as a natural resource:

• We receive and inject an average of approximately 18 million gallons of reclaimed wastewater per day into the geothermal steam reservoir at The Geysers where the water is naturally heated by the Earth, creating additional steam to fuel our Geysers Assets. Approximately 14 million gallons is received from the Santa Rosa Geysers Recharge Project, developed by us and the City of Santa Rosa, which was previously being discharged into the Russian River, and we receive, on average, approximately 4 million gallons a day from The Lake County Recharge Project from Lake County.

• In our combined-cycle plants we use mechanical draft cooling towers, which consume up to 90 percent less water than conventional once-through cooling systems. Two of our combined-cycle plants employ air-cooled condensers, which consume virtually no water for cooling. We use once-through cooling systems at only two power plants, our Deepwater and Edge Moor power plants.

• Through separate agreements with several municipalities where we use cooling towers, we use treated wastewater for cooling at several of our power plants. This eliminates the need to consume valuable surface and/or groundwater supplies, in the amount of three to four million gallons per day for an average power plant.

• Our Russell City Energy Center will use 100% reclaimed water from the City of Hayward’s Water Pollution Control Facility for cooling and boiler makeup, which will prevent nearly four million gallons of wastewater per day from being discharged into the San Francisco Bay.

GOVERNMENTAL AND REGULATORY MATTERS

We are subject to complex and stringent energy, environmental and other laws and regulations at the federal, state and local levels as well as within the RTO and ISO markets in which we participate in connection with the development, ownership and operation of our power plants. Federal and state legislative and regulatory actions continue to change how our business is regulated.

Environmental Matters

Federal Regulation of Air Emissions

The CAA provides for the regulation of air quality and air emissions, largely through state implementation of federal requirements. We believe that all of our operating power plants comply with existing federal and state performance standards mandated under the CAA. We continue to monitor and actively participate in EPA initiatives where we anticipate an impact on our business. Some of the more significant governmental and regulatory matters that affect our business are discussed below.

Criteria Pollutants and Hazardous Air Pollutants

The CAA requires the EPA to regulate emissions of pollutants considered harmful to public health and the environment. The EPA has set NAAQS for six “criteria” pollutants: carbon monoxide, lead, NO2, particulate matter (“PM”), ozone and SO2. In addition, the CAA regulates a large number of air pollutants that are known to cause or may reasonably be anticipated to cause adverse effects to human health or adverse environmental effects, known as hazardous air pollutants (“HAPs”). The EPA is required to issue technology-based national emissions standards for hazardous air pollutants (“NESHAPs”) to limit the release of specified HAPs from specific industrial sectors.

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Mercury and Air Toxics Standards

On December 21, 2011, the EPA issued the National Emission Standards for Hazardous Air Pollutants from Coal- and Oil-fired Electric Utility Steam Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric Utility, Industrial-Commercial-Institutional, and Small Industrial-Commercial-Institutional Steam Generating Units, otherwise known as the Mercury and Air Toxics Standards (“MATS”). These rules limit, for the first time, emissions of mercury, acid gases and other metals from coal and oil-fired power plants. We are not directly affected by the rule because it does not apply to natural gas-fired units, peaker units or units that use fuel oil as a backup fuel. We believe that the proposed emission standards are sufficiently stringent to force coal units without emission controls to be retired or to install acid gas, mercury, and particulate matter controls by 2015, which could benefit our competitive position.

Cross-State Air Pollution Rule

On July 6, 2011, the EPA finalized rules to control interstate transportation of fine particulate matter (PM-2.5) and ozone. The Cross-State Air Pollution Rule (“CSAPR”) requires substantial emissions reductions of NOx and SO2 from electric generating units in 27 states primarily in the eastern U.S. The rule sets up three distinct cap-and-trade programs: annual NOx and SO2 trading programs to control fine particles, and a NOx trading program from May through September (the ozone season) to control ozone. Emission reductions were scheduled to take effect starting January 1, 2012 for SO2 and annual NOx reductions and May 1, 2012 for ozone season NOx reductions. Significant additional SO2 emission reductions in Group 1 states will be required in 2014. Compared to 2005, the EPA estimates that by 2014 this rule and other federal rules will lower power plant annual emissions in the CSAPR region by 6.4 million tons per year of SO2 (a 73% reduction) and 1.4 million tons per year of NOx (a 54% reduction). The rule established an unlimited intrastate and limited interstate trading program with allowances allocated to sources based on historic heat input but capped at maximum annual emissions from 2003 to 2010. At current capacity factors, Calpine will be allocated sufficient allowances; thus, CSAPR is not expected to have a material impact on our operations. We expect the overall impact of this rule to be a net positive to Calpine as the significant emission reductions require coal-fired electric generating units to either purchase allowances, switch to more expensive fuels, install air pollution controls, or reduce or discontinue operations.

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

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

CAIR and Multi-Pollutant Program

Pursuant to authority granted under the CAA, the EPA promulgated the Clean Air Interstate Rule, or CAIR, regulations in March 2005, applicable to 28 eastern states and the District of Columbia, to facilitate attainment of its ozone and fine particulates NAAQS issued in 1997. CAIR’s goal is to reduce SO2 emissions in these states by over 70%, and NOX emissions by over 60% from 2003 levels by 2015. CAIR established annual cap-and-trade programs for SO2 and NOX as well as a seasonal program for NOX. On July 11, 2008, a panel of the U.S. Court of Appeals for the D.C. Circuit invalidated CAIR, stating that the “EPA’s approach – region-wide caps with no state specific quantitative contribution determinations or emission requirements – is fundamentally flawed.” The court did not overturn the existing cap-and-trade program for SO2 reductions under the Acid Rain Program or the existing ozone season cap-and-trade program under the NOX State Implementation Plan Call. On September 25, 2008, the EPA petitioned the court for rehearing. On December 23, 2008, the court remanded CAIR without vacatur for the EPA to conduct further proceedings consistent with the July 11, 2008 opinion. As a result of the court’s decision, CAIR was left intact and went into effect as planned on January 1, 2009, for many of our power plants located throughout the eastern and central U.S. Due to favorable

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allowance allocations, particularly in Texas, we have a net surplus of annual NOX allowances and the net financial impact of the program to our operations is positive. As part of the stay of CSAPR, the DC Circuit reinstated CAIR for the 2012 compliance year.

GHG Emissions

On April 2, 2007, the U.S. Supreme Court ruled that the EPA has the authority to regulate GHG emissions under the CAA. As a result of this ruling, the EPA is moving forward to regulate GHG emissions pursuant to its existing authority under the CAA. On December 7, 2009, the EPA made an “endangerment finding” with respect to GHGs, determining that current and projected concentrations of six key GHGs endanger the public health and welfare of current and future generations. As part of the EPA’s initiative to regulate GHGs, on May 13, 2010, the EPA finalized regulations referred to as the “Tailoring Rule” to require new sources emitting over 100,000 tons per year (a “major” source) of GHG emissions or modifications to existing major sources that would increase their GHG emissions by greater than 75,000 tons per year to undergo a major new source review (“NSR”). Beginning in January 2011, sources or modifications already required to obtain a prevention of significant deterioration (“PSD”) permit due to their emissions of conventional regulated pollutants were required to satisfy best available control technology (“BACT”) requirements for GHG as well. Beginning in July 2011, new sources and modifications exceeding the 100,000 and 75,000 tons per year thresholds, respectively, were required to obtain a PSD permit and satisfy BACT requirements for GHGs, regardless of their emissions of any conventional pollutants. The EPA has issued guidance to permitting authorities on the implementation of GHG BACT that focuses on energy efficiency, but requires consideration of carbon capture and storage (“CCS”) as available technology for high-emitting industries, although the EPA acknowledges that CCS may be eliminated as technically infeasible or excessively costly at this time. We believe that the impact of the final Tailoring Rule will be neutral to us because we expect that our efficient power plants would be found to meet BACT for GHGs if required to undergo PSD review.

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

Fees on Permissible Emissions

Section 185 of the CAA requires major stationary sources of NOX and volatile organic compounds (“VOCs”), such as power plants and refineries, in areas that fail to attain the NAAQS for ozone by the attainment date to pay a fee to the state or in the absence of state action, the EPA. The fee was set by Congress in the CAA at $5,000 per ton of NOX or VOC (adjusted for inflation or approximately $9,000 per ton in 2011) and is payable on emissions that exceed 80% of each individual power plant’s baseline emissions, which were established in the year before the attainment date; however, the EPA is considering alternative baseline calculations. The fee will remain in effect until the designated area achieves attainment. We operate 13 power plants that are located within designated nonattainment areas in Texas, New York, and New Jersey, which are subject to this fee. On January 5, 2010, the EPA issued guidance on developing fee programs required under Section 185 of the CAA. Texas issued a draft rulemaking to collect the fees in late 2009; however, Texas inactivated the proposed rulemaking in 2010. We estimate that compliance with this fee could result in additional costs of approximately $2 million to $4 million on an annual basis and our financial statements include accruals for our estimated Section 185 fees. Our estimate is dependent upon a number of factors that could change in the future dependent upon, among other things: implementation by the states of guidance from the EPA, state rulemakings, the designation of nonattainment status, our number of power plants located in these areas and our level of NOX emissions.

Acid Rain Program

As a result of the 1990 CAA amendments, the EPA established a cap-and-trade program for SO2 emissions from power plants throughout the U.S. Starting with Phase II of the program in 2000, a permanent ceiling (or cap) was set at 10 million tons per year, declining to 8.95 million tons per year by 2010. The EPA allocated SO2 allowances to power plants. Each allowance permits a unit to emit one ton of SO2 during or after a specified year, and allowances may be bought, sold or banked. All but a small percentage of allowances were allocated to power plants placed into service before 1990. Our Edge Moor and Deepwater power plants currently receive sufficient free SO2 allowances; therefore, we will have no compliance expense for this program.

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Regional and State Air Emissions Activities

Several states and regional organizations are developing, or already have developed, state-specific or regional initiatives to reduce GHG emissions through mandatory programs. The most advanced programs include the RGGI in the northeast states and California’s implementation of its own GHG policy pursuant to AB 32, including its RPS. The evolution of these programs could have a material impact on our business.

California: GHG (AB 32)

California's AB 32 creates a statewide cap on GHG emissions and requires the state to return to 1990 emission levels by 2020. On October 20, 2011, the CARB adopted final cap-and-trade and mandatory reporting regulations which were approved by the Office of Administrative Law on December 15, 2011. The regulations took effect on January 1, 2012 and CARB has begun to implement the program. The first compliance year when covered sources, including Calpine, will have to turn in allowances has been moved from 2012 to 2013; however, CARB is implementing other requirements of the regulation including registering covered entities, putting in place and testing the necessary infrastructure, and conducting two auctions in August and November of 2012. Litigation challenging the implementation of CARB's AB 32 Scoping Plan has been resolved and there are currently no challenges to the Scoping Plan or the cap-and-trade regulations. However, we cannot predict whether there will be new legal challenges filed against the regulation or what the associated impacts of any such litigation would be. A number of parties continue to seek further refinements to improve the regulation. Concurrent with the adoption of the regulations, on October 20, 2011, CARB also adopted Resolution 11-32 outlining the issues it will continue to address including, but not limited to, issues raised by Calpine on the market's auction purchase and holding limit rules and issues involving long-term contracts executed prior to AB 32. CARB has recently announced that it will consider these issues in two new rulemakings in the second and fourth quarters of 2012. Overall, we support AB 32 and believe we are favorably positioned to comply with these regulations.

Northeast and Mid-Atlantic: CO2 (RGGI)

On January 1, 2009, ten northeast and Mid-Atlantic states implemented a cap-and-trade program, RGGI, that affects our power plants in Maine, New York, New Jersey and Delaware (together emitting about 3.9 million tons of CO2 annually). In 2011, New Jersey announced that it will withdraw from the RGGI program effective for the compliance year 2012. RGGI caps regional CO2 emissions and requires generators to acquire one allowance for every ton of CO2 emitted over a three-year compliance period. Apart from state-specific set-asides and other factors, the vast majority of the region’s CO2 allowances are distributed to the market via public auction. RGGI auctions have recently cleared at the program’s floor price of $1.86 per ton. We are required to purchase allowances by buying them in RGGI public auctions or via the secondary market, or by investment in qualified offsets, to cover CO2 emissions from our power plants in the RGGI region. We have also received annual allocations from New York’s long-term contract set-aside pool to cover some of the CO2 emissions attributable to our PPAs at both the Kennedy International Airport Power Plant and Stony Brook Power Plant, and we received allowances for our power plants in Delaware pursuant to the state’s allowance allocation program. We do not anticipate any significant business impact from RGGI, given the efficiency of our power plants in RGGI states.

Texas: NOX

Pursuant to authority granted under the CAA, regulations adopted by the Texas Commission on Environmental Quality (“TCEQ”) to attain the one-hour and eight-hour NAAQS for ozone included the establishment of a cap-and-trade program for NOX emitted by power plants in the Houston/Galveston ozone nonattainment area. We own and operate seven power plants that participate in this program, all of which received free NOX allowances based on historical operating profiles. At this time, our Houston-area power plants have sufficient NOX allowances to meet forecasted obligations under the program.

New Jersey: NOX

New Jersey has enacted air regulations that limit the number of hours some of our New Jersey assets will be permitted to operate. These regulations will require future investment in emission controls on some of our units. Our 158 MW Deepwater power plant and certain of the New Jersey peaker power plants will need additional NOX controls to continue operating beyond May 1, 2015 under the regulations. We are currently evaluating the cost to comply with these air regulations and are uncertain of the impact to our financial position or results of operations.

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Other

Other states where our power plants are located may implement state or regional CO2 compliance requirements. The Western Climate Initiative, launched in February 2007, is a collaboration of seven U.S. Governors and four Canadian Premiers to reduce GHG emissions and could affect our power plants in California, Arizona, Oregon and Ontario. The Western Climate Initiative’s goal is to establish a multi-sector cap-and-trade program effective for most sectors of the economy by 2012 and regulation of the transportation sector by 2015. Some partner states, such as Arizona, have indicated their participation will be delayed or dependent on further economic analysis and recovery. To date, California and Quebec are the only members that have reaffirmed their commitment to participate in the Western Climate Initiative, with both committing to begin cap-and-trade in 2013.

Renewable Portfolio Standards

Policymakers have been considering variations of an RPS at the federal and state level. Generally, an RPS requires each retail seller of electricity to include in its resource portfolio (the resources procured by the retail seller to supply its retail customers) a certain amount of power generated from renewable or clean energy resources by a certain date.

Federal RPS

Although there is currently no national RPS, President Obama has stated his goal is to have 80% of the nation’s electricity provided from clean energy resources, which includes natural gas resources, by 2035, and some U.S. Congressional leaders have continued to press for a national renewable or clean energy standard in this Congress. It is too early to determine whether or not the enactment of a national RPS will have a positive or negative impact on us. Depending on the RPS structure, an RPS could enhance the value of our existing Geysers Assets. However, an RPS would likely initially drive up the number of wind and solar resources, which could negatively impact the dispatch of our natural gas assets, primarily in Texas and California. Conversely, our natural gas power plants could benefit by providing complementary/back-up service for these intermittent renewable resources or by being included in a clean energy standard.

California RPS

On April 12, 2011, California's governor signed into law legislation establishing a new and higher RPS. The new law requires implementation of a 33% RPS by 2020, with intermediate targets between now and 2020. The previous RPS legislation required certain retail power providers to generate or procure 20% of the power they sell to retail customers from renewable resources beginning in 2010. The new standard applies to all load-serving entities, including entities such as large municipal utilities that are not CPUC-jurisdictional. Under the new law, there are limits on different "buckets" of procurement that can be used to satisfy the RPS. Load-serving entities must satisfy at least a fraction of their compliance obligations with renewable power from resources located in California or delivered into California within the hour. Similarly, the legislation places limits on the use of “firmed and shaped” transactions and unbundled RECs - claims to the renewable aspect of the power produced by a renewable resource that can be traded separately from the underlying power. In general, the ability to use “firmed and shaped” transactions and unbundled RECs becomes more limited over the course of the implementation period. On December 1, 2011, the CPUC issued a decision on intermediate RPS procurement targets between the present and 2020. On December 15, 2011 the CPUC issued a decision clarifying exactly what transactions will fall into which bucket. Important additional details of the implementation of the 33% RPS are the subject of ongoing regulatory proceedings at both the CPUC and the California Energy Commission.

Other

A number of additional states have an RPS in place. Existing state-specific RPS requirements may change due to regulatory and/or legislative initiatives, and other states may consider implementing enforceable RPS in the future.

Other Environmental Regulations

In addition to air emissions, our power plants and the equipment necessary to support them are subject to other extensive federal, state and local laws and regulations adopted for the protection of the environment and to regulate land use. The laws and regulations applicable to us primarily involve the discharge of emissions into the water and the use of water, but can also include wetlands preservation, endangered species, hazardous materials handling and disposal, waste disposal and noise regulations. Noncompliance with environmental laws and regulations can result in the imposition of civil or criminal fines or penalties. In some instances, environmental laws may also impose clean-up or other remedial obligations in the event of a release of pollutants or contaminants into the environment. The following federal laws are among the more significant environmental laws that apply to us. In most cases, analogous state laws also exist that may impose similar and, in some cases, more stringent requirements on us than those discussed below. Our general policy with respect to these laws attempts to take advantage of our relatively clean portfolio of power plants as compared to our competitors.

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Clean Water Act

The federal Clean Water Act establishes rules regulating the discharge of pollutants into waters of the U.S. We are required to obtain wastewater and storm water discharge permits for wastewater and runoff, respectively, for certain of our power plants. We are required to maintain a spill prevention control and countermeasure plan with respect to certain of our natural gas power plants. We believe that we are in material compliance with applicable discharge requirements of the federal Clean Water Act.

Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of cooling water intake structures reflect the best technology available for minimizing adverse environmental impact. On March 28, 2011, the EPA proposed rules (the “Water Intake Rule”) that would allow states to require power plants employing older once-through cooling systems, particularly along biologically productive estuaries and rivers, to undertake major modifications to their cooling water intake structures or even install cooling towers to reduce impingement (where fish and other aquatic life get trapped against the intake screens) and entrainment (where small aquatic life passes through the intake screens and goes through the condenser at high temperatures). While these rules will likely affect our competitors, we do not expect these rules to have a material impact on our operations because we have only two peaking power plants that employ once-through cooling.

In California, the EPA delegates the implementation of 316(b) to the California State Water Resources Control Board (“SWRCB”). SWRCB has promulgated its own once-through cooling policy that established a schedule for once-through cooling units to install cooling towers or reduce entrainment and impingement to comparable levels as would be achieved with a cooling tower, or be retired. The compliance dates for approximately 12,000 MW of once-through cooling capacity in California occur between now and 2020.

Safe Drinking Water Act

Part C of the Safe Drinking Water Act establishes the underground injection control program that regulates the disposal of wastes by means of deep well injection. Although geothermal production wells, which are wells that bring steam to the surface, are exempt under the Energy Policy Act of 2005 (“EPAct 2005”), we use geothermal re-injection wells to inject reclaimed wastewater back into the steam reservoir, which are subject to this regulation. We believe that we are in material compliance with Part C of this Act.

Resource Conservation and Recovery Act

The Resource Conservation and Recovery Act (“RCRA”), regulates the management of solid and hazardous waste. With respect to our solid waste disposal practices at our power plants and steam fields located in The Geysers region of northern California, we are also subject to certain solid waste requirements under applicable California laws. We believe that our operations are in material compliance with RCRA and all such laws.

On June 21, 2010, the EPA proposed rules to regulate coal combustion residuals (“CCRs”) under RCRA. The EPA seeks to establish more stringent dam safety requirements to enhance performance of CCRs managed in surface impoundments. The EPA also seeks to regulate disposal of CCRs and has proposed to either regulate them as hazardous waste under Subtitle C of RCRA, or as nonhazardous waste under Subtitle D of RCRA. Both options will impose additional waste management costs on our competitors who rely on coal as a fuel. The EPA estimates a net present value cost of $3 billion to $21 billion to coal plants. We do not use coal so these rules will have no direct impact on us.

Comprehensive Environmental Response, Compensation and Liability Act

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also referred to as the Superfund, requires cleanup of sites from which there has been a release or threatened release of hazardous substances, and authorizes the EPA to take any necessary response action at Superfund sites, including ordering potentially responsible parties liable for the release to pay for such actions. Potentially responsible parties are broadly defined under CERCLA to include past and present owners and operators of, as well as generators of, wastes sent to a site. As of the filing of this Report, we are not subject to any material liability for any Superfund matters. However, we generate certain wastes, including hazardous wastes, and send certain of our wastes to third party waste disposal sites. As a result, there can be no assurance that we will not incur a liability under CERCLA in the future.

New Jersey Environmental Programs

New Jersey has a program mandating the cleanup of sites where there has been a release of a hazardous substance. As part of the Conectiv Acquisition on July 1, 2010, we assumed environmental remediation liabilities related to certain of the assets located in New Jersey that are subject to the ISRA. We have accrued or paid $10 million related to these liabilities at December 31, 2011. Pursuant to the Conectiv Purchase Agreement, PHI is responsible for any amounts that exceed $10 million associated with

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New Jersey environmental remediation liabilities. Our accrual is included in our allocation of the Conectiv Acquisition purchase price. See Note 3 of the Notes to Consolidated Financial Statements for disclosures related to our Conectiv Acquisition.

Federal Litigation on Liability for Air Emissions

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

On September 21, 2009, the Second Circuit issued a ruling in State of Connecticut, et al. v. American Electric Power Company Inc., et al., reversing a lower court's dismissal of two public nuisance claims filed by various states, municipalities and private entities against operators of coal-fired power plants. Plaintiffs argued that the power plant defendants contribute to global warming by emitting 650 million tons of CO2 per year and these emissions are causing and will continue to cause serious harm affecting human health and natural resources. The lower court held that plaintiffs' claims presented a non-legal political question and dismissed the complaints. The Second Circuit vacated the lower court's decision, ruling in favor of the plaintiffs. The Second Circuit's decision was appealed to the U.S. Supreme Court. On June 20, 2011, the Supreme Court issued a decision rejecting the plaintiffs' federal common law claim. The Court found that even if a federal common law claim could be made by plaintiffs, the CAA essentially “displaced” that claim. The case was remanded to the Second Circuit for further consideration of other issues in the case, including whether the plaintiffs may raise their claims under state common law or whether those claims are also preempted by federal law. The Second Circuit remanded to the district court for additional fact-finding. On December 6, 2011, the case was voluntarily dismissed. We cannot predict what impact the precedent of this case could have on our business.

The Supreme Court’s decision in the above matter is expected to have consequences for other climate change cases that are in the Fourth, Fifth, and Ninth Circuit courts of appeal, including Native Village of Kivalina v. ExxonMobil. In Kivalina, a federal district court in California sided with the defendants, 24 oil, energy and utility companies, against the Village of Kivalina, a small, self-governing tribe of Inupiat people who reside north of the Arctic Circle. The residents of Kivalina had sued the defendants for damages under federal nuisance law arguing that, as a result of global warming, Kivalina is subject to coastal storm waves and surges. On September 30, 2009, the court ruled in favor of the defendants finding that the plaintiff’s global warming claim was based upon the emission of GHGs from innumerable sources located throughout the world affecting the entire planet and its atmosphere and that no federal standards limit the discharge of GHGs. Kivalina is currently on appeal to the Ninth Circuit court. A three-judge panel of the Ninth Circuit heard oral arguments on November 28, 2011. We cannot predict the outcome of this case or what impact the precedent of this case could have on our business.

Power and Natural Gas Matters

Federal Regulation of Power

FERC Jurisdiction

Electric utilities have been highly regulated by the federal government since the 1930s, principally under the Federal Power Act (“FPA”), and the U.S. Public Utility Holding Company Act of 1935. These statutes have been amended and supplemented by subsequent legislation, including PURPA, EPAct 2005, and PUHCA 2005. These particular statutes and regulations are discussed in more detail below.

The FPA grants the federal government broad authority over electric utilities and independent power producers, and vests its authority in FERC. Unless otherwise exempt, any person that owns or operates facilities used for the wholesale sale or transmission of power in interstate commerce is a public utility subject to FERC’s jurisdiction. FERC governs, among other things, the disposition of certain utility property, the issuance of securities by public utilities, the rates, the terms and conditions for the transmission or wholesale sale of power in interstate commerce, the interlocking directorates, and the uniform system of accounts and reporting requirements for public utilities.

The majority of our power plants are subject to FERC’s jurisdiction; however, certain power plants qualify for available exemptions. FERC’s jurisdiction over EWGs under the FPA applies to the majority of our power plants because they are EWGs or are owned by EWGs, except our EWGs located in ERCOT. Power plants located in ERCOT are exempt from many FERC regulations under the FPA. Many of our power plants that are not EWGs are operated as QFs under PURPA. Several of our affiliates have been granted authority to engage in sales at market-based rates and blanket authority to issue securities, and have also been granted certain waivers of FERC reporting and accounting regulations available to non-traditional public utilities; however, we cannot assure that such authorities or waivers will not be revoked for these affiliates or will be granted in the future to other affiliates.

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FERC has the right to review books and records of “holding companies,” as defined in PUHCA 2005, that are determined by FERC to be relevant to the companies’ respective FERC-jurisdictional rates. We are considered a holding company, as defined in PUHCA 2005, by virtue of our control of the outstanding voting securities of our subsidiaries that own or operate power plants used for the generation of power for sale, or that are themselves holding companies. However, we are exempt from FERC’s books and records inspection rights pursuant to one of the limited exemptions under PUHCA 2005 as we are a holding company due solely to our owning one or more QFs, EWGs and Foreign Utility Companies (“FUCOs”). If any of our entities were not a QF, EWG or FUCO, then we and our holding company subsidiaries would be subject to the books and records access requirement.

FERC’s policies and rules will continue to evolve, and FERC may amend or revise them, or may introduce new policies or rules in the future. The impact of such policies and rules on our business is uncertain and cannot be predicted at this time.

FERC Regulation of Market-Based Rates

Under the FPA and FERC’s regulations, the wholesale sale of power at market-based or cost-based rates requires that the seller have authorization issued by FERC to sell power at wholesale pursuant to a FERC-accepted rate schedule. FERC grants market-based rate authorization based on several criteria, including a showing that the seller and its affiliates lack market power in generation and transmission, that the seller and its affiliates cannot erect other barriers to market entry and that there is no opportunity for abusive transactions involving regulated affiliates of the seller. All of our affiliates that own domestic power plants, except for certain of those power plants that are QFs under PURPA or that are located in ERCOT, as well as our market-based rate companies, are currently authorized by FERC to make wholesale sales of power at market-based rates.

Market-based rate authorization could possibly be revoked for any of our market-based rate companies if they fail to continue to satisfy FERC’s current or future criteria, or if FERC eliminates or restricts the ability of wholesale sellers of power to make sales at market-based rates. If market-based rate authority were revoked or restricted, affected power plants could be required to make wholesale sales of power based on cost-of-service rates, which could negatively impact their revenues.

FERC’s regulations specifically prohibit the manipulation of the power markets by making it unlawful for any entity in connection with the purchase or sale of power, or the purchase or sale of power transmission service under FERC’s jurisdiction, to engage in fraudulent or deceptive practices.

To ward against market manipulation, FERC requires us and other sellers making sales pursuant to their market-based rate authority to file certain reports, including quarterly reports of contract and transaction data, notices of any change in status and triennial updated market power analyses. If a seller does not timely file these reports or notices, FERC can revoke the seller’s market-based rate authority. FERC’s regulations also contain four market behavior rules that apply to sellers with market-based rate authority. These rules address such matters as compliance with organized RTO or ISO market rules, communication of accurate information, price reporting to publishers of power or natural gas price indices, and record retention. Failure to comply with these regulations can lead to sanctions by FERC, including penalties and suspension or revocation of market-based rate authority.

FERC Regulation of Transfers of Jurisdictional Facilities

Dispositions of our jurisdictional facilities or certain types of financing arrangements may require prior FERC approval, which could result in revised terms or impose additional costs, or cause a transaction to be delayed or terminated. Pursuant to Section 203 of the FPA, as amended by EPAct 2005, a public utility must obtain authorization from FERC before the public utility is permitted to: sell, lease or dispose of FERC-jurisdictional facilities with a value in excess of $10 million; merge or consolidate facilities with those of another entity; or acquire any security or securities with a value in excess of $10 million issued by another public utility. FERC’s prior approval is also required for transactions involving certain transfers of existing generation facilities and certain holding companies’ acquisitions of facilities with a value in excess of $10 million. FERC’s regulations implementing Section 203 of the FPA provide blanket authorizations for certain types of transactions, including acquisitions by holding companies that are holding companies solely due to their ownership, directly or indirectly, of one or more QFs, EWGs and FUCOs, to acquire additional QFs, EWGs or FUCOs, or the securities of additional QFs, EWGs and FUCOs without prior FERC approval.

FERC Regulation of Qualifying Facilities

Cogeneration and certain small power production facilities are eligible to be QFs under PURPA, provided that they meet certain power and thermal energy production requirements, and efficiency standards. QF status provides an exemption from PUHCA 2005 and grants certain other benefits to the QF, including, in some cases, the right to sell power to utilities at the utilities’ avoided cost (“PURPA put”). Certain types of sales by QFs are also exempt from FERC regulation of wholesale sales of the QFs’ power output. QFs are also exempt from most state laws and regulations. To be a QF, a cogeneration power plant must produce power and useful thermal energy for an industrial or commercial process, or heating or cooling applications in certain proportions to the power plant’s total energy output, and must meet certain efficiency standards.

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An electric utility may be relieved of the mandatory purchase obligation under the PURPA put if FERC determines that such QFs have access to a competitive wholesale power market.

Station Power Ruling

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

FERC Credit Reforms in Organized Wholesale Electric Markets

In October 2010, FERC issued a final rule regarding credit reforms in the organized wholesale electric markets. The reforms include shortening the settlement timeframes, restricting or eliminating the use of unsecured credit, clarifying the ability to offset market obligations, establishing minimum criteria for market participation, and establishing and clarifying when an ISO or RTO may require additional collateral from market participants for a material adverse change. ISO and RTO compliance filings were submitted in June 2011. Many of the credit rules took effect on October 1, 2011, with additional requirements being developed by the ISOs and RTOs. The credit rules and procedures for each ISO and RTO differ in requirements and compliance obligations. We continue to work to enhance uniformity and compliance obligations among the ISOs and RTOs, but we do not believe these changes to FERC's credit rules will have a material impact on our business.

FERC Enforcement Authority

FERC has civil penalty authority over violations of any provision of Part II of the FPA, as well as any rule or order issued thereunder. FERC is authorized to assess a maximum civil penalty of $1 million per violation for each day that the violation continues. The FPA also provides for the assessment of criminal fines and imprisonment for violations under Part II of the FPA. This penalty authority was enhanced in EPAct 2005. With this expanded enforcement authority, violations of the FPA and FERC’s regulations could potentially have more serious consequences than in the past.

NERC Compliance Requirements

Pursuant to EPAct 2005, NERC has been certified by FERC as the Electric Reliability Organization to develop and oversee the enforcement of electric system reliability standards applicable throughout the U.S., which are subject to FERC review and approval. FERC-approved reliability standards may be enforced by FERC independently, or, alternatively, by the Electric Reliability Organization and regional reliability organizations with frontline responsibility for auditing, investigating and otherwise ensuring compliance with reliability standards, subject to FERC oversight. Monetary penalties of up to $1 million per day per violation may be assessed for violations of the reliability standards. Certain electric reliability standards which apply to us as a generator owner, generator operator or marketer of power (purchasing and selling entity) are effective and mandatory. In addition, the regional reliability organizations have the ability to formulate supplemental reliability standards to apply in their specific regions, which may be more stringent than the NERC reliability standards. We comply with different reliability standards, requirements and procedural rules in each region in which we operate. It is expected that additional or modified NERC and regional reliability standards will be approved by FERC in the coming years, requiring us to take additional steps to remain fully compliant.

Regional and State Regulation of Power

The following summaries of the regional rules and regulations affecting our business focus on the West, Texas and North because these are the regions in which we have the most significant portfolios of power plants. While we provide a brief overview of the primary regional rules and regulations affecting our power plants located in other regions of the country, we do not provide an in-depth discussion of these rules and regulations because our asset portfolio in those regions is not as significant. All power plant and MW data is reported as of December 31, 2011.

West

We have 24 natural gas-fired power plants, including 2 under construction, with the capacity to generate a total of 6,194 MW in the WECC NERC region, which extends from the Rocky Mountains westward. In addition, we own and operate 15 geothermal power plants located in northern California capable of producing a total of 725 MW. The majority of these power plants are located in California, in the CAISO region; however, we also own a power plant in Arizona and one in Oregon.

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CAISO is responsible for ensuring the safe and reliable operation of the transmission grid within California and providing open, nondiscriminatory transmission services. Pursuant to a FERC-approved tariff, CAISO has certain abilities to impose penalties on market participants for violations of its rules. CAISO maintains various markets for wholesale sales of power, differentiated by time and type of electrical service, into which our subsidiaries may sell power from time to time. These markets are subject to various controls, such as price caps and mitigation of bids when transmission constraints arise. The controls and the markets themselves are subject to regulatory change at any time. CAISO runs integrated day-ahead and real-time markets for energy and ancillary services. The energy markets include centralized, day-ahead and real-time markets for energy, a nodal transmission congestion management model that results in locational marginal pricing at each generation location, financial congestion hedging instruments, a centralized day-ahead commitment process and an energy bid cap of $1,000 per MWh. The locational marginal pricing market design is intended to reward and encourage generation resources on favorable grid locations, such as some of the locations of our power plants.

Our Sutter power plant, which is a 578 MW combined-cycle natural gas-fired power plant, has no contracts for its output in 2012. In late 2011, we determined that the power plant will be uneconomic and may have to be shut down absent incremental compensation. Consequently, on November 22, 2011, we submitted a request to the CAISO to compensate our Sutter power plant under a provision of CAISO's current tariff that is intended to avoid retirement of needed generating units. This tariff provision, the Capacity Procurement Mechanism (“CPM”), allows the CAISO to compensate assets that are needed in the future, but are not currently receiving sufficient revenues to sustain operation. Upon review of our request, the CAISO determined we had met all of the requirements for such compensation. However, the CAISO also determined that the need for our Sutter power plant cannot be demonstrated in the following year (as required by the current tariff), but some time later. On January 26, 2012, the CAISO submitted a request to FERC seeking a narrow waiver of its tariff to allow such designation and compensation for our Sutter power plant. In parallel, we submitted a notice to the CPUC indicating that the operational status of our Sutter power plant may change. In a separate action, the CPUC has issued a draft resolution directing the state-jurisdictional load serving entities to enter into contracts sufficient to preserve our Sutter power plant through 2012. The resolution will be considered at the February 15, 2012 CPUC meeting. The outcome of these proceedings is uncertain at this time.

A recently implemented CPUC settlement changes significant aspects of policy towards California QFs, including our non-renewable QF facilities. The settlement resolves issues related to QFs under existing QF contracts. Most existing California QFs are under QF contracts. The settlement establishes new energy pricing options for QFs under QF contracts, including the option to shed QF host and efficiency obligations and become dispatchable, and specifies mechanisms for the California IOUs to procure both existing combined heat and power (“CHP”) that is not otherwise under contract and new CHP. Pursuant to the QF Settlement, we have converted one of our former QFs to a dispatchable non-QF unit and are exploring similar opportunities for some of our other California QFs. In addition, we plan to participate in the IOUs’ upcoming CHP solicitations.

Our power plants located outside of California either sell power into the markets administered by CAISO or sell power through bilateral transactions outside CAISO. Those transactions occurring outside CAISO are subject to FERC regulation and oversight, but they are not subject to CAISO rules and regulations.

Texas

We have 12 natural gas-fired power plants in the TRE NERC region with the capacity to generate a total of 7,239 MW, all of which are physically located in the ERCOT market. ERCOT is the ISO that manages approximately 85% of Texas’ load and an electric grid covering about 75% of the state, overseeing transactions associated with Texas’ competitive wholesale and retail power markets. FERC does not regulate wholesale sales of power in ERCOT. The PUCT exercises regulatory jurisdiction over the rates and services of any electric utility conducting business within Texas. Our subsidiaries that own power plants in Texas have power generation company status at the PUCT, and are either EWGs or QFs and are exempt from PUCT rate regulation. ERCOT ensures resource adequacy through an energy-only model rather than the capacity-based resource adequacy model that is more common among RTOs or ISOs in the Eastern Interconnect. In ERCOT, there is a market price cap for energy and capacity purchased by ERCOT. Under certain market conditions, the offer cap could be lower. Our subsidiaries are subject to the offer cap rules, but only for sales of power and capacity services to ERCOT.

ERCOT implemented a nodal market structure on December 1, 2010. A nodal market structure results in locational marginal pricing at each generation location rather than establishing pricing in four zones as was done prior to December 1, 2010.

The PUCT initiated a Resource and Reserve Adequacy and Shortage Pricing proceeding and held workshops during the summer of 2011 to examine the factors affecting ERCOT's annual planning reserve margins and the effects of the deployment of operating reserves on shortage pricing in the region's energy-only market design. The effect of the initiative thus far has been the establishment of price floors of $120/MWh for on-line non-spin and $180/MWh for off-line non-spin when contingency reserves are deployed. At the direction of the PUCT, stakeholders and ERCOT are considering additional changes which include a corresponding reduction in non-spinning reserve service and increase in responsive reserves, establishing a floor for reliability

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unit commitment units deployed for capacity and changing the slope and price cap for the power balance penalty curve. The PUCT requested action on these proposals by the end of the second quarter of 2012. If some or all of these changes are adopted, we expect more scarcity pricing opportunities, which should have a positive impact on our Commodity Margin.

The Sunset Review Process, implemented by the Texas Legislature in 1977, is the regular assessment of the need for a state agency to exist and to consider new and innovative changes to improve each agency’s operations and activities. The Sunset Review Process works by setting a date on which an agency will be abolished unless legislation is passed to continue its functions. The Sunset Review Process began in September 2009 for the PUCT and ERCOT and concluded in April 2010. The TCEQ and Texas Railroad Commission reviews began in April 2010 and were completed in December 2010. While significant changes were proposed at the Commission level, the legislation containing the proposed changes did not reach final passage during the 2011 legislative session. Therefore, another review of these agencies will begin and any resulting legislation will be considered in the 2013 legislative session.We cannot predict which changes, if any, will be placed into legislation and ultimately reach final passage. We will continue to participate in these processes where we anticipate an impact on our business; however, we do not expect such changes, if any, will have a material impact on our operations.

On July 17, 2008, the PUCT tentatively approved a transmission build plan, the Competitive Renewable Energy Zones, or CREZ, to expand the delivery of wind-generated power from western Texas to service approximately 18,500 MW of planned wind generation. Wind generation tends to supply more power during off-peak hours and shoulder months, and is unpredictable. If completed as currently approved, the impact of the transmission upgrades and associated wind generation on our Texas plants is unknown.

North

We have a total of 31 power plants with 7,914 MW of peaking capacity located in the RFC, NPCC and MRO NERC regions.

We have 19 operating power plants with the capacity to generate a total of 4,491 MW in Eastern PJM. In addition, we have one operating power plant, with the capacity to generate 503 MW, located in Western PJM. However, this power plant is partially committed to load in MISO. Eastern PJM and Western PJM are both located in the RFC NERC region. PJM operates wholesale power markets, a locationally based capacity market, a forward capacity market and ancillary service markets. PJM also performs transmission planning for the region.

Recently, certain states in the PJM market region have taken actions that could impact the PJM capacity market. In New Jersey, legislation enacted in 2011 required the New Jersey Board of Public Utilities (“BPU”) to issue a request for proposals ("RFP") for new generation. Market participants and others were concerned that awarding long-term contracts could impact the clearing prices of future PJM capacity auctions. The BPU has also initiated a proceeding and held hearings to investigate whether there is a need for New Jersey to pursue additional generation capacity beyond the 2,000 MW already contracted for pursuant to the legislation. Meanwhile, in response to a filing by PJM that was intended in part to address the negative implications from these state actions by revising the Minimum Offer Price Rule (“MOPR”) in its tariff, FERC issued an order on April 12, 2011 approving PJM's MOPR tariff changes. Also, on February 9, 2011, we joined a group of generators and utilities in filing a complaint in federal district court challenging the constitutionality of the New Jersey legislation. The court proceeding is continuing.

On September 29, 2011, the Maryland Public Service Commission (“MPSC”) issued a “Notice of Approval of Request for Proposals for New Generation to be Issued by Maryland Electric Distribution Companies.” The Notice required the state's IOUs to issue RFPs for up to 1,500 MW of capacity. The Notice specifies that proposals must be for new natural gas-fired capacity capable of delivery into the PJM Southwest Mid-Atlantic Area Council delivery area. The MPSC held a hearing on January 31, 2012 to determine whether new capacity is required, but it has not issued a final order in this proceeding.

We have a total of eight natural gas-fired power plants with the capacity to generate a total of 1,439 MW in the NPCC NERC region. Five of these power plants are located in New York. NYISO manages the transmission system in New York and operates the state’s wholesale power markets. NYISO manages both day-ahead and real-time energy markets using a locationally based marginal pricing mechanism that pays each generator the zonal marginally accepted bid price for the energy it produces.

Our remaining U.S.-based power plant in the NPCC NERC region is located in Maine. ISO-NE is the RTO for Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont. ISO-NE has broad authority over the day-to-day operation of the transmission system and operates a day-ahead and real-time wholesale energy market, a forward capacity market and ancillary services markets. ISO-NE also provides for regional transmission planning.

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We also have 50% ownership interests in two Canadian power plants, with the total capacity to generate 1,088 MW (544 MW net attributable to Calpine), located in the NPCC NERC region in Ontario, Canada. The Whitby cogeneration facility is a 50 MW facility located in Whitby, Ontario and the Greenfield Energy Centre is a 1,038 MW facility located in Courtright, Ontario. The Independent Electricity System Operator (“IESO”) of Ontario operates the Province’s wholesale power markets and directs the operation and ensures reliability of the IESO controlled grid. Hydro-One owns and operates the transmission system in Ontario, which is regulated by the Ontario Energy Board. Effective December 2009, the IESO of Ontario implemented several rule changes that impacted Greenfield LP's financial performance in 2010 and 2011 and will impact Greenfield LP in future years. Greenfield LP's power supply contract with the Ontario Power Authority provides it with a right to recover for financial consequences of market rule changes that negatively impact Greenfield LP; however, after extended negotiations to modify the agreement to address the financial impacts, Greenfield LP has initiated arbitration as provided for under the power supply contract to preserve its recovery rights. We continue to pursue arbitration of this matter and cannot predict at this time the outcome of arbitration, or the potential impact, if any, to our 50% partnership interest in Greenfield LP.

We have three natural gas-fired power plants with the capacity to generate a total of 1,481 MW operating within the MRO NERC region. MISO manages competitive locationally based wholesale day-ahead, real-time energy and ancillary services markets. MISO’s Resource Adequacy model requires load serving entities to account for capacity obligations under Module E of the MISO tariff. MISO currently conducts a monthly voluntary capacity auction to help purchasers find suppliers with capacity to meet their incremental capacity needs. In July 2011, MISO filed with FERC a proposal to re-design its current capacity market. Among other things, the proposed design would move MISO from a monthly capacity product to an annual capacity product, implement annual auctions, and make market participation mandatory for all load-serving entities as well as generators.

Southeast

We have one operating natural gas-fired power plant with the capacity to generate 1,134 MW located in the SPP NERC region. SPP is an RTO approved by FERC that provides independent administration of the electric power grid. SPP currently manages an energy-only location based real-time wholesale energy market. This market provides both nominal load-following and transmission constraint relief. In April 2011, the SPP board of directors voted to implement the market designs for a full suite of “Day 2” markets, including a day-ahead energy market, a financial transmission rights market, and ancillary service markets. The SPP staff and stakeholders have since entered into contracts with vendors to design the implementing elements and software to support this initiative. These new markets are scheduled to be implemented in March 2014.

We have ten natural gas-fired power plants with the capacity to generate a total of 4,949 MW operating within the SERC and the FRCC NERC regions. Opportunities to negotiate bilateral, individual contracts and long-term transactions with IOUs, municipalities and cooperatives exist within these regions. In addition to entering into bilateral transactions, there is a limited opportunity to sell into the short-term market. In the Entergy sub-region, SPP has been designated as the Independent Coordinator of Transmission. In this capacity, the Independent Coordinator of Transmission provides oversight of the Entergy transmission system.

Entergy and MISO continue to move forward with their proposal to transfer functional control of Entergy’s transmission system to MISO by December 2013. Last fall, Entergy filed change of control applications with the Arkansas Public Service Commission, the City of New Orleans, the Louisiana Public Service Commission, and the Mississippi Public Service Commission, but no concluding order has been issued by these regulatory bodies. Entergy is expected to, but has not made, a similar filing with the Public Utility Commission of Texas. We support Entergy membership in an RTO as soon as possible, with a preference for MISO. SPP continues to publicly oppose the Entergy to MISO proposal and asserts that Entergy should integrate its system with SPP.

Other State Regulation of Power

State Public Utility Commissions, or PUC(s), have historically had broad authority to regulate both the rates charged by, and the financial activities of, electric utilities operating in their states and to promulgate regulation for implementation of PURPA. Since all of our affiliates are either QFs or EWGs, none of our affiliates are currently subject to direct rate regulation by a state PUC. However, states may assert jurisdiction over the siting and construction of power generating facilities including QFs and EWGs and, with the exception of QFs, over the issuance of securities and the sale or other transfer of assets by these facilities. In Cal