CPN Calpine Corp.

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•	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;

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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.

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Item 1.	Business

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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.

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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.

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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:

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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.

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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.

•	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.

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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:

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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(1)	Data source is EIA

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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 SO 2 , NO X , 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, SO 2 , NO X , 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:

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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.

•	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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•	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.

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•	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.

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(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.

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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.

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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.

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Item 1A.	Risk Factors

•	increases and decreases in generation capacity in our markets, including the addition of new supplies of power as a result of the development of new power plants, expansion of existing power plants or additional transmission capacity;

•	changes in power transmission or fuel transportation capacity constraints or inefficiencies;

•	power supply disruptions, including power plant outages and transmission disruptions;

•	Heat Rate risk;

•	weather conditions;

•	quarterly and seasonal fluctuations;

•	risk associated with declining coal prices;

•	changes in the demand for power or in patterns of power usage, including the potential development of demand-side management tools and practices;

•	development of new fuels or new technologies for the production of power;

•	federal and state regulations and actions of the ISOs;

•	federal and state power, market and environmental regulation and legislation, including mandating an RPS or creating financial incentives, each resulting in new renewable energy generation capacity creating oversupply;

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•	changes in prices related to RECs; and

•	changes in capacity prices and capacity markets.

•	rate caps, price limitations and bidding rules imposed by ISOs, Regional Transmission Organizations and other market regulators that may impair our ability to recover our costs and limit our return on our capital investments;

•	regulations promulgated by the FERC and the CFTC;

•	some of our competitors (mainly utilities) receive entitlement-guaranteed rates of return on their capital investments, with returns that exceed market returns and may impact our ability to sell our power at economical rates;

•	structure and operating characteristics of our capacity markets such as our PJM capacity auctions and our NYISO markets; and

•	regulations and market rules related to our RECs.

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•	the cessation or abandonment of the development, construction, maintenance or operation of a power plant;

•	failure of a power plant to achieve construction milestones or commercial operation by agreed-upon deadlines;

•	failure of a power plant to achieve certain output or efficiency minimums;

•	our failure to make any of the payments owed to the counterparty or to establish, maintain, restore, extend the term of, or increase any required collateral;

•	failure of a power plant to obtain material permits and regulatory approvals by agreed-upon deadlines;

•	a material breach of a representation or warranty or our failure to observe, comply with or perform any other material obligation under the contract; or

•	events of liquidation, dissolution, insolvency or bankruptcy.

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•	necessary power generation equipment;

•	governmental permits and approvals including environmental permits and approvals;

•	fuel supply and transportation agreements;

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•	sufficient equity capital and debt financing;

•	power transmission agreements;

•	water supply and wastewater discharge agreements or permits; and

•	site agreements and construction contracts.

•	transportation may be unavailable if pipeline infrastructure is damaged or disabled;

•	pipeline tariff changes may adversely affect our ability to, or cost to, deliver natural gas and fuel oil supply;

•	third-party suppliers may default on natural gas supply obligations and we may be unable to replace supplies currently under contract;

•	market liquidity for physical natural gas and fuel oil or availability of natural gas and fuel oil services (e.g. storage) may be insufficient or available only at prices that are not acceptable to us;

•	natural gas and fuel oil quality variation may adversely affect our power plant operations;

•	our natural gas and fuel oil operations capability may be compromised due to various events such as natural disaster, loss of key personnel or loss of critical infrastructure;

•	fuel supplies diverted to residential heating for humanitarian reasons; and

•	any other reasons.

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•	the heat content of the extractable steam or fluids;

•	the geology of the reservoir;

•	the total amount of recoverable reserves;

•	operating expenses relating to the extraction of steam or fluids;

•	price levels relating to the extraction of steam, fluids or power generated; and

•	capital expenditure requirements relating primarily to the drilling of new wells.

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•	limiting our ability to borrow additional amounts for working capital, capital expenditures, debt service requirements, potential growth or other purposes;

•	limiting our ability to use operating cash flows in other areas of our business because we must dedicate a substantial portion of these funds to service our debt;

•	increasing our vulnerability to general adverse economic and industry conditions;

•	limiting our ability to capitalize on business opportunities, and to react to competitive pressures and adverse changes in governmental regulation;

•	limiting our ability or increasing the costs to refinance indebtedness or to repurchase equity issued by certain of our subsidiaries to third parties; and

•	limiting our ability to enter into marketing, hedging and optimization activities by reducing the number of counterparties with whom we can transact as well as the volume and type of those transactions.

•	low credit ratings may prevent us from obtaining any material amount of additional debt financing;

•	conditions in energy commodity markets;

•	regulatory developments;

•	credit availability from banks or other lenders for us and our industry peers;

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•	investor confidence in the industry and in us;

•	the continued reliable operation of our current power plants; and

•	provisions of tax, regulatory and securities laws that are conducive to raising capital.

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

•	enter into certain types of commodity hedge agreements that can be secured by first lien collateral;

•	enter into sale and leaseback transactions;

•	make certain investments;

•	create or incur liens;

•	consolidate or merge with or transfer all or substantially all of our assets to another entity, or allow substantially all of our subsidiaries to do so;

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

•	engage in certain business activities; and

•	enter into certain transactions with our affiliates.

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Item 1B.	Unresolved Staff Comments

Item 2.	Properties

Item 3.	Legal Proceedings

Item 4.	(Removed and Reserved)

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Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

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(1)	During 2007, we were released from a portion of our direct and indirect Canadian guarantee of the ULC I notes, ULC II notes and redundant Canadian claims and recorded a $4.1 billion credit for the reversal of these redundant claims.

(2)	Although earnings per share information for the year ended December 31, 2007 is presented, it is not comparable to the information presented for the years ended December 31, 2011, 2010, 2009 and 2008, due to the changes in our capital structure on the Effective Date, which also included termination of all outstanding convertible securities.

(3)	In connection with our emergence from Chapter 11, liabilities subject to compromise were either paid or reclassified to equity on the Effective Date.

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Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation s

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

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

•	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

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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.

•	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%.

•	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.

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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.

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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.

•	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.

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•	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.

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#	Variance of 100% or greater

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

(2)	Includes $8 million of contract amortization for the year ended December 31, 2011, related to a contract that became effective in 2011.

(3)	Includes $10 million and $9 million of RGGI compliance and other environmental costs for the years ended December 31, 2011 and 2010, respectively, which are components of Commodity Margin.

(4)	Represents generation and capacity from power plants that we both consolidate and operate. See “— Description of Our Power Plants – Table of Operating Power Plants and Projects Under Construction” for our total equity generation and capacities.

•	an increase in the North primarily due to the Conectiv Acquisition which closed on July 1, 2010, and our York Energy Center which achieved COD in March 2011; partially offset by

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

•	despite a higher contribution from hedges, commodity revenue, net of commodity expense decreased in the West primarily due to lower Spark Spreads resulting from a significant increase in hydroelectric generation in California in 2011 compared to 2010; and

•	a decrease in the Southeast primarily due to the expiration of certain hedge contracts which benefited the year ended December 31, 2010.

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#	Variance of 100% or greater

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

(2)	Includes $9 million and $5 million of RGGI compliance and other environmental costs for the years ended December 31, 2010 and 2009, respectively, which are components of Commodity Margin.

(3)	Represents generation and capacity from power plants that we both consolidate and operate. See “— Description of Our Power Plants – Table of Operating Power Plants and Projects Under Construction” for our total equity generation and capacities.

•	lower average hedge margins in 2010 compared to 2009;

•	lower realized Spark Spreads on open positions due to lower Market Heat Rates, primarily in California and Texas, attributable to weaker market conditions resulting from milder weather and increased hydroelectric generation in the West and an increase in installed generation capacity in California and Texas in 2010 compared to 2009; partially offset by

•	an increase in the North primarily due to the Conectiv Acquisition which closed on July 1, 2010.

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

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

(3)	Adjustments to reflect Adjusted EBITDA from unconsolidated investments include unrealized (gain) loss on mark-to-market activity of $1 million, $1 million and $(47) million for the years ended December 31, 2011 , 2010 and 2009 , respectively.

(4)	Includes $26 million included in sales, general and other administrative expense and $10 million included in plant operating expense.

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(1)	Includes $34 million and $6 million of margin deposits held by us posted by our counterparties at December 31, 2011 and 2010 , respectively.

(2)

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

(3)	Includes availability under our CDHI letter of credit facility. On January 10, 2012, we increased the CDHI letter of credit facility to $300 million and extended the maturity date to January 2, 2016.

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•	the level of Market Heat Rates;

•	our continued ability to successfully hedge our Commodity Margin;

•	the speed, strength and duration of an economic recovery;

•	maintaining acceptable availability levels for our fleet;

•	the impact of current and pending environmental regulations in the markets in which we participate;

•	improving the efficiency and profitability of our operations;

•	continued compliance with the covenants under our existing financing obligations, including our First Lien Notes, Term Loan, New Term Loan, Corporate Revolving Facility, CCFC and other debt obligations;

•	stabilizing and increasing future contractual cash flows; and

•	our significant counterparties performing under their contracts with us.

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(1)

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

(2)	On January 10, 2012, we increased the CDHI letter of credit facility to $300 million and extended the maturity date to January 2, 2016.

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

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

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

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

•	incur additional subordinated or junior secured debt; and

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

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•	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 (309MW) and the feasibility

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•	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.

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(1)	Consist of amounts to be drawn under our Russell City Project Debt and Los Esteros Project Debt.

•	Working capital — Working capital employed increased by approximately $194 million for the year ended December 31, 2011 compared to 2010 after adjusting for debt related balances and non-hedging interest rate swaps which did not impact cash provided by operating activities. The increase was primarily due to a reduction in margin requirements during the year ended December 31, 2010.

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•

Interest paid — Cash paid for interest, inclusive of interest rate swaps in hedging relationships, increased by $21 million to $656 million for the year ended December 31, 2011, as compared to $635 million for 2010. The increase was primarily due to timing of interest payments on the issuance of First Lien Notes, Term Loan and New Term Loan as compared to the previously outstanding First Lien Credit Facility and project debt.

•	Prepayment Premiums — For the year ended December 31, 2011, we paid $13 million of prepayment premiums related to the extinguishment of the NDH Project Debt.

•	Income from operations — Income from operations, adjusted for non-cash items increased by $41 million for the year ended December 31, 2011, as compared to 2010. Non-cash items consist primarily of depreciation and amortization, gains and losses on sales of assets, impairment losses, income and losses from unconsolidated investments and unrealized gains and losses in mark to market activity.

•	Purchase of Conectiv assets and BRSP — We purchased the Conectiv assets and BRSP for approximately $1.7 billion in 2010. There were no acquisitions in 2011.

•	Capital expenditures — Capital expenditures increased by $314 million primarily resulting from construction activity at the Russell City Energy Center, Los Esteros Critical Energy Facility and York Energy Center combined with our turbine upgrade program.

•

Lower proceeds from sales of power plants, interests and other — In the year ended December 31, 2011, we received proceeds of approximately $13 million from the disposal of other plant assets compared to proceeds of approximately $954 million primarily relating to the sale of Blue Spruce, Rocky Mountain and a 25% undivided interest in the assets of our Freestone power plant in the year ended December 31, 2010.

•	Settlement of non-hedging interest rate swaps — During the year ended December 31, 2011 we made payments on interest rate swap derivative instruments associated with swaps that formerly hedged variable rate debt which was converted to fixed rate debt of $189 million compared to payments of $69 million during the same period in 2010.

•	Restricted cash — The net decrease in restricted cash was $54 million for the year ended December 31, 2011, compared to $322 million for the same period in 2010. The decrease in restricted cash in 2011 as compared to 2010 was primarily due to the maturity of project debt and the corresponding reduction in restricted cash requirements.

•	Transmission credits — During the year ended December 31, 2011, we paid $31 million for transmission credits related to construction of our Russell City Energy Center.

•	Issuance of the Term Loan and New Term Loan — During the year ended December 31, 2011, we received proceeds of approximately $1.7 billion from the issuance of the Term Loan and New Term Loan. We used the proceeds to repay our NDH Project Debt of approximately $1.3 billion resulting in a net increase of $374 million.

•

Issuance of the First Lien Notes — We received proceeds of approximately $1.2 billion from the issuance of the 2023 First Lien Notes and used those proceeds to terminate the First Lien Credit Facility in accordance with its repayment terms resulting in a net increase of $5 million during the year ended December 30, 2011, compared to a net increase of $14 million during the year ended December 31, 2010.

•	Reduced proceeds from project debt — During the year ended December 31, 2011, we received proceeds of approximately $327 million related to our Russell City Project Debt and Los Esteros Project Debt. During 2010 we received proceeds of approximately $1.3 billion to fund the Conectiv acquisition.

•	Lower Repayments of Project Debt — During the year ended December 31, 2011, we made repayments on project debt of approximately $550 million, compared to approximately $937 million in the year ended December 31, 2010.

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•	Increased Contributions from noncontrolling interest holder — During the year ended December 31, 2011, we received proceeds of approximately $34 million from a noncontrolling interest holder in Russell City Energy Center, compared to contributions of approximately $17 million in the year ended December 31, 2010.

•	Decreased Finance Costs — During the year ended December 31, 2011, primarily due to the refinancing of the First Lien Credit Facility and the NDH Project Debt, we incurred $81 million in finance costs primarily related to the issuance of the First Lien Notes and project debt, compared to $136 million in finance costs primarily related to the issuance of the First Lien Notes and project debt.

•	Stock Repurchases — During the year ended December 31, 2011, we made payments of approximately $119 million under the share repurchase program announced on August 23, 2011. There were no similar repurchases during the same period in 2010.

•	Working capital — Working capital employed, after adjusting for debt related balances and derivative activities which did not impact cash provided by operating activities, decreased by approximately $188 million for the year ended December 31, 2010 compared to 2009. The decrease was primarily due to reduced Commodity Margin requirements.

•	Interest paid — Cash paid for interest, inclusive of interest rate swaps in hedging relationships, decreased by $126 million to $635 million for the year ended December 31, 2010, as compared to $761 million for 2009, primarily due to the timing of interest payments and the replacement of the First Lien Credit Facility with First Lien Notes at lower fixed interest rates.

•	Income from operations — Income from operations, adjusted for non-cash items decreased by $43 million for the year ended December 31, 2010, as compared to 2009. Non-cash items consist primarily of depreciation and amortization, gains and losses on sales of assets, impairment losses, income and losses from unconsolidated investments and unrealized gains and losses in mark to market activity.

•	Cash taxes — Net cash paid for taxes in 2010 was approximately $17 million compared to net cash received for taxes of approximately $37 million in 2009. In 2009, we received refunds from foreign tax jurisdictions with no such refunds in 2010.

•	Purchase of Conectiv assets and BRSP — We purchased the Conectiv assets and BRSP for approximately $1.7 billion in 2010. There were no acquisitions in 2009.

•	Capital expenditures — Capital expenditures increased by $190 million primarily resulting from construction activity at our York Energy Center and Russell City Energy Center combined with our Geysers Assets expansion activities.

•	Settlement of non-hedging interest rate swaps — In the year ended December 31, 2010 we paid $69 million on interest rate swap losses associated with swaps that formerly hedged the variable rate debt which was converted to fixed rate debt in the year. We made no similar payments in 2009.

•	Decrease in restricted cash — Restricted cash decreased $322 million in 2010 compared to a $59 million increase in 2009. The decrease was primarily due to releases of restrictions on cash resulting from the repayment of project debt.

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•	Sales of power plants, interests and other — We received proceeds of approximately $954 million from the sale of our 100% ownership interests in Blue Spruce and Rocky Mountain, combined with the sale of a 25% undivided interest in the assets of our Freestone power plant. We had no significant asset sales in 2009.

•	Issuance of the First Lien Notes — In the year ended December 31, 2010, we received proceeds of approximately $3.5 billion from the issuance of First Lien Notes. We used these proceeds to make repayments on the First Lien Credit Facility of approximately $3.4 billion resulting in a net increase of $50 million.

•

Lower Repayments on the First Lien Credit Facility — In the year ended December 31, 2010, we made regularly scheduled payments on the First Lien Credit Facility of approximately $36 million, a decrease of $24 million compared to payments of $60 million for the year ended December 31, 2009. Additionally, in the year ended December 31, 2009, we repaid $725 million on our First Lien Credit Facility revolver.

•	Increase in Project Debt — In the year ended December 31, 2010, we received proceeds of approximately $1.3 billion from project debt used to finance the Conectiv Acquisition, a $238 million increase compared to project debt issued in the year ended December 31, 2009, which was primarily due to the refinancing of CCFC.

•

Lower Repayments of Project Debt — In the year ended December 31, 2010, we made repayments on project debt of approximately $937 million, a decrease of $424 million compared to the prior year. The decrease is primarily due to the repayment of approximately $418 million related to the Blue Spruce and Rocky Mountain transaction in 2010, compared to approximately $1.1 billion of repayments related to the CCFC Refinancing in 2009. Additionally, we made higher payments of approximately $239 million on other project debt in the year ended December 31, 2010.

•

Increased Finance Costs — The increase in cash flows provided by financing activities was partially offset by an increase in finance costs of $71 million. In the year ended December 31, 2010, we incurred $136 million in finance costs primarily related to the issuance of the First Lien Notes and project debt, compared to $65 million incurred in 2009 to facilitate an amendment to the First Lien Credit Facility and to refinance other project debt.

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

(2)	The standby letters of credit disclosed above represent those disclosed in Note 6 of the Notes to Consolidated Financial Statements.

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

(4)	These are contingent off balance sheet obligations.

(5)	As of December 31, 2011, $4 million of cash collateral is outstanding related to these bonds.

(1)	Included in the total are future minimum payments for power plant, office and equipment and land and other operating leases. See Note 15 of the Notes to Consolidated Financial Statements for more information.

(2)	The amounts presented here include contracts for the purchase, transportation, or storage of commodities accounted for as executory contracts and therefore not recognized as liabilities on our Consolidated Balance Sheet.

(3)	The amounts presented here include water agreements, transmission agreements, parts supply agreements and other purchase obligations.

(4)	The amounts included above for purchase obligations represent the minimum requirements under contract.

(5)	A note payable totaling $49 million associated with the sale of the PG&E note receivable to a third party is excluded from debt for this purpose as it is a non-cash liability.

(6)	Amounts are projected based upon interest rates at December 31, 2011.

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(1)

Interest rate settlements consist of recognized losses from former interest rate cash flow hedges of $18 million that were de-designated as a result of the repayment of project debt in 2011, $69 million related to recognition of losses from settlements of designated cash flow hedges and $127 million in losses from settlements of undesignated interest rate swaps (represents a portion of interest expense and loss on interest rate derivatives as reported on our Consolidated Statements of Operations).

(2)

Gains on settlement of commodity contracts not designated as hedging instruments of $176 million (represents a portion of operating revenues and fuel and purchased energy expense as reported on our Consolidated Statements of Operations) and $27 million related to recognition of gains from cash flow hedges, previously reflected in OCI, partially offset by other changes in derivative assets and liabilities not reflected in OCI or net income.

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

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(1)	In addition to changes in market value on derivatives not designated as hedges, changes in unrealized gain (loss) also includes de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into income, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.

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•	credit approvals;

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

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

•	margin, collateral, or prepayment arrangements; and

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

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(1)	Projection based upon anticipated LIBOR rates.

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•	a contract that qualifies as a lease;

•	a derivative;

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

•	a contract that is a physical or executory contract.

•	power and steam revenue consisting of fixed and variable capacity payments, including capacity payments received from PJM capacity auctions which are not related to generation;

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

•	other service revenues.

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•	perform an ongoing reassessment each reporting period of whether we are the primary beneficiary of our VIEs; and

•

evaluate if an entity is a VIE and whether we are the primary beneficiary whenever any changes in facts and circumstances occur such that the holders of the equity investment at risk, as a group, lose the power from voting rights or similar rights of those investments to direct the activities of a VIE that most significantly impact the VIE's economic performance or when there are other changes in the powers held by individual variable interest holders.

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

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

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

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

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

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

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Item 7A.	Quantitative and Qualitative Disclosures about Market Risk

Item 8.	Financial Statements and Supplementary Data

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Item 9A.	Controls and Procedures

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•	pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

•	provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and

•	provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on our financial statements.

Item 9B.	Other Information

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Item 10.	Directors, Executive Officers and Corporate Governance

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Item 11.	Executive Compensation

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Item 13.	Certain Relationships and Related Transactions, and Director Independence

Item 14.	Principal Accounting Fees and Services

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Item 15.	Exhibits, Financial Statement Schedule

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*	Filed herewith.

‡	Furnished herewith.

†	Management contract or compensatory plan or arrangement.

**	Schedules omitted pursuant to Item 601(b)(2) of Regulation S-K. Calpine will furnish supplementally a copy of any omitted schedule to the SEC upon request.

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

***	XBRL (eXtensible Business Reporting Language) information is furnished, not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise is not subject to liability under those sections.

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(1)	Includes depreciation and amortization included in fuel and purchased energy expense, interest expense and discontinued operations on our Consolidated Statements of Operations.

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1.	Organization and Operations

2.	Summary of Significant Accounting Policies

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•	financial institutions and trading companies;

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

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

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(1)	At both December 31, 2011 and 2010 , debt service included approximately $ 25 million of repurchase agreements with a financial institution containing maturity dates greater than one year.

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

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

•	other service revenues.

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•	quantitative information about the unobservable inputs used in a fair value measurement that is categorized within level 3 of the fair value hierarchy;

•	for those fair value measurements categorized within level 3 of the fair value hierarchy, both the valuation processes used and the sensitivity of the fair value measurement to changes in unobservable inputs and the interrelationships between those unobservable inputs, if any; and

•	the categorization by level of the fair value hierarchy for items that are not measured at fair value in the statement of financial position but for which the fair value is required to be disclosed.

3.	Acquisitions, Divestitures and Discontinued Operations

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4.	Property, Plant and Equipment, Net

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5.	Variable Interest Entities and Unconsolidated Investments

•	perform an ongoing reassessment each reporting period of whether we are the primary beneficiary of our VIEs; and

•

evaluate if an entity is a VIE and whether we are the primary beneficiary whenever any changes in facts and circumstances occur such that the holders of the equity investment at risk, as a group, lose the power from voting rights or similar rights of those investments to direct the activities of a VIE that most significantly impact the VIE's economic performance or when there are other changes in the powers held by individual variable interest holders.

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(1)	OMEC was consolidated effective January 1, 2010. See Note 2.

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6.	Debt

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

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

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

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

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

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

•	incur or guarantee additional first lien indebtedness;

•	enter into certain types of commodity hedge agreements that can be secured by first lien collateral;

•	enter into sale and leaseback transactions;

•	create or incur liens; and

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

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

(2)	Represents a sale-leaseback transaction that is accounted for as financing transaction under U.S. GAAP.

(3)	Represents a weighted average of first and second lien loans for the weighted average effective interest rates.

(4)	On June 17, 2011 , we repaid Metcalf and Deer Park project debt with the proceeds received from $ 360 million in borrowings under the New Term Loan as further described above.

(5)	The Whitby Holdings debt was purchased from a third party in 2011.

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(1)	Amounts are accounted for as financing transactions under U.S. GAAP and are included in our project financing, notes payable and other amounts above.

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(1)

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

(2)	On January 10, 2012, we increased the CDHI letter of credit facility to $300 million and extended the maturity date to January 2, 2016.

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

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

7.	Assets and Liabilities with Recurring Fair Value Measurements

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(1)	As of December 31, 2011 and 2010 , we had cash equivalents of $1,249 million and $1,094 million included in cash and cash equivalents and $166 million and $203 million included in restricted cash, respectively.

(2)	Includes OTC swaps and options.

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

(2)	For natural gas contracts, swaps and options, included on our Consolidated Statements of Operations.

(3)	We transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no significant transfers into/out of level 1 during the years ended December 31, 2011 , 2010 and 2009 .

(4)	We had $2 million in losses transferred out of level 2 into level 3 for the year ended December 31, 2011, due to changes in market liquidity in various power and natural gas markets.There were no significant transfers into level 3 for the years ended December 31, 2010 and 2009 .

(5)	There were no significant transfers out of level 3 for the year ended 2011. We had $3 million in losses and $(34) million in (gains) transferred out of level 3 into level 2 for the years ended December 31, 2010 and 2009 , respectively, due to changes in market liquidity in various power markets.

8.	Derivative Instruments

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

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(1)	In addition to changes in market value on derivatives not designated as hedges, changes in unrealized gain (loss) also includes de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into income, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.

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

(2)	Cumulative cash flow hedge losses, net of tax, remaining in AOCI were $172 million and $122 million at December 31, 2011 and 2010 , respectively. Our other components of AOCI were not material at December 31, 2011 and 2010.

(3)

Reclassification of losses from OCI to earnings consisted of $32 million in losses from the reclassification of interest rate contracts due to settlement, $15 million in losses from terminated interest rate contracts due to the repayment of project debt in 2011, and $91 million in losses from existing interest rate contracts reclassified from OCI into earnings due to the refinancing of variable rate First Lien Credit Facility term loans.

(4)	Reclassification of losses from OCI to earnings consisted of $183 million in losses from the reclassification of interest rate contracts due to settlement and $206 million in losses from interest rate contracts reclassified from OCI into earnings due to the refinancing of variable rate First Lien Credit Facility term loans.

9.	Use of Collateral

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

(2)	At December 31, 2011 and 2010 , $162 million and $183 million , respectively, were included in margin deposits and other prepaid expense and $20 million and $22 million were included in other assets at December 31, 2011 and 2010 , respectively, on our Consolidated Balance Sheets.

(3)

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

(4)	At December 31, 2010 , the fair value of our commodity derivative instruments collateralized by first priority liens was an asset of $193 million ; therefore, there was no collateral exposure at December 31, 2010 .

(5)	Included in other current liabilities on our Consolidated Balance Sheets.

10.	Income Taxes

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

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11.	Earnings (Loss) per Share

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12.	Stock-Based Compensation

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(1)	Expected term calculated using the simplified method prescribed by the SEC due to the lack of sufficient historical exercise data to provide a reasonable basis to estimate the expected term.

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

(3)	Volatility calculated using the implied volatility of our exchange traded stock options.

(4)	We have never paid cash dividends on our common stock, and it is not anticipated that any cash dividends will be paid on our common stock in the near future.

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13.	Defined Contribution and Defined Benefit Plans

14.	Capital Structure

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15.	Commitments and Contingencies

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

(2)	The standby letters of credit disclosed above represent those disclosed in Note 6.

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

(4)	These are contingent off balance sheet obligations.

(5)	As of December 31, 2011 , $4 million of cash collateral is outstanding related to these bonds.

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16.	Segment and Significant Customer Information

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(1)	Mark-to-market commodity activity represents the unrealized portion of our mark-to-market activity, net, included in operating revenues and fuel and purchased energy expense on our Consolidated Statements of Operations for the years ended December 31, 2011 , 2010 and 2009 , as well as a non-cash gain from amortization of prepaid power sales agreements for the year ended December 31, 2009 .

(2)	Includes $12 million of lease levelization and $8 million of contract amortization for the year ended December 31, 2011 related to contracts that became effective in 2011 .

(3)	Excludes $10 million , $9 million and $5 million of RGGI compliance and other environmental costs for the years ended December 31, 2011 , 2010 and 2009 , respectively, which are components of Commodity Margin.

17.	Quarterly Consolidated Financial Data (unaudited)

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(1)	Represents write-offs of accounts considered to be uncollectible and previously reserved.

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*	Filed herewith.

‡	Furnished herewith.

†	Management contract or compensatory plan or arrangement.

**	Schedules omitted pursuant to Item 601(b)(2) of Regulation S-K. Calpine will furnish supplementally a copy of any omitted schedule to the SEC upon request.

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

***	XBRL (eXtensible Business Reporting Language) information is furnished, not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise is not subject to liability under those sections.