Introduction and Overview

We are an independent wholesale power generation company engaged in the ownership and operation of natural gas-fired and geothermal power plants in North America. We have a significant presence in the major competitive power markets in the U.S., including California and Texas. We sell wholesale power, steam, capacity, renewable energy credits and ancillary services to our customers, including industrial companies, retail power providers, utilities, municipalities, independent electric system operators, marketers and others. We engage in the purchase of natural gas as fuel for our power plants and in related natural gas transportation and storage transactions, and in the purchase of electric transmission rights to deliver power to our customers. We also enter into natural gas and power, commodity and financial derivative transactions to economically hedge our business risks and optimize our portfolio of power plants. We seek to grow our business through selective power plant development, construction and acquisition, as well as through expansion or upgrades of our existing power plants, in each case, based primarily on whether we expect to achieve an attractive return on invested capital.

We are the largest publicly traded, independent wholesale power company in the U.S. measured by power produced in the U.S. in 2008. Our portfolio, including partnership interests, consists of 77 operating power plants, with an aggregate generation capacity of approximately 24,795 MW and our net interest of about 400 MW in Russell City Energy Center in advanced development and the planned expansion of 120 MW to our Los Esteros power plant. Our portfolio is comprised of two types of power generation technologies: natural gas-fired combustion turbines (primarily combined-cycle) and renewable geothermal conventional steam turbines. We generate 4,080 MW of baseload capacity from our Geysers Assets and cogeneration power plants (natural gas-fired power plants that produce and sell both power and steam), 15,570 MW of intermediate load capacity from our combined-cycle combustion turbines and 5,145 MW of peaking capacity from our simple-cycle combustion turbines and duct-fired capability.

We assess our business on a regional basis due to the impact on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors impacting supply and demand. Our reportable segments are West (including geothermal), Texas, Southeast and North (including Canada). In these segments we have an aggregate generation capacity of 7,854 MW in the West, 7,487 MW in Texas, 6,104 MW in the Southeast and 3,350 MW in the North (including Canada). Our Geysers Assets, located in northern California and included in our West segment, produce approximately 725 MW from 15 operating power plants and represent the largest geothermal power generation portfolio in the U.S.

We remain focused on increasing our earnings and generating cash flows sufficient to maintain adequate levels of liquidity to service our debt and to fund our operations. We will continue to pursue opportunities to improve our fleet performance and reduce operating costs. In order to manage our various physical assets and contractual obligations, we will continue to execute commodity hedging agreements within the guidelines of our commodity risk policy.

Operational Developments

During 2009, we have continued to implement our strategy for excellence in operations and the optimization of our existing assets. We have made some notable achievements that are listed below:

• During the quarter, our plant operating personnel exceeded the first quartile performance for employee lost time incident rate for fossil fuel electric power generator companies with 1,000 or more employees, achieved high unit availability (over 97%) and disciplined cost controls.

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

• Our customer origination focus has delivered several significant new transactions, including in California, amendments to existing PPAs extending the duration and quantity of those contracts and new PPAs, some of which must be approved by the CPUC.

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

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

Capital Management

We have opportunistically completed several financing transactions to improve our flexibility and management of our capital structure. Significant 2009 actions include, but are not limited to, the following:

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

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

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

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

Legislative and Regulatory Update

We are subject to complex and stringent energy, environmental and other governmental laws and regulations at the federal, state and local levels in connection with the development, ownership and operation of our power plants. Ongoing state, regional and federal initiatives to implement new environmental and other governmental regulations are expected to have a significant impact on the power generation industry. Such changes could have positive or negative impacts on our existing business. We are actively participating in these debates at the federal, regional and state levels. For a further discussion of the environmental and other governmental regulations that affect us, please see "- Governmental and Regulatory Matters" in Part I, Item 1. of our 2008 Form 10-K. Below is a short discussion of the recent developments as they pertain to our business.

Climate Change

On June 26, 2009, the U.S. House of Representatives passed "The American Clean Energy and Security Act of 2009," a climate change and clean energy bill. The legislation includes, among other provisions:

• An economy-wide carbon cap-and-trade program that:

i. sets reduction targets for carbon emissions from capped sources in several sectors of the economy, including the power sector, starting at a 3% reduction from 2005 levels by 2012, increasing to 17% by 2020, 42% by 2030 and 83% by 2050,

ii. starts in 2012 for the power sector and establishes the point of regulation at the power plant,

iii. distributes 85% of emissions allowances for free, with 35.85% going to the power sector, including 1.5% to eligible generation facilities with qualifying long-term power and steam sales contracts,

iv. requires an auction of the remaining 15% of emissions allowances with the proceeds of such auctions distributed to low- and moderate-income families, and

v. delegates authority to FERC to regulate the cash market in emissions allowances and offsets and to the CFTC to regulate the associated derivatives market.

• A federal energy efficiency and renewable electricity standard which requires retail electricity suppliers to meet the needs of a specific percentage of their load from renewable energy resources and electricity savings.

If this bill were to become law, we would have the obligation to obtain emissions allowances for the operation of our fossil-fuel power plants. While we expect the costs to acquire allowances to be a factor that will impact market price, there can be no assurance that market price will fully reflect these costs. With respect to our existing long-term steam and power contracts under which we would not be able to recover costs to acquire allowances from our customers, the bill allocates a

pool of free allowances to generators with qualifying contracts to mitigate such costs. However, there can be no assurance there will be a sufficient number of free allowances in the pool to fully cover emissions related to generation under such contracts.

On October 23, 2009, draft climate change legislation entitled the Clean Energy Jobs and American Power Act, was released in the Senate. The legislation is similar to the House passed legislation, though its focus is primarily on climate change, not energy. The legislation sets reduction targets for carbon emissions of 20% by 2020 rather than the 17% included in The American Clean Energy and Security Act of 2009; distributes a substantial portion of emissions allowances for free, with some going to the power sector, including to eligible power plants with qualifying long-term power and steam sales contracts; requires an auction of 25% of emissions allowances with the proceeds dedicated for consumer protections and deficit reduction; states that there will be one regulatory body that has market oversight authority, though it does not specify which agency will have that authority; directs the administrator of the EPA to establish an incentives payment program that promotes generation projects that have lower GHG emissions; and provides grants for research and development for advanced natural gas-fired generation technology.

The Senate Environment and Public Works Committee commenced legislative hearings on October 27, 2009 with the stated goal of passing legislation out of the committee by the end of November. Although we cannot predict the effect and ultimate content of final climate change legislation and regulations, if any, on our business, we continue to monitor and actively participate in the process where we anticipate an impact on our business.

Federal Regulation of GHG under Existing Law

As discussed in the 2008 Form 10-K, in 2007 the U.S. Supreme Court ruled in Commonwealth of Massachusetts, et al. v. U.S. Environmental Protection Agency, that the EPA has the authority to regulate GHG issues under language included in the CAA. On April 24, 2009, the EPA released its proposed finding that GHG emissions endanger the public health and welfare of current and future generations. Should the EPA finalize the finding, it may begin developing rules to regulate GHG emissions under the CAA starting with mobile sources, and later including larger stationary sources such as power plants. We are uncertain of the timing of the process for development of potential GHG emissions regulations or what form such regulations may take; accordingly, it is not clear what impact any regulations will have on us.

In a separate case, on September 21, 2009 the U.S. Court of Appeals for the Second Circuit issued an order in State of Connecticut, et al. v. American Electric Power Company Inc., et al., reversing a lower court's dismissal of two public nuisance claims filed by various states, municipalities and private entities against operators of coal-fired power plants. Plaintiffs argued that the power plant defendants contribute to global warming by emitting 650 million tons per year of carbon dioxide and these emissions are causing and will continue to cause serious harms 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 ruling and remanded the cases to the lower court for further proceedings. On October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit made a similar ruling, finding that private property owners may bring claims of public and private nuisance against GHG-emitting oil and chemical companies. We cannot predict at this time the outcome of these cases or what impact the precedent of these cases could have on our business.

Texas

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 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 for the PUCT and ERCOT. It is expected to be concluded by April 2010. The TCEQ review will begin in April 2010 and is scheduled to be completed by November 2010 when the compliance phase for all agencies will begin. We will monitor the Sunset review process of these entities and will seek to participate in these processes where we anticipate an impact on our business.

California

At the end of the California legislative session, the legislature passed a bill to increase the state's RPS to 33% by 2020. The governor of California vetoed the bill. In a separate move, the governor signed an executive order directing CARB under its authority granted by Assembly Bill 32 to adopt regulations consistent with a 33% RPS by 2020. Implementation details of the executive order are yet to be determined; however, it directs CARB to adopt regulations by July 31, 2010.

Stimulus Bill

The American Recovery and Reinvestment Act of 2009, also referred to as the Stimulus Bill, was signed into law on February 17, 2009. The Stimulus Bill includes approximately $787.0 billion in federal tax cuts, expansion of unemployment benefits and other social welfare provisions, and increased domestic spending for education, healthcare and infrastructure, including the energy sector. Approximately $43.0 billion will be available for loans and investments into green energy technology and a number of other renewable energy incentives that can impact our growth and development, particularly our geothermal assets. Specifically, the Stimulus Bill:

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

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

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

We expect that any new geothermal power plant development of our Geysers Assets will qualify for the 30% investment tax credit from the IRS, and our re-powering of our existing plants to qualify for the 10% investment tax credit.

Financial Regulatory Reform and Derivatives

In August 2009, the Obama Administration released draft financial regulatory reform language that, among other things, could significantly change how derivative markets and their participants are regulated. The House Financial Services Committee voted out a bill on October 15, 2009 to regulate OTC derivatives trading, and the House Agriculture Committee voted out a similar bill on October 21, 2009. The two committee bills must be combined and brought to the House floor for a vote. The stated goal is to have a House floor vote by late November. The regulatory reform topics related to derivatives being considered include, among other things: "standardized" OTC energy derivatives be traded on registered exchanges regulated by the CFTC, new and potentially higher capital and margin requirements, volume and position limits, increased regulation and supervision from the CFTC and the SEC, and additional business conduct, record-keeping and reporting requirements. The leadership of the relevant Senate committees has not yet made clear either their legislative priorities with respect to financial regulatory reform, or their anticipated schedule for hearings and markups. Although we cannot predict the effect and ultimate content of final derivatives legislation, if any, some of the new proposed regulatory requirements could make our hedging and optimization activities more difficult and more costly, which could have an adverse impact on our ability to hedge risks associated with our business. We intend to actively monitor and participate in this process where we anticipate an impact on our business.

Geothermal Operations

In 2009, as part of a joint private and federally funded geothermal technology research project, a company unrelated to us commenced deepening an existing geothermal well on a property neighboring our Geysers Assets and reportedly was attempting to drill into the hot, low or non-permeable base rock that underlies the existing geothermal steam reservoir at The Geysers to engineer or create a "multilayered heat extraction system" below the reservoir by injecting water under very high pressure, fracturing the rock. This process has spawned public and political concern regarding increased seismicity risk. As a consequence, in July 2009, the Department of Energy temporarily halted funding of its portion of that project pending further seismicity studies.

In addition, the Department of Energy and residents located near our Geysers Assets have expressed concern regarding induced seismicity associated with geothermal operations. In response to those concerns, it is possible that government entities or agencies will seek to more stringently regulate the exploration, development, and operation of geothermal facilities, including our Geysers Assets, in order to mitigate induced seismicity resulting from geothermal operations.

Results of Operations for the Three Months Ended September 30, 2009 and 2008

Below are the results of operations for the three months ended September 30, 2009, as compared to the same period in 2008 (in millions, except for percentages and operating performance metrics). We have modified our presentation of commodity revenue and commodity expense to include cash settlements from our marketing, hedging and optimization activities that were previously included in mark-to-market activity. Our 2008 commodity revenue and expense information has been reclassified to conform to the current period presentation. In the "$ Change" and ''% Change" columns below, increases in revenue/income or decreases in expense (favorable variances) are shown without brackets while decreases in revenue/income or increases in expense (unfavorable variances) are shown with brackets.

                                             2009          2008         $ Change       % Change
Operating revenues:
Commodity revenue                          $   1,830     $   2,960     $   (1,130 )       (38)   %
Mark-to-market activity(1)                        12           218           (206 )       (94)
Other revenue                                      5            12             (7 )       (58)
Operating revenues                             1,847         3,190         (1,343 )       (42)
Cost of revenue:
Fuel and purchased energy expense:
Commodity expense                              1,061         2,160          1,099          51
Mark-to-market activity(1)                       (31 )         162            193           #
Fuel and purchased energy expense              1,030         2,322          1,292          56

Plant operating expense                          196           198              2           1
Depreciation and amortization expense            108           110              2           2
Other cost of revenue(2)                          20            26              6          23
Total cost of revenue                          1,354         2,656          1,302          49
Gross profit                                     493           534            (41 )        (8)
Sales, general and other administrative
expense                                           38            58             20          34
Loss from unconsolidated investments in
power plants                                      13           202            189          94
Other operating expense                            5             2             (3 )         #
Income from operations                           437           272            165          61
Interest expense                                 198           212             14           7
Interest (income)                                 (3 )         (11 )           (8 )       (73)
Debt extinguishment costs                         16             -            (16 )         -
Other (income) expense, net                        4            18             14          78
Income before reorganization items and
income taxes                                     222            53            169           #
Reorganization items                              (8 )          (2 )            6           #
Income before income taxes                       230            55            175           #
Income tax benefit                                (7 )         (80 )          (73 )       (91)
Net income                                       237           135            102          76
Net loss attributable to the
noncontrolling interest                            1             1              -           -
Net income attributable to Calpine         $     238     $     136     $      102          75

Operating Performance Metrics:                2009          2008         Change        % Change
MWh generated (in thousands)(3)               28,051        25,773          2,278           9    %
Average availability                            97.1 %        96.6 %          0.5           1
Average total MW in operation                 23,423        23,064            359           2
Average capacity factor, excluding
peakers                                         60.7 %        55.2 %          5.5          10
Steam Adjusted Heat Rate                       7,268         7,274              6           -


__________

# Variance of 100% or greater

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

(2) Includes $1 million and nil of RGGI compliance costs for the three months ended September 30, 2009 and 2008, respectively, which is a component of Commodity Margin.

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

Commodity revenue, net of commodity expense, decreased $31 million for the three months ended September 30, 2009 compared to the same period in 2008, primarily due to a decrease in Commodity Margin in Texas of $46 million resulting from lower market spark spreads caused by lower natural gas prices partially offset by higher Market Heat Rates

and higher average availability. The overall decrease was partially offset by an increase of $21 million in Commodity Margin in the West due to higher hedge prices and the higher Market Heat Rate component of spark spread where we had hedged the corresponding gas open position. In addition, Commodity Margin in the Southeast and North decreased $3 million and $4 million, respectively, for the three months ended September 30, 2009 compared to 2008.

Net unrealized mark-to-market activity primarily resulting from our portfolio hedging activities that did not qualify for hedge accounting decreased $13 million for the three months ended September 30, 2009, compared to the same period in 2008. The decrease in revenues from mark-to-market activity was primarily driven by the impact of 2008 where rapidly falling power prices resulted in a gain on our short hedge positions in operating revenues. Similarly, the decrease in expenses from mark-to-market activity was primarily driven by the impact of 2008 where rapidly falling natural gas prices resulted in losses on our long hedge positions in fuel and purchased energy expense.

Other revenue decreased for the three months ended September 30, 2009 compared to the same period in 2008, primarily related to a $4 million decrease in revenue from operation and maintenance contracts and a $1 million decrease in revenue from construction management projects completed in 2008.

Normal, recurring costs in plant operating expense decreased for the three months ended September 30, 2009 compared to the same period in 2008, after accounting for $15 million in reimbursements for insurance claims from prior periods that reduced expenses in the three months ended September 30, 2008.

Other cost of revenue decreased for the three months ended September 30, 2009 compared to the three months ended September 30, 2008, as a result of a decrease of $3 million related to the discontinuation of the amortization of other assets associated with the sale of Auburndale in 2008 as well as a $3 million decrease in royalty expense due to lower revenues from our Geysers Assets resulting from lower spot market power prices in the third quarter of 2009 compared to the same period in 2008. The decrease was partially offset by an increase of $1 million in expenses related to RGGI compliance in the Northeast which was initiated in 2009.

Sales, general and other administrative expense decreased for the three months ended September 30, 2009 compared to the same period in 2008, due to a $9 million decrease in personnel costs and stock-based compensation expense resulting primarily from a lower headcount in 2009 as well as a $9 million decrease in legal and consulting expenses.

Our loss from unconsolidated investments in power plants decreased for the three months ended September 30, 2009 compared to the three months ended September 30, 2008, primarily due to an impairment loss of $179 million related to our equity interest in Auburndale recorded during the third quarter of 2008. Also contributing to the decrease was income from our investment in Greenfield LP of $1 million for the three months ended September 30, 2009, which is due to . . .