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 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 76 operating power plants, with an aggregate generation capacity of approximately 24,187 MW and our net interest in two additional power plants totaling nearly 1,000 MW under construction or in advanced development. 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), 15,057 MW of intermediate load capacity from our combined-cycle combustion turbines and 5,050 MW of peaking capacity from our simple-cycle combustion turbines and duct-fired capability.

We assess our business primarily 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 7,487 MW of capacity in Texas, 7,246 MW in the West, 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.

Legislative and Regulatory Update

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. We are actively participating in these debates at the federal, regional and state levels concerning potential environmental regulation. Although the ultimate legislation and regulations that result from these activities could have a material impact on our business, we believe we will face an overall lower compliance burden than some of our competitors due to the relatively low GHG emission rates of our fleet. 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 March 31, 2009, a climate change and clean energy legislative discussion draft, "The American Clean Energy and Security Act of 2009" was proposed by the chairmen of both the House Energy Committee and the House Energy and Environment Subcommittee. The discussion draft proposes, among other things:

• an economy-wide carbon cap-and-trade program,

• setting carbon emissions reduction targets of: 3% from 2005 levels by 2012, 20% by 2020, 42% by 2030, and 83% by 2050,

• a federal renewable electricity standard which requires retail electricity suppliers to supply a specific percentage of power from renewable energy resources,

• federal policy objectives for transmission planning to facilitate deployment of renewable and zero-carbon electricity resources while ensuring reliability, congestion reduction, cyber-security, and cost-effective electricity services,

• delegating to FERC responsibility for regulation of the cash market in emission allowances and offsets and directing the President to delegate the regulatory responsibility for the derivatives market to an appropriate agency (or agencies).

Further details, including disbursement of allowances and proceeds from allowance auctions, are expected to evolve through committee member discussions, legislative hearings and the markup process. The proposal currently does not address whether long-term contracts that were executed before the regulation of GHG emissions were reasonably anticipated, would be eligible for free allowances or otherwise excepted under the regulation. We have certain power and steam sales contracts that may not allow such costs to be recovered from customers, which could raise our costs of compliance or offset potential benefits to us.

Hearings on the discussion draft have been held and we expect debate to continue. The Senate has not yet taken any action on climate change legislation. Although we cannot predict the ultimate effect any future climate change legislation or regulations could have on our business, we intend to monitor the process and may seek to be heard on any legislation that may ultimately be proposed.

Texas Legislation

Proposed Texas bill HB 2782, currently pending in the House State Affairs Committee, would limit the amount of generation a single entity is permitted to own or control in ERCOT, in an ERCOT zonal boundary or in a functional market recognized by the PUCT to 20%. If an entity owns or controls more than 20% in any such area, that entity would be required to sell at auction or otherwise divest that amount of generation needed to bring it below the 20% threshold, with the PUCT to be required to adopt rules no later than December 31, 2009, to define the scope of the auctions if the bill becomes law. The Senate bill counterpart has not yet been heard in committee. We currently own more than 20% of the generation in the Houston zone; however, we cannot predict at this time whether this or similar legislation will be passed, or what impact it will have on us if passed. We intend to monitor the process and may seek to be heard on any such legislation if it proceeds.

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. 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.

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 is intended to spur economic activity and growth in the wake of the recent economic downturn. The Stimulus Bill includes approximately $787.0 billion in federal tax cuts, expansion of unemployment benefits and other social welfare provisions, increased domestic spending for education,

healthcare and infrastructure, including the energy sector. The Stimulus Bill includes approximately $43.0 billion devoted to renewable energy for loans and investments into green energy technology and a number of other incentives that can impact our growth and development, particularly of our geothermal assets. Specifically, the Stimulus Bill:

• extends the deadline to place new geothermal projects in service to qualify for ten years of "production tax credits" on the electricity output by three years through 2013

• provides geothermal developers the option to elect a 30% investment tax credit in lieu of production tax credits with respect to certain "qualified property" that is part of a geothermal plant placed in service during 2009 or 2010 (or, in certain cases, after 2010), with the ability to receive that 30% investment tax credit in the form of a cash grant from the Department of Treasury that, subject to yet-to-be issued rules, would be paid within 60 days following the later of (i) the placed-in-service date of the new facility and (ii) the grant application date

• designates $6.0 billion in funds to be used as a loss reserve and source of funding for a federal loan guarantee program, anticipated to backstop $80.0 to $110.0 billion of financing for new renewable energy plant and transmission line projects

• designates $400 million in funds for the Department of Energy's Geothermal Technologies Program, which we anticipate will be utilized for cost shared drilling with industry and research and development projects, both targeted towards advancing the production of geothermal energy

We anticipate that our planned investment in our current geothermal power plants, including the re-powering of many of our existing power plants, along with expansion efforts that may include new geothermal plant development, could all benefit from the additional funds and incentives provided by the Stimulus Bill.

Liquidity and Capital Resources

Our business is capital intensive. Our ability to successfully implement our strategy is dependent on the continued availability of capital on attractive terms. In addition, our ability to successfully operate our business and to meet certain near-term debt repayment obligations is dependent on maintaining sufficient liquidity.

Volatility in the financial markets through 2008 and into 2009, including the failure or merger of certain financial institutions and continued uncertainty surrounding many others continues to constrict access to capital and credit markets in the U.S. and worldwide, including within our industry, for us and for our counterparties. We expect these conditions will persist during 2009 and possibly longer. As a result, we and the industry have experienced increased credit and liquidity risk over the past several months. Even if we are not impacted directly, we could be impacted indirectly in the event our counterparties are unable to perform under their contractual obligations with us. We actively monitor our exposure to our counterparties including their credit status.

As of March 31, 2009, we had $1.6 billion in cash and cash equivalents and $476 million of restricted cash including $725 million borrowed on October 2, 2008, under our Exit Credit Facility revolving facility. This borrowing, which was invested in money market funds, which are mainly invested in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. government, its agencies or instrumentalities, was a proactive financial decision to increase our cash position and reduce the risk of nonperformance from institutions that hold a commitment in our Exit Credit Facility revolving facility during a period of uncertainty in the capital markets. Our remaining availability under our Exit Credit Facility revolving facility as of March 31, 2009, is approximately $45 million for future letters of credit or cash borrowings. Our decision to repay, hold or pay down other debt with the cash from our $725 million draw under our Exit Credit Facility revolving facility will be determined based upon our future liquidity needs and confidence in future credit markets.

We have $740 million in current maturities of long-term debt as of March 31, 2009. We believe that we have adequate resources to repay our current maturities as they become due with a combination of cash and cash equivalents on hand and cash expected to be generated from future operations. In the event confidence in the credit markets returns and if we are able to obtain favorable credit terms, we may decide to refinance portions of our current maturities or other more costly debt.

Significant changes in commodity prices and Market Heat Rates can have an impact on our liquidity as we use margin deposits, cash prepayments and letters of credit as credit support (collateral) with and from our counterparties for commodity procurement and risk management activities. Utilizing our portfolio of transactions subject to collateral exposure, we estimate that, as of May 5, 2009, an increase of $1/MMBtu in natural gas prices would result in an increase of collateral required of approximately $205 million. If natural gas prices decreased by $1/MMBtu, we estimate that our collateral requirements would decrease by approximately $210 million. Changes in Market Heat Rates also affect our liquidity. For

example, as demand increases, less efficient generation is dispatched, which increases the Market Heat Rate and results in increased collateral requirements. Based upon historical relationships of natural gas and Market Heat Rate movements for our portfolio of assets, we derived a statistical analysis that indicates that a change of $1/MMBtu in natural gas is comparable to a Market Heat Rate change of 170 Btu/KWh. We estimate that, as of May 5, 2009, an increase of 170 Btu/KWh in the Market Heat Rate would result in an increase in collateral required of approximately $21 million. If Market Heat Rates were to fall at a similar rate, we estimate that our collateral required would decrease by $22 million. These amounts are not necessarily indicative of the actual amounts that could be required, which may be higher or lower than the amounts estimated above.

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

To provide for increased liquidity in periods of rising commodity prices, we entered into two credit facilities, the Knock-in Facility and Commodity Collateral Revolver that increase our liquidity available to collateralize obligations to counterparties under eligible commodity hedge agreements during periods of increasing natural gas prices. The Knock-in Facility, maturing on June 25, 2009, provides an initial $50 million of available capacity for the issuance of letters of credit up to a total maximum availability of $200 million contingent on natural gas futures contract prices exceeding certain thresholds. The Commodity Collateral Revolver, maturing July 8, 2010, under which we received an initial advance of $100 million, provides up to a total maximum availability of $300 million contingent on mark-to-market exposure amounts under certain reference transactions. It is unlikely that any additional amounts under either facility will be available as natural gas prices are not expected to exceed stated thresholds in the near future.

We could potentially face downward pressure on our Commodity Margin as a result of the current economic recession. The impacts would be highly dependent on the severity and duration of the economic downturn. During pronounced recessionary periods, there can be a decrease in power demand primarily driven by decreased usage by the industrial and manufacturing sectors. This "softening" of demand typically results in more demand satisfied by baseload and intermediate units using lower variable cost fuel sources such as coal and nuclear fuel, and less demand served by higher variable cost units such as natural gas-fired peaking power plants. Additionally, a recessionary environment can result in lower natural gas pricing which may adversely impact our Commodity Margin as our cost of production advantage relative to less efficient natural gas-fired generation is diminished on an absolute basis. However, with our combined forward power sales and natural gas purchases, we believe that we have substantially hedged our Commodity Margin for the remainder of 2009. Additionally, we have continued to increase our hedging activities through 2010 and therefore do not expect further declines in natural gas prices to significantly impact our results of operations in the near term.

It is difficult to predict future developments and the amount of credit support that we may need to provide as part of our business operations should financial market and commodity price volatility persist for a significant period of time. Our ability to generate sufficient cash is dependent upon, among other things:
(i) improving the profitability of our operations; (ii) continued compliance with the covenants under our Exit Credit Facility and other existing financing obligations; (iii) stabilizing and increasing future contractual cash flows; and
(iv) our significant counterparties performing under their contracts with us.

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

Letter of Credit Facilities - The table below represents amounts outstanding under our letter of credit facilities as of March 31, 2009 (in millions):

                                       2009
Exit Credit Facility                   $ 230
Calpine Development Holdings, Inc.       148
Knock-in Facility                         30
Various project financing facilities      98
Total                                  $ 506

Cash Management - We manage our cash in accordance with our intercompany cash management system subject to the requirements of the Exit Credit Facility and requirements under certain of our project debt and lease agreements or by regulatory agencies. Our cash and cash equivalents as well as our restricted cash balances generally exceed FDIC insured limits or are invested in money market accounts with investment banks that are not FDIC insured. We place our cash, cash equivalents and restricted cash in what we believe to be credit-worthy financial institutions and certain of our money market accounts invest in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. government, its agencies or instrumentalities.

We are prohibited from paying any cash dividends on our common stock for the foreseeable future because our ability to pay cash dividends is restricted under the Exit Credit Facility and certain of our other debt agreements. Future cash dividends, if any, will be at the discretion of our Board of Directors and will depend upon, among other things, our future operations and earnings, capital requirements, general financial condition, contractual and financing restrictions and such other factors as our Board of Directors may deem relevant.

NOLs - We have significant NOLs that will provide future tax deductions if we generate sufficient taxable income during the carryover periods. We are comprised primarily of two groups for federal income tax reporting purposes, CCFC and its subsidiaries, which we refer to as the CCFC group and Calpine Corporation and its subsidiaries other than CCFC, which we refer to as the Calpine group. As of December 31, 2008, our consolidated federal NOLs totaled approximately $7.5 billion, which consists of approximately $7.1 billion from our Calpine group and approximately $396 million from our CCFC group. We expect to generate approximately $150 million to $200 million in federal NOLs in 2009 from the CCFC and Calpine groups. In addition, we have approximately $1.0 billion in foreign NOLs and $4.4 billion in state NOLs. Our Calpine group has recorded a valuation allowance against the deferred taxes related to most of their NOLs as we determined it is more likely than not, that they will expire unutilized. We estimate that our CCFC group will be able to utilize their NOLs, and accordingly have not recorded a valuation allowance against the deferred taxes related to these NOLs. Approximately $5.6 billion of our NOLs have annual limitations under Section 382 of the IRC. Amounts subject to limitations, but not used, can be carried forward to succeeding years.

Optimization of Existing Assets - We continue to review development opportunities, which were put on hold during the pendency of our Chapter 11 cases, to determine whether future actions are appropriate and we may pursue new opportunities that arise, particularly if power contracts and financing are available and attractive returns are expected. Currently, we have one project, Russell City Energy Center, in advanced development and our OMEC project remains under construction and is expected to achieve commercial operations in the fall of 2009.

The Russell City Energy Center is currently contracted to deliver its full output to PG&E under a PPA which was executed in December 2006 and approved by the CPUC in January 2007. The PPA was amended in 2008 and was approved by the CPUC on April 16, 2009. All permits for the projects have been issued and approved with the exception of an air permit now pending before the local air quality board. Under the amended PPA, the expected commercial operation date has been extended by two years from 2010 to June 2012. Completion of the Russell City Energy Center is dependent upon obtaining the necessary permits, regulatory approvals, construction contracts and construction funding under project financing facilities. We do not expect the costs to complete the Russell City Energy Center to be material to us on a consolidated basis. Upon completion, this project would bring on line approximately 362 MW of net interest baseload capacity (390 MW with peaking capacity) representing our 65% share.

We hold all of the equity interest in one unconsolidated project under construction at March 31, 2009, OMEC, which is expected to achieve commercial operations in 2009. The completion of OMEC will bring on line approximately 596 MW of net interest baseload (with peaking) capacity. We also own a 50% equity interest in the Greenfield Energy Centre, which achieved commercial operations on October 17, 2008. Our net interest baseload (with peaking) capacity increased as a result of Greenfield Energy Centre by approximately 503 MW representing our 50% share.

Cash Flow Activities - The following table summarizes our cash flow activities for the three months ended March 31, 2009 and 2008 (in millions):

                                             2009         2008
Beginning cash and cash equivalents         $ 1,657     $  1,915
Net cash provided by (used in):
Operating activities                             80         (340 )
Investing activities                            (27 )        483
Financing activities                            (84 )     (1,777 )
Net decrease in cash and cash equivalents       (31 )     (1,634 )
Ending cash and cash equivalents            $ 1,626     $    281

Net Cash Provided By (Used In) Operating Activities

Cash flows provided by operating activities for the three months ended March 31, 2009, resulted in net inflows of $80 million compared to outflows of $340 million for the same period in 2008. The change in cash flows from operating activities was primarily due to:

• Increases in gross profit - Gross profit, excluding unrealized changes in mark-to-market activity, increased by $7 million in 2009 primarily due to higher realized spark spreads resulting from higher hedged levels. The favorable margins were partially offset by a decrease in generation.

• Decreases in interest paid - Cash paid for interest decreased by $244 million in 2009 to $226 million for the three months ended March 31, 2009, as compared to $470 million for the same period in 2008, primarily due to the repayment of the Second Priority Debt.

• Decreases in working capital - Working capital employed decreased by approximately $91 million during the period after adjusting for debt related balances and assets held for sale, which did not impact cash provided by operating activities. The decrease was primarily due to reductions in margin deposits partially offset by current derivative activity.

• Decreases in reorganization costs - Cash payments for reorganization items decreased by $64 million.

Net Cash Provided By (Used In) Investing Activities

Cash flows used in investing activities for the three months ended March 31, 2009, were $27 million compared to cash flows provided by investing activities of $483 million for the three months ended March 31, 2008. The difference was primarily due to:

• Sales of power plants, turbines and investments - Proceeds from asset sales were $398 million in 2008 compared to nil in 2009.

• Reconsolidation of our Canadian Debtors and other foreign entities - In 2008, a favorable cash effect of $64 million was received from the reconsolidation of our Canadian Debtors and other foreign entities.

• Return of investment from unconsolidated investments - In the three months ended March 31, 2008, we received distributions of $24 million compared to nil for the three months ended March 31, 2009.

• Reduced restricted cash requirements - The net reduction in restricted cash was $27 million in 2009, down $16 million from $43 million in 2008. Restricted cash decreased in 2009 mainly due to regularly scheduled repayments of notes payable partially offset by funding from the Deer Park financing.

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