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Article by DailyStocks_admin    (10-24-08 08:54 AM)

Filed with the SEC from Oct 9 to Oct 15:

Calpine (CPN)
A group including SPO Advisory boosted its holdings in the energy provider to 80,047,061 shares (18.9%) from the 75,384,261 (17.8%) disclosed on Oct. 6.

BUSINESS OVERVIEW

Business

In addition to historical information, this Report contains forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. We use words such as “believe,” “intend,” “expect,” “anticipate,” “plan,” “may,” “will” and similar expressions to identify forward-looking statements. Such statements include, among others, those concerning our expected financial performance and strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. You are cautioned that any such forward-looking statements are not guarantees of future performance and that a number of risks and uncertainties could cause actual results to differ materially from those anticipated in the forward-looking statements. Such risks and uncertainties include, but are not limited to: (i) our ability to implement our business plan; (ii) financial results that may be volatile and may not reflect historical trends; (iii) seasonal fluctuations of our results and exposure to variations in weather patterns; (iv) potential volatility in earnings associated with fluctuations in prices for commodities such as natural gas and power; (v) our ability to manage liquidity needs and comply with covenants related to our Exit Facilities and other existing financing obligations; (vi) our ability to complete the implementation of our Plan of Reorganization and the discharge of our Chapter 11 cases including successfully resolving any remaining claims; (vii) disruptions in or limitations on the transportation of natural gas and transmission of electricity; (viii) the expiration or termination of our PPAs and the related results on revenues; (ix) risks associated with the operation of power plants including unscheduled outages; (x) factors that impact the output of our geothermal resources and generation facilities, including unusual or unexpected steam field well and pipeline maintenance and variables associated with the waste water injection projects that supply added water to the steam reservoir; (xi) risks associated with power project development and construction activities; (xii) our ability to attract, retain and motivate key employees including filling certain significant positions within our management team; (xiii) our ability to attract and retain customers and counterparties; (xiv) competition; (xv) risks associated with marketing and selling power from plants in the evolving energy markets; (xvi) present and possible future claims, litigation and enforcement actions; (xvii) effects of the application of laws or regulations, including changes in laws or regulations or the interpretation thereof; and (xviii) other risks identified in this Report. You should also carefully review other reports that we file with the SEC. We undertake no obligation to update any forward-looking statements, whether as a result of new information, future developments or otherwise.

We file annual, quarterly and periodic reports, proxy statements and other information with the SEC. You may obtain and copy any document we file with the SEC at the SEC’s public reference room at 100 F Street, NE, Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the SEC’s public reference facilities by calling the SEC at 1-800-SEC-0330. You can request copies of these documents, upon payment of a duplicating fee, by writing to the SEC at its principal office at 100 F Street, NE, Room 1580, Washington, D.C. 20549-1004. The SEC maintains an Internet website at http://www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. Our SEC filings are accessible through the Internet at that website.

Our reports on Forms 10-K, 10-Q and 8-K, and amendments to those reports, are available for download, free of charge, as soon as reasonably practicable after these reports are filed with the SEC, at our website at www.calpine.com. The content of our website is not a part of this Report. You may request a copy of our SEC filings, at no cost to you, by writing or telephoning us at: Calpine Corporation, 717 Texas Avenue, Houston, TX 77002, attention: Corporate Communications, telephone: (713) 830-8775. We will not send exhibits to the documents, unless the exhibits are specifically requested and you pay our fee for duplication and delivery.

OVERVIEW

Our Business

We are an independent power producer that operates and develops clean and reliable power generation facilities in North America. Our primary business is the generation and sale of electricity and electricity-related products and services to wholesale and industrial customers through the operation of our portfolio of owned and leased power generation assets with approximately 24,000 MW of generating capacity. We market electricity produced by our generating facilities to utilities and other third party purchasers. Our commercial marketing and energy trading organizations work closely with our plant operations team to protect and enhance the value of our assets by coordinating dispatch and utilization of our power plants with maintenance schedules to achieve effective deployment of our portfolio.

Our power generation facilities comprise two fuel-efficient and clean power generation technologies: natural gas-fired combustion (primarily combined-cycle) and renewable geothermal facilities. At December 31, 2007, we owned or leased a portfolio of 60 active, clean burning, natural gas-fired power plants throughout the U.S. and 17 active geothermal power plants in the Geysers region of northern California. Our natural gas-fired portfolio is equipped with modern and efficient power generation technologies and is an example of our commitment to clean energy production. Our geothermal plants are low variable-cost facilities that harness the power of the Earth’s naturally occurring steam geysers to generate electricity. Our geothermal energy portfolio is one of the largest producing geothermal resources in the world. In addition to our operating plants, we have interests in two plants in active construction and one plant in active development.

We seek to optimize the profitability of our individual facilities by coordinating O&M and major maintenance schedules, as well as dispatch and fuel supply, throughout our portfolio. We manage the energy commodity price risk of our power generation facilities as an integrated portfolio in the major U.S. markets in which we operate. By centrally managing the portfolio, our sales and marketing resources are able to more efficiently serve our power generation facilities by providing trading and scheduling services to meet delivery requirements, respond to market signals and to ensure fuel is delivered to our facilities. Central management also enables us to reduce our exposure to market volatility and improve our results. In the event that one of our facilities is unavailable or less economic to run in a particular market, we might call upon another one of our facilities in the same market to generate the electricity promised to a customer. Such coordination has allowed us to achieve a high level of reliability. We also have developed risk management guidelines, approved by our Board of Directors, which apply to the sales, marketing, trading and scheduling processes. Market risks are monitored to ensure compliance with our risk management guidelines and to seek to minimize our exposure to those risks. We believe that our capabilities, guidelines and arrangements collectively create efficiencies and value for the enterprise beyond what we could achieve by operating each power plant on a stand-alone basis.

Although we centrally manage our portfolio, 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. Accordingly, our reportable segments are West (including geothermal), Texas, Southeast, North and Other. Over 77% of our generation in 2007 was attributable to our West and Texas segments. Our “Other” segment includes fuel management, our turbine maintenance group, our TTS and PSM businesses for periods prior to their sale and certain hedging and other corporate activities. See Note 16 of the Notes to Consolidated Financial Statements for financial information about our business segments and “—Description of Power Generation Facilities” for a list of our power plants and generation statistics by segment.

We were organized as a corporation in 1984 for the purpose of providing clean energy and services to the newly emerging independent power industry. Our principal offices are located in San Jose, California and Houston, Texas, and we operate our business through a variety of divisions, subsidiaries and affiliates.

Chapter 11 Cases and CCAA Proceedings

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

As a result of the filings under the CCAA, we deconsolidated most of our Canadian and other foreign entities as of the Petition Date as we determined that the administration of the CCAA proceedings in a jurisdiction other than that of the U.S. Debtors’ Chapter 11 cases resulted in a loss of the elements of control necessary for consolidation. We fully impaired our investment in the Canadian and other foreign subsidiaries as of the Petition Date and, through the period covered by this Report, accounted for such investments under the cost method. On February 8, 2008, the Canadian Effective Date, the proceedings under the CCAA were terminated and, accordingly, these entities were reconsolidated. Because the reconsolidation occurred after December 31, 2007, our Consolidated Financial Statements exclude the financial statements of the Canadian Debtors, and the information in this Report principally describes the Chapter 11 cases and only describes the CCAA proceedings where they have a material effect on our operations or where such description provides necessary background information.

During the pendency of our Chapter 11 cases through the Effective Date, pursuant to automatic stay provisions under the Bankruptcy Code and orders granted by the Canadian Court, all actions to enforce or otherwise effect repayment of liabilities preceding the Petition Date as well as all pending litigation against the Calpine Debtors generally were stayed. Following the Effective Date, actions to enforce or otherwise effect repayment of liabilities preceding the Petition Date, as well as pending litigation against the Calpine Debtors related to such liabilities generally have been permanently enjoined. Any unresolved claims will continue to be subject to the claims reconciliation process under the supervision of the U.S. Bankruptcy Court. However, certain pending litigation related to pre-petition liabilities may proceed in courts other than the U.S. Bankruptcy Court to the extent the parties to such litigation have obtained relief from the permanent injunction.

Plan of Reorganization — On June 20, 2007, the U.S. Debtors filed the Debtors’ Joint Plan of Reorganization and related Disclosure Statement, which were subsequently amended on each of August 27, September 18, September 24, September 27 and December 13, 2007. On December 19, 2007, we filed the Sixth Amended Joint Plan of Reorganization. As a result of the modifications to the Plan of Reorganization as well as settlements reached by stipulation with certain creditors, all classes of creditors entitled to vote ultimately voted to approve the Plan of Reorganization. The Plan of Reorganization, which provides that the total enterprise value of the reorganized U.S. Debtors for purposes of the Plan of Reorganization is $18.95 billion, also provided for the amendment and restatement of our certificate of incorporation and the adoption of the Calpine Equity Incentive Plans. The Plan of Reorganization was confirmed by the U.S. Bankruptcy Court on December 19, 2007, and became effective on January 31, 2008.

The Plan of Reorganization provides for the treatment of claims against and interests in the U.S. Debtors. Pursuant to the Plan of Reorganization, allowed administrative claims and priority tax claims will be paid in full in cash or cash equivalents, as will allowed first and second lien debt claims. Other allowed secured claims will be reinstated, paid in full in cash or cash equivalents, or have the collateral securing such claims returned to the secured creditor. Allowed make whole claims arising in connection with the repayment of the CalGen Second Lien Debt and the CalGen Third Lien Debt will be paid in full in cash or cash equivalents, which may include cash proceeds generated from the sale of common stock of the reorganized Calpine Corporation pursuant to the Plan of Reorganization. To the extent that the common stock reserved on account of such make whole claims is insufficient to generate sufficient cash proceeds to satisfy such claims in full, the Company must use other available cash to satisfy such claims. Allowed unsecured claims will receive a pro rata distribution of all common stock of the reorganized Calpine Corporation to be distributed under the Plan of Reorganization (except shares reserved for issuance under the Calpine Equity Incentive Plans). Allowed unsecured convenience claims (subject to certain exceptions, all unsecured claims $50,000 or less) will be paid in full in cash or cash equivalents. Holders of allowed interests in Calpine Corporation (primarily holders of Calpine Corporation common stock existing as of the Petition Date) will receive a pro rata share of warrants to purchase approximately 48.5 million shares of reorganized Calpine Corporation common stock, subject to certain terms. Holders of subordinated equity securities claims will not receive a distribution under the Plan of Reorganization and may only recover from applicable insurance proceeds. Because certain disputed claims were not resolved as of the Effective Date and are not yet finally adjudicated, no assurances can be given that actual claim amounts may not be materially higher or lower than confirmed in the Plan of Reorganization.

In connection with the consummation of the Plan of Reorganization, we closed on our approximately $7.3 billion of Exit Facilities, comprising the outstanding loan amounts and commitments under the $5.0 billion DIP Facility (including the $1.0 billion revolver), which were converted into exit financing under the Exit Credit Facility, approximately $2.0 billion of additional term loan facilities under the Exit Credit Facility and $300 million of term loans under the Bridge Facility. Amounts drawn under the Exit Facilities at closing were used to fund cash payment obligations under the Plan of Reorganization including the repayment of a portion of the Second Priority Debt and the payment of administrative claims and other pre-petition claims, as well as to pay fees and expenses in connection with the Exit Facilities and for working capital and general corporate purposes.

Pursuant to the Plan of Reorganization, all shares of our common stock outstanding prior to the Effective Date were canceled, and we authorized the issuance of 485 million new shares of reorganized Calpine Corporation common stock, of which approximately 421 million shares have been distributed to holders of allowed unsecured claims against the U.S. Debtors (of which approximately 10 million are being held in escrow pending resolution of certain intercreditor matters), and approximately 64 million shares have been reserved for distribution to holders of disputed unsecured claims whose claims ultimately become allowed. We estimate that the number of shares reserved was more than sufficient to satisfy the U.S. Debtors’ obligations under the Plan of Reorganization even if all disputed unsecured claims ultimately become allowed. As disputed claims are resolved, the claimants receive distributions of shares from the reserve on the same basis as if such distributions had been made on or about the Effective Date. To the extent that any of the reserved shares remain undistributed upon resolution of the remaining disputed claims, such shares will not be returned to us but rather will be distributed pro rata to claimants with allowed claims to increase their recovery. We are not required to issue additional shares above the 485 million shares authorized to settle unsecured claims, even if the shares remaining for distribution are not sufficient to fully pay all allowed unsecured claims. Accordingly, resolution of these claims could have a material effect on creditor recoveries under the Plan of Reorganization as the total number of shares of common stock that remain available for distribution upon resolution of disputed claims is limited pursuant to the Plan of Reorganization.

In addition to the 485 million shares authorized to be issued to settle unsecured claims, pursuant to the Plan of Reorganization, we authorized the issuance to certain of our subsidiaries of additional shares of new common stock to be applied to the termination of certain intercompany balances. Upon termination of the intercompany balances on February 1, 2008, these additional shares were returned to us and have been restored to our authorized shares available for future issuance.

In addition, pursuant to the Plan of Reorganization, we authorized the issuance of up to 15 million shares under the Calpine Equity Incentive Plans and we issued warrants to purchase approximately 48.5 million shares of common stock at $23.88 per share to holders of our previously outstanding common stock. Each warrant represents the right to purchase a single share of our new common stock and will expire on August 25, 2008.

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

Several parties have filed appeals seeking reconsideration of the Confirmation Order. See Note 15 of the Notes to Consolidated Financial Statements for more information.

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

As a result of the termination of the CCAA proceedings, the Canadian Debtors and other deconsolidated foreign entities, consisting of a 50% ownership interest in the 50-MW Whitby Cogeneration power plant, approximately $34 million of debt and various working capital items, were reconsolidated on the Canadian Effective Date.

Business Initiatives

Prior to and during 2007, in connection with our restructuring, we undertook an asset rationalization process that resulted in the divestiture of nine power plants and two subsidiary businesses, TTS and PSM, that provide services and parts for combustion turbine equipment, that were determined to be under-performing or non-core businesses. In addition, we entered into an agreement to sell a development project, and closed the sale of a second, for each of which construction had been suspended, and we entered into an asset purchase agreement for the RockGen Energy Center, which we previously leased. We restructured existing agreements or reconfigured equipment to enhance the economic or operational performance of five power plants for which we had previously agreed to limit the amount of funds available to support operations; as a result of such actions, the limitations were terminated. We are also actively marketing two natural gas-fired power plants and their eventual sale remains a possibility. We continue to evaluate our power generation portfolio and other business activities on an ongoing basis to determine if actions should be taken with respect to other assets, including whether any should be marketed for potential divestiture and if other actions including restructurings, expansions, improvements or personnel and other overhead adjustments should be implemented in order to optimize productivity and the economics of the asset.

All new development projects, including expansions of existing projects, are evaluated based on a variety of factors to determine the optimal opportunities for us and our fleet. We will continue to seek opportunities to develop our business through selective acquisitions, joint ventures, and divestitures to further enhance our asset mix and competitive position.

We maintain a fleet-wide operating data acquisition, retrieval and storage system, and employ a condition-based maintenance program to evaluate the current status of our turbine fleet based on inspections and operating conditions to determine the most efficient timing to replace worn parts. We intend to further develop and enhance our plant monitoring systems on an ongoing basis to provide an advanced fleet-wide management tool that will integrate all plant natural gas, steam, and power volumes into a common system to handle reporting, billing, monitoring, and billing disputes in a cost-efficient and regulatory-compliant manner.

We strive to continually improve our risk management policy and procedures and the infrastructure required to support risk management, which may be modified from time to time as determined by our senior management and our Board of Directors. All of our energy commodity risk is managed within the limits defined in our risk management policy. Our senior management team will review and approve long-term strategic actions. Long-term strategies will generally seek to balance our market view of commodity prices and the economic value we are seeking to capture with the perceived impact on our risk profile by our investors and rating agencies and the cost of implementing that strategy for our collateral and capital structure.

THE MARKET FOR ELECTRICITY

Overview

The power industry represents one of the largest industries in the U.S. and impacts nearly every aspect of our economy, with an estimated end-user market comprising approximately $339 billion of electricity sales in 2007 based on information published by EIA. Historically, vertically integrated electric utilities with monopolistic control over franchised territories dominated the power generation industry in the U.S. However, industry trends and regulatory initiatives designed to encourage competition in wholesale electricity markets have transformed some markets into more competitive arenas where load-serving entities and end-users may purchase electricity from a variety of suppliers, including IPPs, power marketers, regulated public utilities, major financial institutions and others. For over a decade, the power industry has been deregulated at the wholesale level allowing generators to sell directly to the load-serving entities such as public utilities, municipalities and electric cooperatives. Although industry trends and regulatory initiatives aimed at further deregulation have slowed, halted or even reversed in some geographic regions, in terms of the level of competition, pricing mechanisms and pace of regulatory reform, two of our largest markets, West and Texas, have emerged as more competitive markets.

Four key market “drivers” significantly affect our financial performance. These are the regional supply and demand environment for electricity, regional generation technology and fuel mix, natural gas prices and environmental regulations.

While our market drivers are subject to risk, some of the uncertainty is reduced by the existence of steam sales contracts and PPAs which dictate the payments we receive for energy and capacity and by the hedging activities that are undertaken by our energy trading group. The balance of our generation not subject to steam sales contracts and PPAs is sold into the market. Although these sales are subject to the risk of unfavorable movements in prices, much of our projected earnings from sales into the market are hedged through forward sales or other derivative transactions. We continue to pursue opportunities to secure steam sales contracts and PPAs where they are considered to be more preferable to sales directly into the market.

Regional Supply and Demand

The current U.S. market consists of distinct regional electric markets, not all of which are effectively interconnected. As a result, reserve margins (the measure of how much the total generating capacity installed in a region exceeds the peak demand for power in that region) vary from region to region. For example, a reserve margin of 15% indicates that supply exceeds expected peak electricity demand by 15%. Holding other factors constant, lower reserve margins typically lead to higher power prices, because the less efficient capacity in the region is needed to satisfy electricity demand.

Regional supply and demand affect the pricing for electricity that results from wholesale market competition, and, consequently, are key drivers of our financial performance. For much of the 1990s, utilities invested relatively sparingly in new generating capacity. As a result, by the late 1990s, many regional markets were in need of new capacity to meet growing electricity demand. Prices rose due to capacity shortages, and the emerging merchant power industry responded by constructing significant amounts of new capacity. Between 2000 and 2003, more than 175,000 MW of new generating capacity came “on line” in the United States. In most regions, these new capacity additions far outpaced the growth of demand, resulting in “overbuilt” markets, i.e., markets with excess capacity. In the West, for example, approximately 24,000 MW of new generating capacity was added between 2000 and 2003, while demand only increased by approximately 8,000 MW. Most of this new generating capacity consisted of gas-fired combined-cycle plants which use a gas turbine to create electricity, then capture, or recycle, the waste heat to create steam, which is then used to create additional electricity through a steam turbine. Natural gas-fired combined-cycle units tend to have higher variable costs in the current natural gas price climate and generally cannot compete effectively with nuclear and coal-fired units, which can produce power at lower variable costs. This surge of generation investment has subsided since 2003. During 2005, for example, approximately 17,000 MW of new supply was added nationwide. This coupled with growing demand for electricity, has begun to reduce the level of excess supply, leading to current predictions of decreasing reserve margins for many regional markets through the end of the decade.

As a result, reserve margins may decrease after current capacity is absorbed by the market. Some market regulators have forecasted such a decrease in two of our major markets. For example, ERCOT, which includes all of our Texas power plants, has forecasted that its reserve margins will decrease from 13.1% in 2008 to 8.2% in 2013. Similarly, in California, which includes a significant portion of our West power plants, PG&E estimates that reserve margins in its service territory, will decrease from 18.2% in 2008 to 10.9% in 2016.

Moreover, in various regional markets, electricity market administrators have acknowledged that the markets for generating capacity do 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 are being implemented in the Northeast and Mid-Atlantic regional markets to address this issue. In addition, California has several preceedings, both at the CPUC and the CAISO, to enhance existing capacity markets. If these market design efforts are successful, and if other markets adopt this approach, it could provide additional capacity revenues for IPPs, but any such new capacity market could take years to develop.

Regional Generation Technology and Fuel Mix

In a competitive market, the price of electricity typically is related to the operating costs of the marginal, or price-setting, generator. Assuming economic behavior by market participants, generating units generally are dispatched in order of their variable costs. In other words, units with lower costs are dispatched first and higher-cost units are dispatched as demand (sometimes referred to as “load”) grows. Accordingly, the variable costs of the last (or marginal) unit needed to satisfy demand typically drives the regional power price.

There are three general classifications of generation capacity: baseload; intermediate; and peaking. Baseload units, fueled by cheaper fuels such as hydro, geothermal, coal, or nuclear fuels, are the least expensive from a variable cost perspective and generally serve electricity demand during most hours. Intermediate units, such as combined-cycle plants fueled by natural gas, are more expensive and generally are required to serve electricity demand during on-peak or weekday daylight hours. Lastly, peaking units are the most expensive units from a variable cost perspective to dispatch and generally serve electricity demand only during on-peak hours after less expensive baseload and intermediate units are at full capacity. Much of our generating capacity is in our West and Texas markets, which are regional markets in which gas-fired units set prices during most hours. Because natural gas prices generally are higher than most other input fuels, these regions generally have higher power prices than regions in which coal-fired units set prices. Outside of the West and Texas regions, however, other generating technologies, typically coal-fired plants, tend to set prices more often, reducing average prices and “commodity margin,” which is our term used to describe the margin between realized power prices and fuel costs. These conditions, particularly in overbuilt markets, often make it difficult for gas-fired generation to compete.

In addition to earning margins from the sale of electricity, our geothermal assets benefit from regulations that promote renewable or “green” energy sources. For example, regardless of the dominant technology types for the generation of electricity in the West, the current shortage of renewable generation sources creates a premium for electricity from the geothermal facilities.

Natural Gas Prices

Natural gas prices have been particularly volatile in the current decade. As examples, during the California energy crisis in 2000, daily (or “spot”) natural gas prices rose at times above $20/MMBtu in California, and during 2005, natural gas prices rose to the $11-$13/MMBtu level in the aftermath of disruptions

in Gulf of Mexico gas production caused by Hurricane Katrina, before trending downward in 2006 to the $5-$7/MMBtu range. Natural gas contracts for delivery beyond 2007 continue to trade in the $8-$10/MMBtu range.

At times, higher natural gas prices tend to increase our commodity margin; this occurs where natural gas is the price-setting fuel, such as generally during peak periods in Texas and the West, because our combined-cycle plants are more fuel-efficient than many older gas-fired technologies and peaking units. At other times higher natural gas prices have a neutral impact on us, such as where we enter into tolling agreements under which the customer provides the natural gas in return for electric power or where we enter into indexed-based agreements with a contractual Heat Rate at or near our actual Heat Rate. And at other times, high natural gas prices can decrease our margins, such as where we have entered into fixed-price PPAs and have not hedged the cost of natural gas or where another fuel, such as coal, is the price-setting fuel, which occurs frequently in the Southeast.

Because the price of natural gas is so volatile, we attempt to hedge our exposure to changes in gas prices, as discussed under “— Marketing, Hedging, Optimization and Trading Activities” below.

Environmental Regulations

Environmental regulations force generators to incur costs to comply with limits on emissions of certain pollutants. Higher operating costs for coal and oil fuel-fired generators implicitly favor low-emissions generating technologies such as our geothermal and gas-fired capacity. Further, to the extent that price-setting units experience higher variable costs due to environmental regulations, market prices tend to increase. See “— Government Regulation” for a discussion of the regulations that have or may have a significant impact on our business.

COMPETITION

We believe our ability to compete effectively will be substantially driven by the extent to which we (i) achieve and maintain a lower cost of production and transmission, primarily by managing fuel costs; (ii) effectively manage and accurately assess our risk portfolio; and (iii) provide reliable service to our customers. Wholesale power generation is a capital-intensive, commodity-driven business with numerous industry participants. We compete against other IPPs, trading companies, financial institutions, retail load aggregators, municipalities, retail electric providers, cooperatives and regulated utilities to supply electricity and electricity-related products to our customers in major markets nationwide and throughout North America. In addition, in some markets, we compete against some of our own customers. During recent years, financial institutions have aggressively entered the market along with hedge funds and other private equity funds. We believe the addition of these financial institutions and other investors to the market has generally been beneficial by increasing the number of customers for our physical power products, offering risk management products to manage commodity price risk, improving the general financial strength of market participants and ultimately increasing liquidity in the markets.

In less regulated markets, our natural gas and geothermal facilities compete directly with all other sources of electricity. Even though most new power generating facilities are fueled by natural gas, EIA estimates that in 2007 only 22% of the electricity generated in the U.S. was fueled by natural gas and that approximately 67% of power generated in the U.S. was still produced by coal and nuclear facilities, which generated approximately 48% and 19%, respectively. EIA estimates that the remaining 11% of electricity generated in the U.S. was fueled by hydro, fuel oil and other energy sources. However, as environmental regulations continue to evolve, the proportion of electricity generated by natural gas and other low emissions resources is expected to increase in some markets. Some states are imposing strict environmental standards on generators to limit their emissions of NOx, SO 2, Hg and GHG. As a result, many of the current coal plants will likely have to install costly emission control devices or limit their operations. Meanwhile, many states are mandating that certain percentages of electricity delivered to end users in their jurisdictions be produced from renewable resources, such as geothermal, wind and solar energy. This activity could cause some coal plants to be retired, thereby allowing a greater proportion of power to be produced by facilities fueled by natural gas, geothermal or other resources that have a less adverse environmental impact.

However, some regulated utilities have proposed to construct coal and nuclear facilities, in some cases with governmental subsidies or under legislative action. Unlike IPPs, these utilities often can recover fixed costs through regulated retail rates, allowing them to invest capital without the need to rely on market prices to recover their investments. In addition, many regulated utilities are also seeking to acquire distressed assets or make substantial improvements to existing coal plants, in each case with regulatory assurance that the utility will be permitted to recover its costs, plus earn a return on its investment. IPPs, such as us, may be put at a competitive disadvantage because we rely heavily on market prices rather than governmental subsidies or regulatory assurances.

MANAGEMENT DISCUSSION FROM LATEST 10K

EXECUTIVE OVERVIEW

Our Business

We are an independent power producer that operates and develops clean and reliable power generation facilities primarily in the U.S. Our fleet of power generation facilities, with nearly 24,000 MW of capacity as of December 31, 2007, makes us one of the largest independent power producers in the U.S. Our portfolio is comprised of two power generation technologies: natural gas-fired combustion (primarily combined-cycle) and renewable geothermal. We operate 60 natural gas-fired power facilities located in the West (approximately 6,521 MW, primarily in California), Texas (approximately 7,487 MW), Southeast (approximately 6,254 MW) and North (approximately 2,822 MW). We also operate 17 geothermal facilities in the Geysers region of northern California capable of producing 725 MW, which are reported within our West segment. Our renewable geothermal facilities are the largest producing geothermal resource in the U.S.

We are focused on maximizing value by leveraging our portfolio of power plants, our geographic diversity and our operational and commercial expertise to provide the optimal combination of products and services to our customers. To accomplish this goal, we seek to maximize asset performance, optimize the management of our commodity exposure and take advantage of growth and development opportunities that fit our core business and are accretive to earnings.

During 2006 and 2007, and through the Effective Date, we conducted our business in the ordinary course as debtors-in-possession under the protection of the Bankruptcy Courts. We emerged from Chapter 11 on January 31, 2008, as described below in “— Our Emergence From Chapter 11.”

Our Business Segments

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. Accordingly, our reportable segments are West (including geothermal), Texas, Southeast, North and Other. Our “Other” segment includes fuel management, our turbine maintenance group, our TTS and PSM businesses prior to their sale and certain hedging and other corporate activities.

We use the non-GAAP financial measure “commodity margin” to assess our financial performance on a consolidated basis and by our reportable segments. Commodity margin includes our electricity and steam revenues, hedging and optimization activities, renewable energy credit revenue, transmission revenue and expenses, and fuel and purchased energy expenses, but excludes mark-to-market activity and other service revenues. We believe that commodity margin is a useful tool for assessing the performance of our core operations and is a key operational measure reviewed by our chief operating decision maker. Commodity margin is not a measure calculated in accordance with GAAP, and should be viewed as a supplement to and not a substitute for our results of operations presented in accordance with GAAP. Commodity margin does not purport to represent net income (loss), the most comparable GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly-titled measures reported by other companies. See “— Results of Operations for the Years Ended December 31, 2007 and 2006 — Consolidated Commodity Margin” and “— Results of Operations for the Years Ended December 31, 2006 and 2005 — Consolidated Commodity Margin” for a reconciliation of commodity margin to our GAAP results.

Our Key Financial Performance Drivers

Our commodity margin and cash flows from operations are primarily derived from the sale of electricity and electricity-related products generated predominantly from our natural gas-fired power generation portfolio. Thus, the spread between natural gas prices and power prices contributes significantly to our financial results and is the primary component of our commodity margin. Natural gas prices, weather, generation outages and reserve margins have the most significant impact on our commodity margin due to the impact each has on our power prices and natural gas costs resulting from changes in supply and demand. In addition, our plant operating performance and availability are key to our performance.

Natural gas prices and power prices are generally correlated in our two primary markets, the West and Texas, because plants using natural gas-fired technology tend to be the marginal or price-setting generation units in these regions. Holding other factors constant, where natural gas is the price-setting fuel, higher natural gas prices tend to increase our commodity margin. This is because our combined-cycle plants are more fuel-efficient than many other older gas-fired technologies and peaking units. The older units with higher operating costs often set power prices in our West and Texas regions, creating positive commodity margin for us. However, the positive relationship between natural gas prices and our commodity margin does not take into account the effects of our fixed-price PPAs and will tend to break down where natural gas-fired units are not on the margin such as is often seen in the off-peak periods or in markets where non-gas-fired capacity can satisfy the majority of the demand. Our geothermal units do not consume natural gas, and, because there is a direct relationship between power prices and natural gas prices in the West, increases in natural gas prices generally benefit our geothermal units.

Weather could have a significant short-term impact on supply and demand. In addition, a disproportionate amount of our total revenue is realized during our third fiscal quarter and we expect this trend to continue in the future as U.S. demand for electricity peaks during this time. Typically, demand for and the price of electricity is higher in the summer and winter seasons when temperatures are more extreme, and therefore, our revenues and commodity margin could be negatively impacted due to relatively cool summers or mild winters.

Generation outages and reserve margins also impact supply and demand and the price for electricity, particularly in markets where reserve margins are low or transmission constraints require that baseload generation be served from generation units operating within that market (such as in the West). In addition, efficient operation of our fleet creates the opportunity to capture commodity margin in a cost effective manner. However, unplanned outages during periods of positive commodity margin could result in a loss of such opportunity. We generally measure our fleet performance based on our availability factors, Heat Rate and plant operating expense. The higher our availability factor, the better positioned we are to capture commodity margin. The less natural gas we must consume for each MWh of electricity generated, the lower our Heat Rate and the higher our commodity margin. See “— Operating Performance Metrics” for additional information.

Our non-operating income and expenses are primarily driven by our financing and restructuring activities. Prior to recording the post-petition interest on LSTC in December of 2007, interest expense related to LSTC was reported only to the extent that it was paid during the pendency of the Chapter 11 cases, was permitted by the Cash Collateral Order or pursuant to orders of the U.S. Bankruptcy Court or was deemed probable of payment. In particular, we made periodic cash adequate protection payments to the holders of Second Priority Debt. We continued to pay the contractual interest on debt not subject to compromise which generally consisted of the project finance facilities of our Non-Debtors. Following the Effective Date, interest expense is accrued on all of our outstanding debt, most significantly the amounts outstanding under our Exit Facilities.

As a result of our restructuring activities, we have incurred substantial expenses or reorganization items which represent the direct and incremental costs related to our Chapter 11 cases such as professional fees, pre-petition liability claim adjustments and losses that are probable and can be estimated, net of interest income earned on cash accumulated during the Chapter 11 cases, gains on the sale of assets or resulting from certain settlement agreements related to our restructuring activities and accruals for emergence incentives and employee severance costs related to our restructuring. Following the Effective Date, any additional income or expense resulting from the implementation of our Plan of Reorganization is included in our operating income (loss).

Our Financial Performance Highlights

During 2007, we recognized net income of $2.7 billion compared to a net loss of $1.8 billion during 2006. Our current year net income primarily resulted from (i) a gain of $4.1 billion in reorganization items related to the Canadian Settlement Agreement, which significantly reduced our obligations under Calpine Corporation’s guarantee of debt issued by certain Canadian Debtors that were deconsolidated in 2005 and (ii) gains from asset sales during 2007. These gains were partially offset by an increase in interest expense of $765 million primarily due to the accrual of post-petition interest expense and an increase in reorganization items for contract rejection and repudiation activities, allowed claim settlements primarily for make whole and other damages claims, asset impairments and costs associated with the refinancing of the Original DIP Facility and repayment of the CalGen Secured Debt.

During 2007, we recognized commodity margin of $2,225 million, an increase of 10% over the same period in 2006. Our gross profit during 2007 was $895 million, as compared to $740 million during 2006. The increase in our core earnings was primarily related to our increase in commodity margin.

Our Emergence from Chapter 11

We emerged from Chapter 11 on January 31, 2008. We were able to meet every critical milestone during our restructuring process and stay on our timeline for emergence pursuant to a comprehensive Plan of Reorganization which, after settlements with certain stakeholders, all classes of creditors voted to approve. Our Plan of Reorganization provides for the discharge of claims through the issuance of reorganized Calpine Corporation common stock, cash and cash equivalents, or a combination thereof. On or about the Effective Date, we canceled all of our then outstanding common stock and authorized the issuance of 485 million shares of reorganized Calpine Corporation common stock for distribution to holders of unsecured claims and for general contingencies pursuant to our Plan of Reorganization. In addition, we issued warrants to purchase 48.5 million shares of reorganized Calpine Corporation common stock to the holders of our previously outstanding common stock that had been canceled on the Effective Date. Our reorganized Calpine Corporation common stock has been re-listed on the NYSE and began “regular way” trading under the symbol “CPN” on February 7, 2008.

efficient operation of our fleet creates the opportunity to capture commodity margin in a cost effective manner. However, unplanned outages during periods of positive commodity margin could result in a loss of such opportunity. We generally measure our fleet performance based on our availability factors, Heat Rate and plant operating expense. The higher our availability factor, the better positioned we are to capture commodity margin. The less natural gas we must consume for each MWh of electricity generated, the lower our Heat Rate and the higher our commodity margin. See “— Operating Performance Metrics” for additional information.

Our non-operating income and expenses are primarily driven by our financing and restructuring activities. Prior to recording the post-petition interest on LSTC in December of 2007, interest expense related to LSTC was reported only to the extent that it was paid during the pendency of the Chapter 11 cases, was permitted by the Cash Collateral Order or pursuant to orders of the U.S. Bankruptcy Court or was deemed probable of payment. In particular, we made periodic cash adequate protection payments to the holders of Second Priority Debt. We continued to pay the contractual interest on debt not subject to compromise which generally consisted of the project finance facilities of our Non-Debtors. Following the Effective Date, interest expense is accrued on all of our outstanding debt, most significantly the amounts outstanding under our Exit Facilities.

As a result of our restructuring activities, we have incurred substantial expenses or reorganization items which represent the direct and incremental costs related to our Chapter 11 cases such as professional fees, pre-petition liability claim adjustments and losses that are probable and can be estimated, net of interest income earned on cash accumulated during the Chapter 11 cases, gains on the sale of assets or resulting from certain settlement agreements related to our restructuring activities and accruals for emergence incentives and employee severance costs related to our restructuring. Following the Effective Date, any additional income or expense resulting from the implementation of our Plan of Reorganization is included in our operating income (loss).

Our Financial Performance Highlights

During 2007, we recognized net income of $2.7 billion compared to a net loss of $1.8 billion during 2006. Our current year net income primarily resulted from (i) a gain of $4.1 billion in reorganization items related to the Canadian Settlement Agreement, which significantly reduced our obligations under Calpine Corporation’s guarantee of debt issued by certain Canadian Debtors that were deconsolidated in 2005 and (ii) gains from asset sales during 2007. These gains were partially offset by an increase in interest expense of $765 million primarily due to the accrual of post-petition interest expense and an increase in reorganization items for contract rejection and repudiation activities, allowed claim settlements primarily for make whole and other damages claims, asset impairments and costs associated with the refinancing of the Original DIP Facility and repayment of the CalGen Secured Debt.

During 2007, we recognized commodity margin of $2,225 million, an increase of 10% over the same period in 2006. Our gross profit during 2007 was $895 million, as compared to $740 million during 2006. The increase in our core earnings was primarily related to our increase in commodity margin.

Our Emergence from Chapter 11

We emerged from Chapter 11 on January 31, 2008. We were able to meet every critical milestone during our restructuring process and stay on our timeline for emergence pursuant to a comprehensive Plan of Reorganization which, after settlements with certain stakeholders, all classes of creditors voted to approve. Our Plan of Reorganization provides for the discharge of claims through the issuance of reorganized Calpine Corporation common stock, cash and cash equivalents, or a combination thereof. On or about the Effective Date, we canceled all of our then outstanding common stock and authorized the issuance of 485 million shares of reorganized Calpine Corporation common stock for distribution to holders of unsecured claims and for general contingencies pursuant to our Plan of Reorganization. In addition, we issued warrants to purchase 48.5 million shares of reorganized Calpine Corporation common stock to the holders of our previously outstanding common stock that had been canceled on the Effective Date. Our reorganized Calpine Corporation common stock has been re-listed on the NYSE and began “regular way” trading under the symbol “CPN” on February 7, 2008.

Financial Reporting Matters and Comparability Related to our Emergence

As of the Petition Date, we deconsolidated most of our Canadian and other foreign entities as we determined that the administration of the CCAA proceedings in a jurisdiction other than that of the U.S. Debtors resulted in a loss of the elements of control necessary for consolidation. On February 8, 2008, the Canadian Effective Date, the proceedings under the CCAA were terminated and accordingly, these entities were reconsolidated, which consisted of a 50% ownership interest in the 50-MW Whitby Cogeneration power plant, approximately $34 million of debt and various working capital items. Because the reconsolidation occurred after December 31, 2007, our Consolidated Financial Statements contained herein exclude the financial statements of the Canadian Debtors and the information in this Report principally describes the Chapter 11 cases and only describes the CCAA proceedings where they have a material effect on our operations or where such information provides necessary background information.

In connection with our emergence from Chapter 11, we recorded certain “plan effect” adjustments to our Consolidated Balance Sheet as of the Effective Date in order to reflect certain provisions of our Plan of Reorganization. These “plan effect” adjustments included the distribution of approximately $4.1 billion in cash and the authorized issuance of 485 million shares of reorganized Calpine Corporation common stock primarily for the discharge of LSTC, repayment of the Second Priority Debt and for various other administrative and other post-petition claims. As a result, we estimate that our equity will increase by approximately $8.8 billion.

Future Performance Indicators

Our historical financial performance during the pendency of the Chapter 11 cases and CCAA proceedings is likely not indicative of our future financial performance because, among other things: (i) we generally have not accrued interest expense on our debt classified as LSTC during the pendency of our Chapter 11 cases, except pursuant to orders of the U.S. Bankruptcy Court and post-petition interest expense included in our Plan of Reorganization and accrued during the fourth quarter of 2007; (ii) we have and expect to further dispose of, or restructure agreements relating to, certain plants that do not generate positive cash flow or which are otherwise considered non-strategic; (iii) we have implemented overhead reduction programs, including staff reductions and non-core office closures; (iv) we have rejected, repudiated or terminated certain unprofitable or burdensome contracts and leases; (v) we have been able to assume certain beneficial contracts and leases (vi) on February 8, 2008, we reconsolidated certain Canadian and other foreign subsidiaries that had been deconsolidated during 2006 and 2007 as a result of the CCAA proceedings; during the period they were deconsolidated, we accounted for our investment in such entities under the cost method. See Notes 2 and 3 of the Notes to Consolidated Financial Statements for further information.

RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2007 AND 2006

Set forth below are the results of operations for the year ended December 31, 2007, as compared to the same period in 2006 (in millions, except for unit pricing information and percentages). In the comparative tables below, increases in revenue/income or decreases in expense (favorable variances) are shown without brackets while decreases in revenue/income or increases in expense (unfavorable variances) are shown with brackets in the “$ Change” and “% Change” columns.

Operating revenues increased primarily as a result of a 9% increase in generation for the year ended December 31, 2007, compared to the same period in 2006, and a 48% increase in hedging and optimization revenues in 2007 as compared to 2006. The reduction in the availability of credit and the termination or disruption of certain customer relationships due to our Chapter 11 filings and reduced generation in 2006 had curtailed the amount of hedging and optimization activity during that period while these conditions were less of a factor in 2007. These factors were partially offset by lower mark-to-market gains on undesignated derivative electricity contracts, which declined by $79 million year over year.

Fuel and purchased energy expenses increased due to higher generation and a 13% increase in the average cost of natural gas consumed for the year ended December 31, 2007, compared to the year ended December 31, 2006. Also contributing to the increase was higher hedging and optimization expenses due to the higher level of such activity in 2007 compared to 2006.

Operating plant impairments of $44 million during the year ended December 31, 2007, were recorded primarily for the Bethpage Power Plant resulting from the expected adverse impact on electric power pricing of new electric power transmission capacity from the PJM market into Long Island. Our operating plant impairments for the year ended December 31, 2006, consisted primarily of a $50 million impairment relating to Fox Energy Center. Certain impairment charges related to our restructuring activities were also recorded during the year ended December 31, 2007, as reorganization items as discussed below.

Other cost of revenue decreased for the year ended December 31, 2007, compared to the year ended December 31, 2006, resulting primarily from lower operating lease expense and lower cost of revenue at PSM, which was sold in March of 2007.

Equipment, development project and other impairments decreased primarily due to the non-recurrence of $65 million in impairment charges recorded for the year ended December 31, 2006, related to certain turbine-generator equipment not assigned to projects for which we determined near-term sales were likely. During the year ended December 31, 2007, an additional $2 million in impairments were recorded related to these turbines resulting from reduced estimated sales prices.

Sales, general and other administrative expense decreased for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily due to an $11 million net reduction in personnel costs resulting from lower headcount and the sale of PSM in early 2007 as well as lower professional fees and consulting fees of $10 million.

Interest expense increased for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily due to $376 million in post-petition interest related to the ULC I notes resulting from the Canadian Settlement Agreement and $347 million in post-petition interest related to other pre-petition obligations recorded during the year ended December 31, 2007, while no similar expense was recorded in the prior year. We also recorded $126 million in default interest in late 2007 related to various settlements reached as well as expected allowed claims for default interest on the CalGen Second Lien Debt and CalGen Third Lien Debt. This was partially offset by the net effect of the refinancings of the CalGen Secured Debt and the Original DIP Facility in late March 2007 primarily using proceeds under the DIP Facility, which carried lower interest rates, and by the repayment of the First Priority Notes in May and June of 2006 using restricted cash and funds available under the Original DIP Facility, which also carried lower interest rates. The total increase in interest expense was also partially offset by a $43 million decrease due to the extinguishment of certain project financing debt as a result of our asset sales, principally related to the Fox Energy Center and Aries Power Plant.

Other (income) expense, net increased for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily as a result of $135 million in income pertaining to a claim settlement with a customer which received court approval during the year ended December 31, 2007. The claim, which was approved by the court hearing the customer’s bankruptcy case, related to the customer’s rejection of our energy services agreement following the customer’s bankruptcy filing, which was unrelated to our Chapter 11 cases.

Provision for Expected Allowed Claims — During the year ended December 31, 2007, our provision for expected allowed claims consisted primarily of (i) a $4.1 billion credit related to the settlement of claims related to Calpine Corporation’s guarantee of the ULC I notes and the release of our guarantee of the ULC II notes following repayment of those notes in September 2007, (ii) accruals totaling $275 million for make whole premiums and/or damages related to the First Priority Notes, Second Priority Debt and Unsecured Notes settlements, (iii) $141 million resulting from the termination of the RockGen operating lease agreement and write-off of the related prepaid lease expense, (iv) $112 million resulting from the repudiation of a gas transportation contract, (v) a $99 million credit resulting from the negotiated settlement of certain repudiated gas transportation contracts, (vi) $85 million related to the settlement agreement with Cleco as a result of the rejection of two PPAs for the output of the Acadia Energy Center, and (vii) an additional accrual of $79 million resulting from the rejection of certain leases and other agreements related to the Rumford and Tiverton power plants for which we agreed to allow general unsecured claims in the aggregate of $190 million. During the year ended December 31, 2006, our provision for expected allowed claims related primarily to repudiated gas transportation and power transmission contracts, the rejection of the Rumford and Tiverton power plant leases and the write-off of prepaid lease expense and certain fees and expenses related to the transaction.

Gains on Asset Sales — During the year ended December 31, 2007, gains on asset sales primarily resulted from the sales of the Aries Power Plant, Goldendale Energy Center, PSM and Parlin Power Plant. During the year ended December 31, 2006, gains on asset sales primarily resulted from the sale of the Dighton Power Plant and Fox Energy Center. See Note 7 of the Notes to Consolidated Financial Statements for further information.

Asset Impairments — During the year ended December 31, 2007, asset impairment charges consisted primarily of a pre-tax, predominately non-cash impairment charge of approximately $89 million in reorganization items to record our interest in Acadia PP at fair value less cost to sell. See Note 7 of the Notes to Consolidated Financial Statements for further information.

DIP Facility Financing and CalGen Secured Debt Repayment Costs — During the year ended December 31, 2007, we recorded costs related to the refinancing of our Original DIP Facility and repayment of the CalGen Secured Debt consisting of (i) $52 million of DIP Facility transaction costs, (ii) the write-off of $32 million in unamortized discount and deferred financing costs related to the CalGen Secured Debt and (iii) $76 million as our estimate of the expected allowed claims resulting from the unsecured claims for damages granted to the holders of the CalGen Secured Debt. During the year ended December 31, 2007, we also recorded transaction costs of $22 million related to the execution of a commitment letter to fund additional exit financing as well as $13 million for secured shortfall claims relating to settlements for the First Priority Notes and the CalGen First Lien Debt. See Note 8 of the Notes to Consolidated Financial Statements for further information.

Professional Fees — The increase in professional fees for the year ended December 31, 2007, over the comparable period in 2006 resulted primarily from an increase in activity managed by our third party advisors related to our Plan of Reorganization, litigation and claims reconciliation matters.

Other — Other reorganization items increased primarily due to a $156 million increase in foreign exchange losses on LSTC denominated in a foreign currency over the comparable period in the prior year.

Provision (benefit) for income taxes — For the year ended December 31, 2007, we recorded a tax benefit of approximately $546 million consisting primarily of $485 million related to the release of valuation allowance. See Note 9 of the Notes to Consolidated Financial Statements for further information regarding our income taxes.

MANAGEMENT DISCUSSION FOR LATEST QUARTER

Executive Overview

We are an independent power producer that operates and develops clean and reliable power generation facilities primarily in the U.S. Our fleet of power generation facilities, with nearly 24,000 MW of capacity as of June 30, 2008, makes us one of the largest independent power producers in the U.S. Our portfolio is comprised of two power generation technologies: natural gas-fired combustion (primarily combined-cycle) and renewable geothermal. We operate 60 natural gas-fired power plants capable of producing approximately 23,000 MW and 17 geothermal facilities in the Geysers region of northern California capable of producing 725 MW. Our renewable geothermal facilities are the largest producing geothermal resource in the U.S.

We are focused on maximizing the value of the Company by leveraging our portfolio of power plants, our geographic diversity and our operational and commercial expertise to provide the optimal combination of products and services to our customers. To accomplish this goal, we seek to maximize asset performance, optimize the management of our commodity exposure and take advantage of growth and development opportunities that fit our core business and are accretive to earnings.

Our Financial Performance Highlights

During the three months ended June 30, 2008, we recognized net income of $197 million compared to a net loss of $(500) million during the same period a year ago. Our current period net income primarily resulted from higher market spark spreads in our West and Texas segments and a decrease in reorganization items as a result of our emergence from Chapter 11 during the first quarter of 2008. Also contributing to our improved results in our Southeast segment was additional revenue of $21 million recognized related to a transmission capacity contract that was approved by the FERC during the three months ended June 30, 2008.

During the six months ended June 30, 2008, we recognized a net loss of $(17) million compared to a net loss of $(959) million during the same period a year ago. The reduction in our current period net loss primarily resulted from higher market spark spreads in our West and Texas segments during the three months ended June 30, 2008, and a decrease in reorganization items as a result of our emergence from Chapter 11, gain on reconsolidation of our Canadian Debtors and gains on sales of our Fremont and Hillabee assets during the first quarter of 2008. Also contributing to our improved results in our Southeast segment was additional revenue of $21 million recognized related to a transmission capacity contract that was approved by the FERC during the three months ended June 30, 2008.

NRG Proposal

On May 14, 2008, we received an unsolicited proposal from NRG regarding a potential combination between the Company and NRG. The terms of NRG’s proposal included an all-stock merger transaction at a fixed exchange ratio of 0.534x. On May 30, 2008, we announced that our Board of Directors had determined that NRG’s proposal was inadequate and materially undervalued our unique asset portfolio and future prospects. We and NRG, and our respective advisors, subsequently exchanged certain information in order to ascertain whether there was a basis for discussions between us and NRG to explore a business combination. Following the exchange of certain information, we determined that there was no basis for entering into discussions regarding a potential business combination with NRG.

Financial Reporting Matters Following Our Emergence from Chapter 11

During the three and six month periods ended June 30, 2007, and for the period January 1, 2008, through the Effective Date, we conducted our business in the ordinary course as debtors-in-possession under the protection of the Bankruptcy Courts. We emerged from Chapter 11 on January 31, 2008. Our Plan of Reorganization provided for the discharge of claims through the issuance of reorganized Calpine Corporation common stock, cash and cash equivalents, or a combination thereof. On or about the Effective Date, we canceled all of our then outstanding common stock and authorized the issuance of 485 million shares of reorganized Calpine Corporation common stock for distribution to holders of unsecured claims and for general contingencies pursuant to our Plan of Reorganization. In addition, we issued warrants to purchase approximately 48.5 million shares of reorganized Calpine Corporation common stock to the holders of our previously outstanding common stock that had been canceled on the Effective Date. Our reorganized Calpine Corporation common stock has been listed on the NYSE and began “regular way” trading under the symbol “CPN” on February 7, 2008.

At the Petition Date, we carried $17.4 billion of debt with an average interest rate of 10.3%. As a result of retiring unsecured debt with reorganized Calpine Corporation common stock, proceeds received from the sale of certain of our assets and the repayment or refinancing of certain of our project debt, we have reduced our pre-petition debt by approximately $7.0 billion. On the Effective Date, we closed on our approximately $7.3 billion of Exit Facilities. We borrowed approximately $6.4 billion under our Exit Facilities, which was used to repay the outstanding term loan balance of $3.9 billion (excluding the unused portion under the $1.0 billion revolver) under our DIP Facility. The remaining net proceeds of approximately $2.5 billion were used to fund cash payment obligations under the Plan of Reorganization including the repayment of a portion of the Second Priority Debt and the payment of administrative claims and other pre-petition claims, as well as to pay fees and expenses in connection with the Exit Facilities and for working capital and general corporate purposes. Upon our emergence from Chapter 11, we carried $10.4 billion of debt with an average interest rate of 8.1%.

On February 8, 2008, the Canadian Effective Date, the Canadian Court ordered and declared that the proceedings under the CCAA were terminated. The termination of the proceedings of the CCAA and our emergence under the Plan of Reorganization allowed us to maintain our equity interest in the Canadian Debtors and other foreign entities, whose principal net assets include debt, various working capital items and a 50% ownership interest in Whitby, an equity method investment. As a result, we regained control over our Canadian Debtors which were reconsolidated into our Consolidated Condensed Financial Statements as of the Canadian Effective Date.

We accounted for the reconsolidation under the purchase method in a manner similar to a step acquisition. The excess of the fair market value of the reconsolidated net assets over the carrying value of our investment balance of $0 amounted to approximately $107 million. We recorded the Canadian assets acquired and the liabilities assumed based on their estimated fair value, with the exception of Whitby. We reduced the fair value of our Whitby equity investment (approximately $37 million) to $0 and recorded the $70 million balance of the excess as a gain in reorganization items on our Consolidated Condensed Statement of Operations in the first quarter of 2008.

In connection with our emergence from Chapter 11, we recorded certain “plan effect” adjustments to our Consolidated Condensed Balance Sheet as of the Effective Date in order to reflect certain provisions of our Plan of Reorganization. These adjustments included the distribution of approximately $4.1 billion in cash and the authorized issuance of 485 million shares of reorganized Calpine Corporation common stock as described above. As a result, our equity increased by approximately $8.9 billion.

During the pendency of the Chapter 11 cases, we began an asset rationalization process that resulted in the sale of certain under-performing assets and non-core businesses. We sold the assets of the Hillabee and Fremont development projects for which construction had been suspended and recorded pre-tax gains of approximately $199 million as reorganization items related to these asset sales during the first quarter of 2008. The proceeds from these two sales were used to retire the $300 million drawn under our Bridge Facility. We believe these actions will allow us to compete more effectively in the future in the markets in which we operate.

Results of Operations for the Three Months Ended June 30, 2008 and 2007

Set forth below are the results of operations for the three months ended June 30, 2008, as compared to the same period in 2007 (in millions). In the comparative tables below, increases in revenue/income or decreases in expense (favorable variances) are shown without brackets while decreases in revenue/income or increases in expense (unfavorable variances) are shown with brackets in the “$ Change” and ‘‘% Change” columns.

Operating revenues increased primarily as a result of a 39% increase in our average realized electric price for the three months ended June 30, 2008, compared to the same period in 2007. As a result, our electricity and steam revenue as well as hedging and optimization revenue, both components of our operating revenues, increased by $601 million, or 41%, and $325 million, or 72%, respectively, during the three months ended June 30, 2008, compared to 2007. These increases were partially offset by mark-to-market losses on derivative electricity contracts that do not qualify for hedge accounting, which totaled $8 million for the second quarter of 2008 compared to mark-to-market gains of $147 million for the second quarter of 2007.

Fuel and purchased energy expense increased due to a 31% increase in the average cost of natural gas consumed as well as a $347 million, or 98%, increase in hedging and optimization expense for the three months ended June 30, 2008, compared to the three months ended June 30, 2007. The increase was partially offset by mark-to-market gains on derivative natural gas contracts that do not qualify for hedge accounting, which totaled $32 million for the second quarter of 2008 compared to mark-to-market losses of $94 million for the second quarter of 2007.

Plant operating expense decreased during the three months ended June 30, 2008, compared to the same period in 2007 primarily as a result of a $7 million decrease in insurance costs due to increased recoveries in the second quarter of 2008, a $3 million decrease in property taxes and a $4 million decrease in expense for major maintenance and parts repair costs. The decrease was partially offset by an $8 million increase in routine maintenance costs.

Depreciation and amortization expense decreased for the three months ended June 30, 2008, compared to the three months ended June 30, 2007, primarily related to a revision in the estimated useful life for our geothermal facilities in the Geysers region of northern California as well as the sale of Acadia PP in September 2007.

Other cost of revenue decreased for the three months ended June 30, 2008, compared to the three months ended June 30, 2007, resulting primarily from a decrease in operating lease expense due to the termination of the lease associated with our purchase of the RockGen Energy Center in January 2008.

Sales, general and other administrative expenses were higher for the three months ended June 30, 2008, compared to the same period in 2007 due to a $5 million increase in personnel costs due primarily to higher stock compensation expense arising from the grant of equity awards during the first quarter of 2008 as well as a $4 million increase in consulting expenses.

Other operating (income) expense decreased for the three months ended June 30, 2008, compared to the three months ended June 30, 2007, primarily due to a $15 million increase in income from our investment in OMEC resulting from gains on interest rate swaps entered into by OMEC. Partially offsetting the decrease was a $6 million impairment related to the discontinuation of the development of a power project recorded during the three months ended June 30, 2008.

Interest expense decreased for the three months ended June 30, 2008, compared to the three months ended June 30, 2007, due largely to lower average debt balances and lower interest rates. During the first quarter of 2008, we settled a portion of our debt through payment of cash and issuance of reorganized Calpine Corporation common stock pursuant to the Plan of Reorganization. Additionally, interest rates on our variable rate debt were lower for the three months ended June 30, 2008, compared to 2007, due to a decrease in LIBOR over the same periods. The decrease was partially offset by losses recorded on interest rate swaps related to our Exit Credit Facility during the three months ended June 30, 2008.

Other (income) expense, net increased primarily due to $6 million for the write-off of unamortized deferred financing costs and other costs associated with the refinancing of our Metcalf term loan facility and preferred interests in June 2008.

Provision for Expected Allowed Claims — During the three months ended June 30, 2008, we recorded $5 million in miscellaneous charges related to Chapter 11 claims. During the three months ended June 30, 2007, our provision for expected allowed claims consisted primarily of (i) $85 million related to the settlement agreement with Cleco as a result of the rejection of two PPAs for the output of the Acadia Energy Center, (ii) an additional accrual of $81 million resulting from the rejection of certain leases and other agreements related to the Rumford and Tiverton power plants for which we agreed to allow general unsecured claims in the aggregate of $190 million and (iii) $65 million resulting from a stipulated settlement related to the RockGen facility.

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