UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

Commission file number: 1-12079

Calpine Corporation

(A Delaware Corporation)

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

50 West San Fernando Street

San Jose, California 95113

Telephone: (408) 995-5115

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

Calpine Corporation Common Stock, $.001 Par Value Registered on the New York Stock Exchange

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

None

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

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

      Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act).     Yes þ          No o

      State the aggregate market value of the common equity held by non-affiliates of the registrant as of June 30, 2004, the last business day of the registrant’s most recently completed second fiscal quarter: approximately $1.9 billion. Common stock outstanding as of March 30, 2005: 538,017,458 shares.

DOCUMENTS INCORPORATED BY REFERENCE

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

FORM 10-K

ANNUAL REPORT

For the Year Ended December 31, 2004

TABLE OF CONTENTS

PART I

      In addition to historical information, this report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. 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) the timing and extent of deregulation of energy markets and the rules and regulations adopted with respect thereto, (ii) the timing and extent of changes in commodity prices for energy, particularly natural gas and electricity, and the impact of related derivatives transactions, (iii) unscheduled outages of operating plants, (iv) unseasonable weather patterns that reduce demand for power, (v) economic slowdowns that can adversely affect consumption of power by businesses and consumers, (vi) various development and construction risks that may delay or prevent commercial operations of new plants, such as failure to obtain the necessary permits to operate, failure of third-party contractors to perform their contractual obligations or failure to obtain project financing on acceptable terms, (vii) uncertainties associated with cost estimates, that actual costs may be higher than estimated, (viii) development of lower-cost power plants or of a lower cost means of operating a fleet of power plants by our competitors, (ix) risks associated with marketing and selling power from power plants in the evolving energy market, (x) factors that impact exploitation of oil or gas resources, such as the geology of a resource, the total amount and costs to develop recoverable reserves, and legal title, regulatory, gas administration, marketing and operational factors relating to the extraction of natural gas, (xi) uncertainties associated with estimates of oil and gas reserves, (xii) the effects on our business resulting from reduced liquidity in the trading and power generation industry, (xiii) our ability to access the capital markets on attractive terms or at all, (xiv) uncertainties associated with estimates of sources and uses of cash, that actual sources may be lower and actual uses may be higher than estimated, (xv) the direct or indirect effects on our business of a lowering of our credit rating (or actions we may take in response to changing credit rating criteria), including increased collateral requirements, refusal by our current or potential counterparties to enter into transactions with us and our inability to obtain credit or capital in desired amounts or on favorable terms, (xvi) present and possible future claims, litigation and enforcement actions, (xvii) effects of the application of regulations, including changes in regulations or the interpretation thereof, and (xviii) other risks identified in this report. Current information set forth in this filing has been updated to March 30, 2005, and we undertake no duty to further update this information. All other information in this filing is presented as of the specific date noted and has not been updated since that time.

      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 450 Fifth Street, N.W., 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 450 Fifth Street, N.W., 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, 50 West San Fernando Street, San Jose, California 95113, attention: Lisa M. Bodensteiner, Assistant Secretary, telephone: (408) 995-5115. We will not send exhibits to the documents, unless the exhibits are specifically requested and you pay our fee for duplication and delivery.

OVERVIEW

      We are an integrated power company with a comprehensive and growing power services business. Based in San Jose, California, we were established as a corporation in 1984 and operate through a variety of divisions, subsidiaries and affiliates. We own and operate power generation facilities and sell electricity, predominantly in the United States but also in Canada and the United Kingdom. We focus on two efficient and clean types of power generation technologies: natural gas-fired combustion turbine and geothermal. We lease and operate a significant fleet of geothermal power plants at The Geysers in California, and have a net operating portfolio of 92 clean burning natural gas power plants capable of producing 26,649 megawatts (“MW”) and an additional 11 plants in construction. We offer to third parties energy procurement, liquidation and risk management services through Calpine Energy Services, L.P. (“CES”) and offer combustion turbine component parts and repair and maintenance services world-wide through Calpine Turbine Services (“CTS”), which includes Power Systems Mfg., LLC (“PSM”) located in Jupiter, Florida, and Netherlands-based Thomassen Turbine Systems B.V. (“TTS”). We also offer engineering, procurement, construction management, commissioning and operations and maintenance (“O&M”) services through Calpine Power Services, Inc. (“CPSI”).

      Our integrated operating capabilities have given us a proven track record in the development and construction of new power facilities. Our Calpine Construct organization consists of an experienced team of construction management professionals who ensure that our projects are built using our standard design specifications reflecting our exacting operational standards. We have established relationships with leading equipment manufacturers for gas turbine generators, steam turbine generators, heat recovery steam generators and other key equipment. While future projects will be developed only when we have attractive power contracts in place, we will continue to leverage these capabilities and relationships to ensure that our power plants are completed on time and are the best built and lowest cost energy facilities possible.

      We have a sophisticated O&M organization based in Folsom, California which staffs and oversees the commissioning and operations of our power plants. With the objective of enhancing the performance of our modern portfolio of gas-fired power plants and lowering our replacement parts and maintenance costs, we capitalize on PSM’s capabilities to design and manufacture high performance combustion system and turbine blade parts. PSM manufactures new vanes, blades, combustors and other replacement parts for our plants and for those owned and operated by third parties as well. It offers a wide range of Low Emissions Combustion (“LEC”) systems and advanced airfoils designed to be compatible for retrofitting or replacing existing combustion systems or components operating in General Electric and Siemens Westinghouse turbines.

      We also have in place an experienced gas production and management team which gives us a broad range of fuel sourcing options, and we own 389 billion cubic feet equivalent (“Bcfe”) of net proved natural gas reserves located primarily in the Sacramento Basin of California and Gulf Coast regions of the United States. We are currently (as of March 2005) capable of producing, net to Calpine’s interest, approximately 100 million cubic feet equivalent (“MMcfe”) of natural gas per day.

      CES provides us with the trading and risk management services needed to schedule power sales and to ensure fuel is delivered to our power plants on time to meet delivery requirements and to manage and optimize the value of our physical power generation and gas production assets. CES currently manages approximately 3% of the U.S. gas and power demand. Our marketing and sales organization complements CES’s activities and is organized not only to serve our traditional load serving client base of local utilities, municipalities and cooperatives but also to meet the needs of our growing list of wholesale and large retail customers. As a general goal, we seek to have 65% of our available capacity sold under long-term contracts or hedged by our risk management group. Currently we have 54% of our available capacity sold or hedged for 2005.

      Additionally, we continue to strengthen our system operations management and information technology capabilities to enhance the economic performance of our portfolio of assets in our major markets and to provide load-following and ancillary services to our customers. These operational optimization systems, combined with our sales, marketing and risk management capabilities, enable us to add value to traditional commodity products.

      Through our development and construction program and past acquisitions, we have built and now operate a modern and efficient portfolio of gas-fired generation assets. Our low cost position, integrated operations and skill sets have allowed us to weather a multi-year downturn in the North American energy industry. We have demonstrated the flexibility to adapt to fundamental market changes. Specifically, we responded to the market downturn by reducing capital expenditures, selling or monetizing various gas, power and contractual assets, restructuring our equipment procurement obligations, and reorganizing to reflect our transition from a development focused company to a company focused on integrated operations and services.

THE MARKET FOR ELECTRICITY

      The electric power industry represents one of the largest industries in the United States and impacts nearly every aspect of our economy, with an estimated end-user market of nearly $268 billion of electricity sales in 2004 based on information published by the Energy Information Administration of the Department of Energy (“EIA”). Historically, the power generation industry has been largely characterized by electric utility monopolies producing electricity from old, inefficient, polluting, high-cost generating facilities selling to a captive customer base. However, industry trends and regulatory initiatives have transformed some markets into more competitive grounds where load-serving entities and end-users may purchase electricity from a variety of suppliers, including independent power producers (“IPPs”), power marketers, regulated public utilities and others. For the past 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, the power industry continues to transform into a more competitive market.

      The North American Electric Reliability Council (“NERC”) estimates that in the United States, peak (summer) electric demand in 2004 totaled approximately 729,000 MW, while summer generating capacity in 2004 totaled approximately 872,000 MW, creating a peak summer reserve margin of 143,000 MW, or 19.6%, which compares to an estimated peak summer reserve margin of 144,000 MW, or 20.3% in 2003. Historically, utility reserve margins have been targeted to be at least 15% above peak demand to provide for load forecasting errors, scheduled and unscheduled plant outages and local area grid protection. The United States market consists of regional electric markets not all of which are effectively interconnected, so reserve margins vary from region to region.

      Even though most new power plants are fueled by natural gas, the majority of power generated in the U.S. is still produced by coal and nuclear power plants. The EIA has estimated that approximately 50% of the electricity generated in the U.S. is fueled by coal, 20% by nuclear sources, 18% by natural gas, 7% by hydro, and 5% from fuel oil and other sources. As regulations continue to evolve, many of the current coal plants will likely be faced with having to install a significant amount of costly emission control devices. This activity could cause some of the oldest and dirtiest coal plants to be retired, thereby allowing a greater proportion of power to be produced by cleaner natural gas-fired generation.

      Due primarily to the completion of gas-fired combustion turbine projects, we have seen power supplies increase and higher reserve margins in the last several years accompanied by a decrease in liquidity in the energy trading markets.

      According to Edison Electric Institute (“EEI”) published data, the growth rate of overall consumption of electricity in 2004 compared to 2003 was estimated to be 1.9%. The estimated growth rates in our major markets were as follows: South Central (primarily Texas) 3.9%, Pacific Southwest (primarily California) 3.3%, and Southeast 2.5%. The growth rate in supply has been diminishing with many developers canceling or delaying completion of their projects as a result of current market conditions. The supply and demand balance in the natural gas industry continues to be strained with gas prices averaging $6.13 per million British thermal unit (“Btu”) (“MMBtu”) in 2005 through February, compared to averages of approximately $5.72 and $6.20 per MMBtu in the same periods in 2004 and 2003, respectively. In addition, capital market participants are slowly making progress in restructuring their portfolios, thereby stabilizing financial pressures on the industry. Overall, we expect the market to continue these trends and work through the current oversupply of power in several regions within the next few years. As the supply-demand picture improves, we expect to see

spark spreads (the difference between the cost of fuel and electricity revenues) improve and capital markets regain their interest in helping to repower America with clean, highly efficient energy technologies.

STRATEGY

      Our vision is to become North America’s most efficient, cost competitive and environmentally friendly power company with a comprehensive and profitable service business. We believe that with our efficient fleet of power generation facilities and economies of scale, we are positioned to operate profitably and with reasonable volatility as the supply and demand picture improves and we increase the proportion of contractual sales. In achieving our corporate strategic objectives, the number one priority for our company is maintaining the highest level of integrity in all of our endeavors. We have posted on our website (www.calpine.com) our Code of Conduct applicable to all employees, including our principal executive officer, principal financial officer and principal accounting officer. We intend to post on our website any amendment to or waiver from our Code of Conduct required to be disclosed under Item 5.05 of Form 8-K.

      Our timeline to achieve our strategic objectives is partially a function of improvement in market fundamentals. When necessary, we will slow or delay our growth activities in order to ensure that our financial health is secure and our investment opportunities meet our long-term rate of return requirements.

Near-Term Objectives

      Our ability to adapt as needed to market dynamics has led us to develop a set of near-term strategic objectives that will guide our activities as market fundamentals improve. These include:

Longer-Term Objectives

      We plan, through our strategy to (1) achieve the lowest-cost position in the industry by applying our fully integrated areas of expertise to the cost-effective development, construction, financing, fueling and operation of the most modern and efficient power generation facilities and by achieving economies of scale in general, administrative and other support costs, and (2) enhance the value of the power we generate in the marketplace by (a) operating our plants as a system, (b) selling directly to load-serving entities and, to the extent allowable, to industrial customers, in each of the markets in which we participate, (c) offering load-following and other ancillary services to our customers, and (d) providing effective marketing, risk management and asset optimization activities through our CES and marketing and sales organizations.

      Our “system approach” refers to our ability to cluster our standardized, highly efficient power generation assets within a given energy market and to sell the energy from that system of power plants, rather than using “unit specific” marketing contracts. The clustering of standardized power generation assets allows for significant economies of scale to be achieved. Specifically, construction costs, supply chain activities such as inventory and warehousing costs, labor, and fuel procurement costs can all be reduced with this approach. The choice to focus on highly efficient and clean technologies reduces our fuel consumption, a major expense when operating power plants. Furthermore, our lower-than-market heat rate (high efficiency advantage) provides us

a competitive advantage in times of rising fuel prices, and our systems approach to fuel purchases reduces imbalance charges when a plant is forced out of service. Finally, utilizing our system approach in a sales contract allows us to provide power to a customer from whichever plant in the system is most economical at a given period of time. In addition, the operation of plants can be coordinated when increasing or decreasing power output throughout the day to enhance overall system efficiency, thereby enhancing the heat rate advantage already enjoyed by the plants. In total, this approach lays a foundation for a sustainable competitive cost advantage in operating our plants.

      The integration of gas production, hedging, optimization and marketing activities achieves additional cost reductions while simultaneously enhancing revenues. Our fleet of natural gas burning power plants requires a large amount of gas to operate. Our fuel strategy is to supplement purchases of gas with production from our own gas reserves. Owning gas reserves provides a natural hedge against gas price volatility, while providing a secure and reliable source of fuel and lowering our fuel costs over time. The ownership of gas provides our CES risk management organization with additional flexibility when structuring fixed price transactions with our customers.

      Recent trends confirm that both buyers and sellers of power and gas benefit from signing long-term power contracts. By signing long-term power contracts with fixed or heat-rate based pricing (a component of which is the gas index), we are able to reduce our exposure to the severe volatility often seen with power and gas prices. The trend towards signing long-term contracts is creating opportunities for companies, such as ours, that own power plants and gas reserves to negotiate directly with buyers (end users and load serving entities) that need power.

      Our marketing and sales organization is dedicated to serving wholesale and industrial customers with reliable, cost-effective electricity and a full range of services. The organization offers customers: (1) wholesale bulk energy; (2) firm supply energy; (3) fully dispatchable energy; (4) full service requirements energy; (5) renewable energy; (6) energy scheduling services; (7) engineering, construction, O&M services; and (8) turbine parts and long-term maintenance agreements. Our physical, financial and intellectual assets and our generating facilities, pooled into unique energy centers in key markets, enable us to create customizable energy solutions for our customers, delivering power when, where and in the capacity our customers need. Our power marketing experience gives us the know-how to structure innovative deals that meet our customers’ particular requirements. For example, we work with our customers to tailor energy contracts to help them offset pricing risk and other variables. We have developed our “Virtual Power Plant” product which provides customers with an energy resource that is reliable and flexible. It gives customers all of the advantages of owning and operating their own plants without many of the risks, by gaining access to a portfolio of highly efficient generation assets and by implementing our IT solutions to allow power to be dispatched as needed. As of March 2, 2005, our marketing and sales team is pursuing 24,633 MW of active opportunities with 198 customers across the United States and Canada. This customer base includes municipalities, cooperatives, investor owned utilities, industrial customers and commercial customers.

      The ultimate objective of our financing strategy is to achieve and maintain an investment grade credit and bond rating from the major rating agencies. In order to achieve this objective we have reduced capital expenditures and are continuing to seek ways to reduce our debt and improve our liquidity. We intend to employ various approaches for extending or refinancing existing credit facilities and for financing new plants, with a goal of retaining maximum system operating flexibility. The availability of capital at attractive terms consistent with achieving our liquidity goals will be a key requirement to enable us to develop and construct new plants. We have adjusted to recent market conditions by taking near-term actions focused on liquidity. We have been successful throughout the last few years at selling certain less strategically important assets, monetizing several contracts, buying back our debt, issuing convertible and non-convertible senior notes, and raising non-recourse project financing.

COMPETITION

      We are engaged in several different types of business activities each of which has a unique competitive environment. To better understand the competitive landscape we face, it is helpful to look at five different groupings of business activities.

      Development and Construction. We face competition from IPPs, non-regulated subsidiaries of utilities, and increasingly from regulated utilities and large end-users of electricity. In addition, there are only a few primary suppliers of key gas turbine, steam turbine and heat recovery steam generator equipment used in state of the art gas turbine power plants. Periodically we face strong competition with respect to securing the best construction personnel and contractors. Regulatory and community pressures against locating a power plant at a specific site can often be substantial, causing months or years of delays.

      Power Plant Operations. The power sales competitive landscape consists of a patchwork of highly competitive and highly regulated markets. This patchwork has been caused by inconsistent transitions to deregulated markets across North America. For example, in markets where there is open competition, our gas-fired or geothermal merchant capacity (that which has not been sold under a long-term contract) competes directly on a real time basis with all other sources of electricity such as nuclear, coal, oil, gas-fired, and renewable energy provided by others. However, there are other markets where the local utility still predominantly uses its own supply to satisfy its own demand before dispatching competitively provided power from others. Each of these markets offers a unique and challenging power sales environment.

      We also compete to be the low cost producer of power. We strive to have better efficiency, start and stop using less fuel, operate with the fewest forced outages and maximum availability and to accomplish all of this while producing less pollutants than competing gas plants and those using other fuels.

      Asset Acquisition and Divestiture. The recent downturn in the electricity industry has prompted many companies to sell assets to improve their financial positions. In addition, the postponement of plans for construction of new power plants is also creating a competitive market for the sale of excess equipment. In the past year, new entrants such as private equity funds, financial institutions and utilities have acquired power plants.

      Gas Production and Operations. Gas production is also highly competitive and is populated by numerous participants including majors, large independents and smaller “wild cat” type exploration companies. Recently, the competition in this sector has increased due to a fundamental shift in the supply and demand balance for gas in North America. This shift has driven gas prices higher and has led to increased production activities and development of alternative supply options such as liquid natural gas or coal gasification. In the near-term, however, we expect that the market to find and produce natural gas will remain highly competitive.

      Power Marketing and Sales. Power marketing and sales generally includes all those activities associated with identifying customers, negotiating, and selling energy and service contracts to load-serving entities and large scale industrial and retail end-users. In the past year, there has been a trend for financial institutions and hedge funds to enter the marketing and trading business. However, many of these players are focused on financial products and standard physical transactions. Power generators like Calpine continue to focus on selling nonstandard physical products directly to load serving entities.

ENVIRONMENTAL STEWARDSHIP

      Calpine’s goal is to produce low-cost electricity with minimal impact on the environment. To achieve this we’ve assembled the largest fleet of combined-cycle natural gas-fired power plants and the largest fleet of geothermal power facilities in North America.

      Both fleets utilize state-of-the-art technology to achieve our goal of environmentally friendly power generation.

      Our fleet of more than 25,800 MW of modern, combined-cycle natural gas-fired power plants is highly efficient. They consume significantly less fuel to generate a MWh of electricity than older boiler/steam turbine power plants. This means that less air pollutants enter the environment per unit of electricity produced, and far less pollutants are emitted compared to electricity generated by coal-fired power plants.

      Calpine’s 750-MW fleet of geothermal power plants utilizes natural heat sources from within the earth to generate electricity with negligible air emissions.

      The table below summarizes approximate air pollutant emission rates from Calpine’s combined-cycle natural gas-fired power plants and our geothermal power plants compared to average emission rates from US coal, oil and gas-fired power plants.

      Calpine’s environmental record has been widely recognized.

RECENT DEVELOPMENTS

      On January 13, 2005, we announced that we are evaluating strategic financial alternatives for our Saltend Energy Centre, including the potential sale of the power plant. We have retained Credit Suisse First Boston to act as our advisor and assist us with this process. Net proceeds from any sale of the facility would be used to redeem our existing $360.0 million Two-Year Redeemable Preferred Shares and $260.0 million Redeemable Preferred Shares Due July 30, 2005. Any remaining proceeds will be used in accordance with the asset sale provisions of our existing bond indentures.

      On January 28, 2005, our indirect subsidiary Metcalf Energy Center, LLC (“Metcalf”)obtained a $100.0 million, non-recourse credit facility for the Metcalf Energy Center in San Jose, California. Loans extended to Metcalf under the facility will fund the balance of construction activities for the 602-MW, natural gas-fired power plant. The facility will mature in July 2008.

      On January 31, 2005, we received funding on a $260.0 million offering of Redeemable Preferred Shares Due July 30, 2005 issued by our subsidiary, Calpine European Financing (Jersey) Limited. The shares were offered in a private placement in the United States under Regulation D under the Securities Act of 1933 and outside of the United States pursuant to Regulation S under the Securities Act of 1933. The Redeemable Preferred Shares, priced at U.S. LIBOR plus 850 basis points, were offered at 99% of par. The proceeds from the offering of the shares were used in accordance with the provisions of our existing bond indentures.

      On February 22, 2005, we announced that our Inland Empire Energy Center site was selected for the North American launch of General Electric’s most advanced gas turbine technology, the H System^tm. We will provide construction services to GE which will initially own and operate the facility. Additionally, we will purchase a portion of the power capacity. The Inland Empire Energy Center site is located in the unincorporated community of Romoland in Riverside County, California. The project is targeted to be online by the summer of 2008 and will be capable of meeting the energy needs of almost 600,000 households in one of the fastest growing regions in the state.

      On March 1, 2005, our indirect subsidiary, Calpine Steamboat Holdings, LLC, closed on a $503.0 million non-recourse project finance facility that will provide $466.5 million to complete the construction of the Mankato Energy Center (“Mankato”) in Blue Earth County, Minnesota, and the Freeport Energy center in Freeport, Texas. The remaining $36.5 million of the facility provides a letter of credit for Mankato that is required to serve as collateral available to Northern States Power Company if Mankato does not meet its obligations under the power purchase agreement. The project finance facility will initially be structured as a

construction loan, converting to a term loan upon commercial operations of the plants, and will mature in December 2011. The facility will initially be priced at LIBOR plus 1.75%.

      On March 31, 2005, our indirect subsidiary, Deer Park Energy Center, Limited Partnership (“Deer Park”), signed a 650 MW, six-year power sales agreement with Merrill Lynch Commodities, Inc. (“MLCI”). As part of this agreement, Deer Park received an upfront payment of approximately $195 million, net of fees and expenses. Deer Park expects to receive approximately $70 million in additional upfront payments over the next several months upon satisfying certain conditions under the power sales agreement, resulting in net payments to Deer Park totaling approximately $265 million. Deer Park has also arranged to purchase natural gas from MLCI over the term of the power sales agreement, which will reduce the working capital required to secure a long-term fuel supply for the facility. See Note 28 of the Notes to Consolidated Financial Statements for further details regarding this transaction.

      Subsequent to December 31, 2004, the Company repurchased $31.8 million in principal amount of its outstanding 8¹/2% Senior Notes Due 2011 in exchange for $23.0 million in cash plus accrued interest. The Company also repurchased $48.7 million in principal amount of its outstanding 8⁵/8% Senior Notes Due 2010 in exchange for $35.0 million in cash plus accrued interest. The Company recorded a pre-tax gain on these transactions in the amount of $22.5 million before write-offs of unamortized deferred financing costs and the unamortized premiums or discounts.

DESCRIPTION OF POWER GENERATION FACILITIES

      At March 30, 2005, we had ownership or lease interests in 92 operating power generation facilities representing 26,649 MW of net capacity. Of these projects, 73 are gas-fired power plants with a net capacity of 25,899 MW, and 19 are geothermal power generation facilities with a net capacity of 750 MW. We also have 11 gas-fired projects currently under construction with a net capacity of 5,500 MW. In addition, and not included in the table above, we expect to complete construction of 10 advanced development projects with a net capacity of 6,095 MW. The timing of the completion of these projects will be based on market fundamentals and when our return on investment criteria are expected to be met, and when power sales contracts and financing are available on attractive terms. Each of the power generation facilities currently in operation produces electricity for sale to a utility, other third-party end user, or to an intermediary such as a marketing company. Thermal energy produced by the gas-fired cogeneration facilities is sold to industrial and governmental users.

      Our gas-fired and geothermal power generation projects produce electricity and thermal energy that is sold pursuant to short-term and long-term power sales agreements (“PSAs”) or into the spot market. Revenue from a power sales agreement often consists of either or both of the following components: energy payments and capacity payments. Energy payments are based on a power plant’s net electrical output, and payment rates are typically either at fixed rates or indexed to fuel costs. Capacity payments are based on a power plant’s available capacity. Energy payments are earned for each kilowatt-hour of energy delivered, while capacity payments, under certain circumstances, are earned whether or not any electricity is scheduled by the customer and delivered.

      Upon completion of our projects under construction, we will provide operating and maintenance services for 101 of the 103 power plants in which we have an interest. Such services include the operation of power plants, geothermal steam fields, wells and well pumps, gas fields, gathering systems and gas pipelines. We also supervise maintenance, materials purchasing and inventory control, manage cash flow, train staff and prepare operating and maintenance manuals for each power generation facility that we operate. As a facility develops an operating history, we analyze its operation and may modify or upgrade equipment or adjust operating procedures or maintenance measures to enhance the facility’s reliability or profitability. These services are sometimes performed for third parties under the terms of an operating and maintenance agreement pursuant to which we are generally reimbursed for certain costs, paid an annual operating fee and may also be paid an incentive fee based on the performance of the facility. The fees payable to us may be subordinated to any lease payments or debt service obligations of financing for the project.

      In order to provide fuel for the gas-fired power generation facilities in which we have an interest, natural gas reserves are acquired or natural gas is purchased from third parties under supply agreements and gas hedging contracts. We manage a gas-fired power facility’s fuel supply so that we protect the plant’s spark spread.

      We currently hold interests in geothermal leaseholds in Lake and Sonoma Counties in northern California (“The Geysers”) that produce steam that is supplied to our leased geothermal power generation facilities for use in producing electricity. In late 2003 we began to inject waste water from the City of Santa Rosa Recharge Project into our geothermal reservoirs. We expect this recharge project to extend the useful life and enhance the performance of The Geysers geothermal resources and power plants.

      Certain power generation facilities in which we have an interest have been financed primarily with project financing that is structured to be serviced out of the cash flows derived from the sale of electricity and thermal energy produced by such facilities and provides that the obligations to pay interest and principal on the loans are secured almost solely by the capital stock or partnership interests, physical assets, contracts and/or cash flow attributable to the entities that own the facilities. The lenders under non-recourse project financing generally have no recourse for repayment against us or any of our assets or the assets of any other entity other than foreclosure on pledges of stock or partnership interests and the assets attributable to the entities that own the facilities.

      Substantially all of the power generation facilities in which we have an interest are located on sites which we own or are leased on a long-term basis. See Item 2. “Properties.”

      Set forth below is certain information regarding our operating power plants and plants under construction as of March 30, 2005.

Operating Power Plants

Projects Under Construction (All gas-fired)

ACQUISITIONS OF POWER PROJECTS AND PROJECTS UNDER CONSTRUCTION

      We have extensive experience in the development and acquisition of power generation projects. We have historically focused principally on the development and acquisition of interests in gas-fired and geothermal power projects, although we may also consider projects that utilize other power generation technologies. We have significant expertise in a variety of power generation technologies and have substantial capabilities in each aspect of the development and acquisition process, including design, engineering, procurement, construction management, fuel and resource acquisition and management, power marketing, financing and operations.

      As indicated above under “Strategy,” our development and acquisition activities have been scaled back, for the indefinite future, to focus on liquidity and operational priorities.

Acquisitions

      We may consider acquisitions of interests in operating projects as well as projects under development where we would assume responsibility for completing the development of the project. In the acquisition of power generation facilities, we generally seek to acquire 100% ownership of facilities that offer us attractive opportunities for earnings growth, and that permit us to assume sole responsibility for the operation and maintenance of the facility. In evaluating and selecting a project for acquisition, we consider a variety of factors, including the type of power generation technology utilized, the location of the project, the terms of any existing power or thermal energy sales agreements, gas supply and transportation agreements and wheeling agreements, the quantity and quality of any geothermal or other natural resource involved, and the actual condition of the physical plant. In addition, we assess the past performance of an operating project and prepare financial projections to determine the profitability of the project. Acquisition activity is dependent on the availability of financing on attractive terms, the expectation of returns that meet our long-term requirements and consistency with our long-term liquidity objectives.

      Although our preference is to own 100% of the power plants we acquire or develop, there are situations when we take less than 100% ownership. Examples of situations in which we took or may take less than a 100% interest in a power plant include: (a) our acquisitions of other IPPs such as Cogeneration Corporation of America in 1999 and SkyGen Energy LLC in 2000 in which minority interest projects were included in the portfolio of assets owned by the acquired entities (Grays Ferry Power Plant (50% now owned by Calpine) and Androscoggin Energy Center (32.3% now owned by Calpine), respectively); (b) opportunities to co-invest with non-regulated subsidiaries of regulated electric utilities, which under PURPA are restricted to 50% ownership of cogeneration qualifying facilities; and (c) opportunities to invest in merchant power projects with partners who bring marketing, funding, permitting or other resources that add value to a project, for example, Acadia Energy Center in Louisiana (50% owned by Calpine and 50% owned by Cleco Midstream Resources, an affiliate of Cleco Corporation). None of our equity investment or cost method projects have nominal carrying values as a result of material recurring losses except for Androscoggin Energy Center, which filed for bankruptcy protection in November 2004. See Note 6 of the Notes to Consolidated Financial Statements for further details. Further, there is no history of impairment in any of these investments except the Androscoggin project.

Projects Under Construction

      The development and construction of power generation projects involves numerous elements, including evaluating and selecting development opportunities, designing and engineering the project, obtaining PSAs in some cases, acquiring necessary land rights, permits and fuel resources, obtaining financing, procuring equipment and managing construction. We intend to focus on completing projects already in construction and starting new projects only when power contracts and financing are available and attractive returns are expected.

      Hillabee Energy Center. On February 24, 2000, we announced plans to build, own and operate the Hillabee Energy Center, a 770 MW, natural gas-fired cogeneration facility in Tallapoosa County, Alabama.

The project is 75% complete, but we have suspended further construction activity until a power contract is available. We expect commercial operation of the facility will commence in 2007 or later.

      Pastoria Energy Center. In April 2001 we acquired the rights to develop the 769 MW Pastoria Energy Center, a combined-cycle project planned for Kern County, California. Construction began in mid-2001, and commercial operation is scheduled to begin in May 2005 for phase one and in June 2005 for phase two.

      Fremont Energy Center. On May 23, 2000, we announced plans to build, own and operate the Fremont Energy Center, a 700 MW natural gas-fired electricity generating facility to be located near Fremont, Ohio. The project is 68% complete, but we have suspended further construction activity until a power contract is available. Commercial operation is expected to commence in the summer of 2007 or later.

      Metcalf Energy Center. On April 30, 1999, we submitted an Application for Certification with the California Energy Commission (“CEC”) to build, own and operate the Metcalf Energy Center, a 602 MW natural gas-fired electricity generating facility located in San Jose, California. Construction of the facility began in June 2002, and commercial operation is anticipated to commence in the summer of 2005.

      Otay Mesa Energy Center. On July 10, 2001, we acquired Otay Mesa Generating Company, LLC and the associated development rights including a license from the CEC. The 593 MW facility is located in southern San Diego County, California. Construction began in 2001. In October 2003 we signed a term sheet setting forth the principal terms and conditions for a ten-year, 570 MW power sales agreement with San Diego Gas & Electric Co. (“SDG&E”). Under the final agreement, we will supply electricity to SDG&E from the Otay Mesa Energy Center. Power deliveries are scheduled to begin in 2007.

      Washington Parish Energy Center. On January 26, 2001, we announced the acquisition of the development rights from Cogentrix Energy, Inc., an independent power company based in North Carolina, for the 565 MW Washington Parish Energy Center, located near Bogalusa, Louisiana. The project is 72% complete, but we have suspended further construction activity until a power contract is available. We expect commercial operation of the facility will commence in 2007 or later.

      Fox Energy Center. In 2003 we acquired the fully permitted development rights to the 560 MW Fox Energy Center in Kaukauna, Wisconsin, which will be used to fulfill an existing contract with Wisconsin Public Service. Commercial operation is expected to begin in the fall of 2005, and in December 2005 for Phase Two. We entered into a financing transaction with respect to Fox Energy Center in November 2004.

      Freeport Energy Center. In May 2004 we announced plans to build and own a 250 MW, natural gas-fired cogeneration energy center in Freeport, Texas. Under a 25-year agreement, up to 200 MW of electricity and one million pounds per hour of steam generated at the facility will be sold to the Dow Chemical Co. (“Dow”) Freeport, Texas, facility. Dow will operate this facility. Construction of the facility began in June 2004. Commercial operations will commence in multiple phases, with the first phases expected to occur in the fall of 2005 and the last phase in November 2006.

      Mankato Power Plant. In March 2004 we announced plans to build, own and operate a 375 MW, natural gas-fired power plant in Mankato, Minnesota. Electric power generated at the facility will be sold to Northern States Power Co. under a 20-year purchased power agreement. Construction began in March 2004 and we expect commercial operation of the facility to commence in June 2006.

      Valladolid III Energy Center. In October 2003 we announced, together with Mitsui & Co., Ltd. (“Mitsui”) of Tokyo, Japan, an intention to build, own and operate a 525 MW, natural gas-fired energy center for Comision Federal de Electricidad (“CFE”) at Valladolid in the Yucatan Peninsula. The facility will deliver electricity to CFE under a 25-year power sales agreement. We are supplying two combustion gas turbines to the project, giving us a 45-percent interest in the facility. Mitsui and Chubu Electric will own the remaining interest. Construction began in May 2004 and we expect commercial operation of the facility to commence in June 2006.

      Bethpage Energy Center 3. In May 2004 we announced plans to build, own and operate a 79.9 MW, natural gas-fired energy center in Hicksville, New York, adjacent to our existing cogeneration facility, the Bethpage Power Plant. Electricity generated at the facility will be sold to the Long Island Power Authority

(“LIPA”) under a 20-year power contract, which includes capacity and related energy and ancillary services. Construction began in July 2004 and commercial operation is expected to commence in July 2005.

OIL AND GAS PROPERTIES

      In 1997, we began an equity gas strategy to diversify the gas sources for our natural gas-fired power plants by purchasing Montis Niger, Incorporated, a gas production and pipeline company operating primarily in the Sacramento Basin in northern California. We currently supply the majority of the fuel requirements for the Greenleaf 1 and 2 Power Plants from these reserves. In October 1999, we purchased Sheridan Energy, Inc. (“Sheridan”), a natural gas exploration and production company operating in northern California and the Gulf Coast region. The Sheridan acquisition provided the initial management team and operational infrastructure to evaluate and acquire oil and gas reserves to keep pace with our growth in gas-fired power plants. In December 1999, we added Vintage Petroleum, Inc.’s interest in the Rio Vista Gas Unit and related areas, representing primarily natural gas reserves located in the Sacramento Basin in northern California. Sheridan was merged into Calpine in April 2000 and Calpine Natural Gas L.P. (“CNGLP”) was subsequently established to manage our oil and gas properties in the U.S. On April 19, 2001, we completed a merger with Encal Energy Ltd., a Calgary, Alberta-based natural gas and petroleum exploration and development company. Upon completion of the acquisition, we gained approximately 664 Bcfe of proved natural gas reserves, net of royalties. This transaction also provided access to firm gas transportation capacity from Western Canada to California and the eastern U.S. On October 22, 2001, we completed the acquisition of 100% of the voting stock of Michael Petroleum Corporation, a natural gas exploration and production company. The acquired assets consisted of approximately 531 wells, producing approximately 33.5 Mmcfe per day totaling approximately 82,590 net acres.

      In 2002, 2003 and 2004, certain divestments were completed to further focus operations on gas production and to enhance liquidity. In October 2003 we established the Calpine Natural Gas Trust (“CNGT”) by selling a portion of our Canadian reserves to the publicly traded trust. We retained a 25% interest in CNGT, which had proved reserves of approximately 72 Bcfe (18 Bcfe, net to Calpine’s equity interest) at December 31, 2003. In September 2004 we sold our Rocky Mountain gas reserves in the New Mexico San Juan Basin and Colorado Piceance Basin for approximately $218.7 million in net cash. Contemporaneously, we completed the sale of our Canadian natural gas reserves and petroleum assets, including the 25% interest in CNGT, for approximately Cdn$841.7 million (US$651.4 million) in net cash. These divestments are discussed in detail under Note 10 of the Notes to Consolidated Financial Statements.

      Equity equivalent net production from U.S. continuing operations averaged approximately 112 MMcfe/day for the year ended December 31, 2004, enough to fuel approximately 1,340 MW of our power plant fleet, assuming an average capacity factor of 50%. We are currently (in March 2005) capable of producing, net to Calpine’s interest, approximately 89 MMcfe of natural gas per day.

      During the year ended December 31, 2004, we recorded impairment charges of $202.1 million related to reduced proved reserve projections based on the year end independent engineer’s report. See Note 4 of the Notes to Consolidated Financial Statements for more information on the impairment charge.

MARKETING, HEDGING, OPTIMIZATION, AND TRADING ACTIVITIES

      Most of the electric power generated by our plants is transferred to our marketing and risk management unit, CES, which sells it to load-serving entities such as utilities, industrial and large retail end users, and to other third parties including power trading and marketing companies. Because a sufficiently liquid market does not exist for electricity financial instruments (typically, exchange and over-the-counter traded contracts that net settle rather than entail physical delivery) at most of the locations where we sell power, CES also enters into physical purchase and sale transactions as part of its hedging, balancing and optimization activities.

      The hedging, balancing and optimization activities that we engage in are directly related to exposures that arise from our ownership and operation of power plants and gas reserves and are designed to protect or enhance our “spark spread” (the difference between our fuel cost and the revenue we receive for our electric

generation). In many of these transactions CES purchases and resells power and gas in contracts with third parties.

      We utilize derivatives, which are defined in Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (“SFAS No. 133”) as amended by SFAS No. 138, “Accounting for Certain Derivative Investments,” (“SFAS No. 138”) and SFAS No. 149, “Amendment of Statement 133 on Derivative Investment Hedging Activities,” (“SFAS No. 149”) to include many physical commodity contracts and commodity financial instruments such as exchange-traded swaps and forward contracts, to optimize the returns that we are able to achieve from our power and gas assets. From time to time we have entered into contracts considered energy trading contracts under Emerging Issues Task Force (“EITF”) Issue No. 02-03, “Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (“EITF Issue No. 02-03”). However, our risk managers have low capital at risk and value at risk limits for energy trading, and our risk management policy limits, at any given time, our net sales of power to our generation capacity and limits our net purchases of gas to our fuel consumption requirements on a total portfolio basis. This model is markedly different from that of companies that engage in significant commodity trading operations that are unrelated to underlying physical assets. Derivative commodity instruments are accounted for under the requirements of SFAS No. 133. The EITF reached a consensus under EITF Issue No. 02-03 that gains and losses on derivative instruments within the scope of SFAS No. 133 should be shown net in the income statement if the derivative instruments are held for trading purposes. In addition we present on a net basis certain types of hedging, balancing and optimization revenues and costs of revenue under EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ As Defined in EITF Issue No. 02-03: ‘Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities’ ” (“EITF Issue No. 03-11”), which we adopted prospectively on October 1, 2003. See Item 7 — “Management’s Discussion and Analysis — Application of Critical Accounting Policies” and Note 2 to the Consolidated Financial Statements for a discussion of the effects of adopting this standard.

      In some instances economic hedges may not be designated as hedges for accounting purposes. An example of an economic hedge that is not a hedge for accounting purposes would be a long-term fixed price electric sales contract that economically hedges us against the risk of falling electric prices, but which for accounting purposes can be exempted from derivative accounting under SFAS No. 133 as a normal purchase and sale. For a further discussion of our derivative accounting methodology, see Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Application of Critical Accounting Policies.”

GOVERNMENT REGULATION

      We are subject to complex and stringent energy, environmental and other governmental laws and regulations at the federal, state and local levels in connection with the development, ownership and operation of our energy generation facilities. Federal laws and regulations govern transactions by electric and gas utility companies, the types of fuel which may be utilized by an electricity generating plant, the type of energy which may be produced by such a plant, the ownership of a plant, and access to and service on the transmission grid. In most instances, public utilities that serve retail customers are subject to rate regulation by the state’s related utility regulatory commission. A state utility regulatory commission is often primarily responsible for determining whether a public utility may recover the costs of wholesale electricity purchases or other supply procurement-related activities through the retail rates the utility charges its customers. The state utility regulatory commission may, from time to time, impose restrictions or limitations on the manner in which a public utility may transact with wholesale power sellers, such as independent power producers. Under certain circumstances where specific exemptions are otherwise unavailable, state utility regulatory commissions may have broad jurisdiction over non-utility electric power plants. Energy producing facilities also are subject to federal, state and local laws and administrative regulations which govern the emissions and other substances produced, discharged or disposed of by a plant and the geographical location, zoning, land use and operation of a plant. Applicable federal environmental laws typically have both state and local enforcement and

implementation provisions. These environmental laws and regulations generally require that a wide variety of permits and other approvals be obtained before the commencement of construction or operation of an energy producing facility and that the facility then operate in compliance with such permits and approvals.

      In light of the circumstances in California, the Pacific Gas and Electric Company (“PG&E”) bankruptcy and the Enron Corp. (“Enron”) bankruptcy, among other events in recent years, there are a number of federal legislative and regulatory initiatives that could result in changes in how the energy markets are regulated. We do not know whether these legislative and regulatory initiatives will be adopted or, if adopted, what form they may take. We cannot provide assurance that any legislation or regulation ultimately adopted would not adversely affect our existing projects. See the risk factors set forth under “— Risk Factors — California Power Market” and “— Government Regulations.”

Federal Energy Regulation

      The Public Utility Regulatory Policies Act of 1978, as amended (“PURPA”), and the regulations adopted thereunder by the Federal Energy Regulatory Commission (“FERC”) provide certain incentives for cogeneration facilities and small power production facilities, which satisfy FERC’s criteria for qualifying facility status (“QFs”). First, FERC’s implementing regulations exempt most QFs from the Public Utility Holding Company Act of 1935, as amended (“PUHCA”), many provisions of the Federal Power Act (“FPA”), and state laws concerning rate, financial, and organizational regulation. These exemptions are important to us and our competitors. Second, FERC’s regulations require that electric utilities purchase electricity generated by QFs at a price based on the purchasing utility’s avoided cost, and that the utility sell back-up power to the QF on a non-discriminatory basis. FERC’s regulations define “avoided costs” as the incremental costs to an electric utility of electric energy or capacity, or both, which, but for the purchase from QFs, such utility would generate itself or purchase from another source.

      To be a QF, a cogeneration facility must produce electricity and useful thermal energy for an industrial or commercial process or heating or cooling applications in certain proportions to the facility’s total energy output, and must meet certain efficiency standards. A geothermal small power production facility may qualify as a QF if, in most cases, its generating capability does not exceed 80 megawatts. Finally, no more than 50% of the equity of a QF can be owned by one or more electric utilities or their affiliates.

      We believe that each of the facilities in which we own an interest and which operates as a QF meets or will meet the requirements for QF status. Certain factors necessary to maintain QF status are, however, subject to the risk of events outside our control. For example, some of our facilities have temporarily been rendered incapable of meeting such requirements due to the loss of a thermal energy customer and we have obtained limited waivers (for up to two years) of the applicable QF requirements from FERC. We cannot provide assurance that such waivers will in every case be granted. During any such waiver period, we would seek to replace the thermal energy customer or find another use for the thermal energy which meets PURPA’s requirements, but no assurance can be given that these remedial actions would be available.

      If one of our facilities should lose its QF status, the facility would no longer be entitled to the exemptions from PUHCA and the FPA. Loss of QF status could also trigger certain rights of termination under the facility’s power sales agreement, could subject the facility to rate regulation as a public utility under the FPA and state law, and could result in us inadvertently becoming an electric utility holding company by owning more than 10% of the voting securities of, or controlling, a public utility company that would no longer be exempt from PUHCA. Loss of the PUHCA exemption could cause all of our remaining QFs to lose their respective QF status, because no more than 50% of a QF’s equity may be owned by such electric utility holding companies. Loss of QF status may also trigger defaults under covenants to maintain QF status in the projects’ power sales agreements, steam sales agreements and financing agreements and may result in termination, penalties or acceleration of indebtedness under such agreements.

      Under Section 32 of PUHCA, the owner of a facility can become an Exempt Wholesale Generator (“EWG”) if the owner is engaged directly, or indirectly through one or more affiliates, and exclusively in the

business of owning and/or operating an eligible electric generating facility and all of the facility’s output is sold at wholesale for resale rather than directly to end users. As an EWG, the owner of the eligible generating facility is exempt from PUHCA even if the generating facility does not qualify as a QF. Therefore, another possible response to the loss or potential loss of QF status would be to apply to have the facility’s owner qualify as an EWG. However, assuming this changed status would be permissible under the terms of the applicable power sales agreement, rate approval from FERC would be required. In addition, the facility would be required to cease selling electricity to any retail electric customers (such as the thermal energy customer) to retain its EWG status.

Public Utility Holding Company Regulation

      Under PUHCA, any corporation, partnership or other defined entity which owns or controls 10% or more of the outstanding voting securities of a public utility company, or a company which is a holding company for a public utility company, is subject to registration with the Securities and Exchange Commission (“SEC”) and regulation under PUHCA, unless eligible for an exemption or unless an appropriate application is filed with, and an order is granted by, the SEC declaring the applicant not to be a holding company. A holding company of a public utility company that is subject to registration is required by PUHCA to limit its utility operations to a single integrated utility system and to divest any other operations not functionally related to the operation of that utility system. Approval by the SEC is required for nearly all important financial and business transactions to be conducted by a registered holding company. Under PURPA, most QFs are exempt from regulation under PUHCA.

      The Energy Policy Act of 1992, among other things, amends PUHCA to allow EWGs, under certain circumstances, to own and operate non-QF electric generating facilities without subjecting those producers to registration or regulation under PUHCA. The effect of such amendments has been to enhance the development of non-QFs which do not have to meet the fuel, production and ownership requirements of PURPA. We believe that these amendments benefit us by expanding our ability to own and operate facilities that do not qualify for QF status. However, the creation of an EWG class of generators has also resulted in increased competition by allowing utilities and their affiliates to develop such facilities which are not subject to the constraints of PUHCA.

Federal Natural Gas Transportation Regulation

      We have an ownership interest in 84 gas-fired power plants in operation or under construction. The cost of natural gas is ordinarily the largest expense of a gas-fired project and is critical to the project’s economics. The risks associated with using natural gas can include the need to arrange gathering, processing, extraction, blending, and storage, as well as transportation of the gas from great distances, including obtaining removal, export and import authority if the gas is transported from Canada; the possibility of interruption of the gas supply or transportation (depending on the quality of the gas reserves purchased or dedicated to the project, the financial and operating strength of the gas supplier, whether firm or non-firm transportation is purchased and the operations of the gas pipeline); and obligations to take a minimum quantity of gas and pay for it (i.e., take-and-pay obligations).

      Pursuant to the Natural Gas Act, FERC has jurisdiction over the transportation and storage of natural gas in interstate commerce. With respect to most transactions that do not involve the construction of pipeline facilities, regulatory authorization can be obtained on a self-implementing basis. However, interstate pipeline rates and terms and conditions for such services are subject to continuing FERC oversight.

Federal Power Act Regulation

      Under the Federal Power Act (“FPA”), FERC is authorized to regulate the transmission of electric energy and the sale of electric energy at wholesale in interstate commerce. Unless otherwise exempt, any person that owns or operates facilities used for such purposes is a public utility subject to FERC jurisdiction. FERC regulation under the FPA includes approval of the disposition of FERC-jurisdictional utility property, authorization of the issuance of securities by public utilities, regulation of the rates, terms and conditions for

the transmission or sale of electric energy at wholesale in interstate commerce, the regulation of interlocking directorates, and the imposition of a uniform system of accounts and reporting requirements for public utilities.

      FERC regulations implementing PURPA provide that a QF is exempt from regulation under the foregoing provisions of the FPA. An EWG is not exempt from the FPA and therefore an EWG that makes sales of electric energy at wholesale in interstate commerce is subject to FERC regulation as a public utility. However, many of the regulations which customarily apply to traditional public utilities have been waived or relaxed for EWGs and other non-traditional public utilities that can demonstrate that they cannot exercise market power. Upon making the necessary showing, EWGs meeting FERC’s requirements are granted authorization to charge market-based rates, blanket authority to issue securities, and waivers of certain FERC requirements pertaining to accounts, reports and interlocking directorates. The granting of such authorities and waivers is intended to implement FERC’s policy to foster a more competitive wholesale power market.

      Many of the generating projects in which we own an interest are or will be operated as QFs and therefore are or will be exempt from FERC regulation under the FPA. However, the majority of our generating projects are or will be EWGs, most of which are or will be subject to FERC jurisdiction under the FPA. Several of our affiliates have been granted authority to engage in sales at market-based rates and blanket authority to issue securities, and have also been granted certain waivers of FERC regulations available to non-traditional public utilities; however, we cannot assure that such authorities or waivers will not be revoked for these affiliates or will be granted in the future to other affiliates.

Federal Open Access Electric Transmission Regulation

      In 1996, FERC issued Order Nos. 888 and 889, introducing competitive reforms and increasing access to the electric power grid. Order No. 888 required the “functional unbundling” of transmission and generation assets by the transmission-owning utilities subject to its jurisdiction. Under Order No. 888, the jurisdictional transmission-owning utilities, and many non-jurisdictional transmission owners (through reciprocity requirements), were required to adopt FERC’s pro forma open access transmission tariff establishing terms of non-discriminatory transmission service. Order No. 889 required transmission-owning utilities to provide the public with an electronic system for buying and selling transmission capacity in transactions with the utilities and abide by specific standards of conduct when using their transmission systems to make wholesale sales of power. In addition, these orders established the operational requirements of Independent System Operators (“ISO”), which are entities that have been given authority to operate the transmission assets of certain jurisdictional and non-jurisdictional utilities in a particular region. The interpretation and application of the requirements of Order Nos. 888 and 889 continues to be refined through subsequent FERC proceedings. These orders have been subject to review, and those parts of the orders that have been the subject of judicial appeals have been affirmed, in large part, by the courts.

      In addition to its Open Access efforts under Order Nos. 888 and 889, our business can be affected by a variety of other FERC policies and proposals, including Order No. 2000, issued in December 1999, which was designed to encourage the voluntary formation of Regional Transmission Organizations; a proposed “Standard Market Design,” issued in July 2002 under which the allocation of transmission capacity, the dispatch of generation in light of transmission constraints, the coordination of transmission upgrades and allocation of associated costs, and other issues would be addressed through a set of standard rules; and Order No. 2003, issued in July 2003, which established uniform procedures for generator interconnection to the transmission grid. All of these policies and proposals continue to evolve, and FERC may amend or revise them, or may introduce new policies or proposals, in the future. In addition, such policies and proposals, in their final form, would be subject to potential judicial review. The impact of such policies and proposals on our business is uncertain and cannot be predicted at this time.

Western Energy Markets

      There was significant price volatility in both wholesale electricity and gas markets in the Western United States for much of calendar year 2000 and extending through the second quarter of 2001. Due to a number of

factors, including drier than expected weather, which led to lower than normal hydro-electric capacity in California and the Northwestern United States, inadequate natural gas pipeline and electric generation capacity to meet higher than anticipated energy demand in the region, the inability of the California utilities to manage their exposure to such price volatility due to regulatory and financial constraints, and evolving market structures in California, prices for electricity and natural gas were much higher than anticipated. A number of federal and state investigations and proceedings were commenced to address the crisis.

      There are currently a number of proceedings pending at FERC which were initiated as a direct result of the price levels and volatility in the energy markets in the Western United States during this period. Many of these proceedings were initiated by buyers of wholesale electricity seeking refunds for purchases made during this period or the reduction of price terms in contracts entered into at this time. We have been a party to some of these proceedings. See “— Risk Factors — California Power Market” and “Legal Proceedings” in Note 25 of the Notes to Consolidated Financial Statements. As part of certain proceedings, and as a result of its own investigations, FERC has ordered the implementation of certain measures for wholesale electricity markets in California and the Western United States, including, the implementation of price caps on the day ahead or real-time prices for electricity and a continuing obligation of electricity generators to offer uncommitted generation capacity to the California Independent System Operator. FERC is continuing to investigate the causes of the price volatility in the Western United States during this period. It is uncertain at this time when these proceedings and investigations at FERC will conclude or what will be the final resolution thereof. See “— Risk Factors — California Power Market” below.

      Other federal and state governmental entities have and continue to conduct various investigations into the causes of the price volatility in the energy markets in the Western United States during 2000-2001. It is uncertain at this time when these investigations will conclude or what the results may be. The impact on our business of the results of the investigations cannot be predicted at this time.

State Regulation

      State public utility commissions (“PUCs”) have historically had broad authority to regulate both the rates charged by, and the financial activities of, electric utilities operating in their states and to promulgate regulation for implementation of PURPA. Since a power sales agreement becomes a part of a utility’s cost structure (generally reflected in its retail rates), power sales agreements with independent electricity producers, such as EWGs, are potentially under the regulatory purview of PUCs and in particular the process by which the utility has entered into the power sales agreements. If a PUC has approved the process by which a utility secures its power supply, a PUC is generally inclined to authorize the purchasing utility to pass through to the utility’s retail customers the expenses associated with a power purchase agreement with an independent power producer. However, a regulatory commission under certain circumstances may not allow the utility to recover through retail rates its full costs to purchase power from a QF or an EWG. In addition, retail sales of electricity or thermal energy by an independent power producer may be subject to PUC regulation depending on state law. Independent power producers which are not QFs under PURPA, or EWGs pursuant to the Energy Policy Act of 1992, are considered to be public utilities in many states and are subject to broad regulation by a PUC, ranging from requirement of certificate of public convenience and necessity to regulation of organizational, accounting, financial and other corporate matters. Because all of Calpine’s affiliates are either QFs or EWGs, none of its affiliates are currently subject to such regulation. However, states may also assert jurisdiction over the siting and construction of electricity generating facilities including QFs and EWGs and, with the exception of QFs, over the issuance of securities and the sale or other transfer of assets by these facilities. In California, for example, the PUC has been required by statute to adopt and enforce maintenance and operation standards for generating facilities “located in the state,” including EWGs but excluding QFs, for the purpose of ensuring their reliable operation. The adopted standards are now in effect.

      State PUCs also have jurisdiction over the transportation of natural gas by local distribution companies (“LDCs”). Each state’s regulatory laws are somewhat different; however, all generally require the LDC to obtain approval from the PUC for the construction of facilities and transportation services if the LDCs generally applicable tariffs do not cover the proposed transaction. LDC rates are usually subject to continuing

PUC oversight. We own and operate numerous midstream assets in a number of states where we have plants and/or oil and gas production.

Environmental Regulations

      The exploration for and development of geothermal resources, oil, gas liquids and natural gas, and the construction and operation of wells, fields, pipelines, various other mid-stream facilities and equipment, and power projects, are subject to extensive federal, state and local laws and regulations adopted for the protection of the environment and to regulate land use. The laws and regulations applicable to us primarily involve the discharge of emissions into the water and air and the use of water, but can also include wetlands preservation, endangered species, hazardous materials handling and disposal, waste disposal and noise regulations. These laws and regulations in many cases require a lengthy and complex process of obtaining licenses, permits and approvals from federal, state and local agencies.

      Noncompliance with environmental laws and regulations can result in the imposition of civil or criminal fines or penalties. In some instances, environmental laws also may impose clean-up or other remedial obligations in the event of a release of pollutants or contaminants into the environment. The following federal laws are among the more significant environmental laws as they apply to us. In most cases, analogous state laws also exist that may impose similar, and in some cases more stringent, requirements on us as those discussed below.

Clean Air Act

      The Federal Clean Air Act of 1970 (“the Clean Air Act”) provides for the regulation, largely through state implementation of federal requirements, of emissions of air pollutants from certain facilities and operations. As originally enacted, the Clean Air Act sets guidelines for emissions standards for major pollutants (i.e., sulfur dioxide and nitrogen oxide) from newly built sources. In late 1990, Congress passed the Clean Air Act Amendments (“the 1990 Amendments”). The 1990 Amendments attempt to reduce emissions from existing sources, particularly previously exempted older power plants. We believe that all of our operating plants and relevant oil and gas related facilities are in compliance with federal performance standards mandated under the Clean Air Act and the 1990 Amendments.

Clean Water Act

      The Federal Clean Water Act (the “Clean Water Act”) establishes rules regulating the discharge of pollutants into waters of the United States. We are required to obtain wastewater and storm water discharge permits for wastewater and runoff, respectively, from certain of our facilities. We believe that, with respect to our geothermal and oil and gas operations, we are exempt from newly promulgated federal storm water requirements. We are required to maintain a spill prevention control and countermeasure plan with respect to certain of our oil and gas facilities. We believe that we are in material compliance with applicable discharge requirements of the Clean Water Act.

Oil Pollution Act of 1990

      The Oil Pollution Act of 1990 (“OPA”) applies to our offshore facilities in the U.S. Gulf of Mexico regulating oil pollution prevention measures and financial responsibility requirements. We believe that we are in material compliance with applicable OPA requirements.

Safe Drinking Water Act

      Part C of the Safe Water Drinking Act (“SWDA”) mandates the underground injection control (“UIC”) program. The UIC regulates the disposal of wastes by means of deep well injection. Deep well injection is a common method of disposing of saltwater, produced water and other oil and gas wastes. We believe that we are in material compliance with applicable UIC requirements of the SWDA.

Resource Conservation and Recovery Act

      The Resource Conservation and Recovery Act (“RCRA”) regulates the generation, treatment, storage, handling, transportation and disposal of solid and hazardous waste. We believe that we are exempt from solid waste requirements under RCRA. However, particularly with respect to our solid waste disposal practices at the power generation facilities and steam fields located at The Geysers, we are subject to certain solid waste requirements under applicable California laws. Based on the exploration and production exception, many oil and gas wastes are exempt from hazardous wastes regulation under RCRA. For those wastes generated in association with the exploration and production of oil and gas which are classified as hazardous wastes, we undertake to comply with the RCRA requirements for identification and disposal. Various state environmental and safety laws also regulate the oil and gas industry. We believe that our operations are in material compliance with RCRA and all such laws.

Comprehensive Environmental Response, Compensation, and Liability Act

      The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (“CERCLA” or “Superfund”), requires cleanup of sites from which there has been a release or threatened release of hazardous substances and authorizes the United States Environmental Protection Agency to take any necessary response action at Superfund sites, including ordering potentially responsible parties (“PRPs”) liable for the release to take or pay for such actions. PRPs are broadly defined under CERCLA to include past and present owners and operators of, as well as generators of wastes sent to, a site. As of the present time, we are not subject to liability for any Superfund matters. However, we generate certain wastes, including hazardous wastes, and send certain of our wastes to third party waste disposal sites. As a result, there can be no assurance that we will not incur liability under CERCLA in the future.

Canadian Environmental, Health and Safety Regulations

      Our Canadian power projects are also subject to extensive federal, provincial and local laws and regulations adopted for the protection of the environment and to regulate land use. We believe that we are in material compliance with all applicable requirements under Canadian law related to same.

Regulation of Canadian Gas

      The Canadian natural gas industry is subject to extensive regulation by federal and provincial authorities. At the federal level, a party exporting gas from Canada must obtain an export license from the National Energy Board (“NEB”). The NEB also regulates Canadian pipeline transportation rates and the construction of pipeline facilities. Gas producers also must obtain a removal permit or license from each provincial authority before natural gas may be removed from the province, and provincial authorities regulate intra-provincial pipeline and gathering systems. In addition, a party importing natural gas into the United States or exporting natural gas from the United States first must obtain an import or export authorization from the U.S. Department of Energy.

Regulation of U.S. Gas

      The U.S. natural gas industry is subject to extensive regulation by federal, state and local authorities. Calpine holds onshore and offshore federal leases involving the U.S. Dept. of Interior (Bureau of Land Management, Bureau of Indian Affairs and the Minerals Management Service). At the federal level, various federal rules, regulations and procedures apply, including those issued by the U.S. Dept. of Interior as noted above, and the U.S. Dept. of Transportation (U.S. Coast Guard and Office of Pipeline Safety). At the state and local level, various agencies and commissions regulate drilling, production and midstream activities. We have state and private oil and gas leases covering developed and undeveloped properties located in Arkansas, California, Colorado, Kansas, Louisiana, Mississippi, Missouri, Montana, New Mexico, Oklahoma, Texas and Wyoming. These federal, state and local authorities have various permitting, licensing and bonding requirements. Varied remedies are available for enforcement of these federal, state and local rules, regulations and procedures, including fines, penalties, revocation of permits and licenses, actions affecting the value of

leases, wells or other assets, and suspension of production. As a result, there can be no assurance that we will not incur liability for fines and penalties or otherwise subject us to the various remedies as are available to these federal, state and local authorities. However, we believe that we are currently in material compliance with these federal, state and local rules, regulations and procedures.

RISK FACTORS

Capital Resources; Liquidity

      We must meet ongoing debt obligations. We have substantial indebtedness that we incurred to finance the acquisition and development of power generation facilities that we may be unable to service and that restricts our activities. As of December 31, 2004, our total consolidated funded debt was $18.0 billion, our total consolidated assets were $27.2 billion and our stockholders’ equity was $4.5 billion. Whether we will be able to meet our debt service obligations and repay, extend, or refinance our outstanding indebtedness will be dependent primarily upon the operational performance of our power generation facilities and of our oil and gas properties, movements in electric and natural gas prices over time, and our marketing and risk management activities, as well as general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control.

      This high level of indebtedness has important consequences, including:

      Our debt instruments impose significant operating and financial restrictions on us; any failure to comply with these restrictions could have a material adverse effect on our liquidity and our operations. The indentures and other instruments governing our outstanding debt impose significant operating and financial restrictions on us. These restrictions could adversely affect us by limiting our ability to plan for or react to market conditions or to meet our capital needs. These restrictions limit or prohibit our ability to, among other things:

      In particular, the covenants in certain of our existing debt agreements currently impose the following restrictions on our activities:

      In addition: (a) if Calpine Corporation’s ownership changes, the indentures and other instruments governing approximately $9.8 billion of our senior notes and term loans may require us to make an offer to purchase those senior notes and term loans, (b) pursuant to the terms of the indentures under which our contingent convertible senior notes were issued, upon the occurrence of certain defined triggering events (which include our common stock reaching certain price levels), the holders of the notes have the right to require that the notes be converted into a combination of cash (in an amount equal to the par value of the notes so converted) and our common shares (with respect to any additional value required to be delivered to the holders) and (c) with respect to our Contingent Convertible Notes due 2014, we may not make such payments upon conversion unless we meet a specified ratio of consolidated cash flow to fixed charges; currently, we do not satisfy such ratio. We may not have the financial resources necessary or may otherwise be

restricted from purchasing those senior notes and term loans, or making such cash payments to holders of those contingent convertible notes in these events.

      Our ability to comply with these covenants may be affected by events beyond our control, and any material deviations from our forecasts could require us to seek waivers or amendments of covenants or alternative sources of financing or to reduce expenditures. We cannot assure you that such waivers, amendments or alternative financing could be obtained, or if obtained, would be on terms acceptable to us.

      If we are unable to comply with the terms of our indentures and other debt agreements, or if we fail to generate sufficient cash flow from operations, or to refinance our debt as described below, we may be required to refinance all or a portion of our senior notes and other debt or to obtain additional financing or sell additional assets. However, we may be unable to refinance or obtain additional financing because of our already high levels of debt and the debt incurrence restrictions under our existing indentures and other debt agreements. If our cash flow is insufficient and refinancing or additional financing is unavailable, we may be forced to default on our senior notes and other debt obligations. Such a default or other breach of the covenants or restrictions contained in any of our existing or future debt instruments could result in an event of default under those instruments and, due to cross-default and cross-acceleration provisions, under our other debt instruments. Upon an event of default under our debt instruments, the debt holders could elect to declare the entire debt outstanding thereunder to be due and payable and could terminate any commitments they had made to supply us with further funds. If any of these events occur, we cannot assure you that we will have sufficient funds available to repay in full the total amount of obligations that become due as a result of any such acceleration, or that we will be able to find additional or alternative financing to refinance any accelerated obligations.

      We must either repay or refinance our debt maturing in 2005 and 2006. Since the latter half of 2001, there has been a significant contraction in the availability of capital for participants in the energy sector. This has been due to a range of factors, including uncertainty arising from the collapse of Enron and a perceived surplus of electric generating capacity. These factors have continued through 2003 and 2004, during which contracting credit markets and decreased spark spreads have adversely impacted our liquidity and earnings. While we have been able to access the capital and bank credit markets, it has been on significantly different terms than in the past. We recognize that terms of financing available to us in the future may not be attractive. To protect against this possibility and due to current market conditions, we scaled back our capital expenditure program to enable us to conserve our available capital resources.

      In 2005, the following payments will be due on our outstanding debt: (i) $186.1 million in aggregate principal amount of 8¹/4% Senior Notes Due 2005 (ii) $148.1 million aggregate principal amount of notes issued by our subsidiary Power Contract Financing, L.L.C. (“PCF”) in connection with the monetization of a power contract with California Department of Water Resources (“CDWR”) and (iii) $260.0 million in Redeemable Preferred Shares issued by our subsidiary Calpine European Financing (Jersey) Limited; in 2006, the following payments will be due on our outstanding debt: (i) $111.6 million in aggregate principal amount of 7⁵/8% Senior Notes Due 2006, (ii) $152.7 million in aggregate principal amount of 10¹/2% Senior Notes Due 2006, (iii) $360.0 million in Two-Year Redeemable Preferred Shares issued by our subsidiary Calpine (Jersey) Limited, and (iv) $155.9 million in aggregate principal amount of the notes issued by PCF in connection with the CDWR power contract monetization. In addition, as of December 31, 2004, we have approximately $181.2 million and $163.8 million of miscellaneous debt and capital lease obligations that are maturing or for which scheduled principal payments will be made in 2005 and 2006, respectively. As discussed above, we are also required to repurchase or redeem approximately $520 million of indebtedness (current estimate) in the aggregate pursuant to our indentures during 2005.

      In addition, our $517.5 million of outstanding HIGH TIDES III (of which $115.0 million have been repurchased and are currently held by us) are scheduled to be remarketed no later than August 1, 2005. In the event of a failed remarketing, the HIGH TIDES III, unless earlier redeemed, will remain outstanding as convertible securities at a term rate equal to the treasury rate plus 6% per annum and with a term conversion price equal to 105% of the average closing price of our common stock for the five consecutive trading days after the applicable final failed remarketing termination date. We currently anticipate refinancing all or a

portion of the outstanding HIGH TIDES prior to the scheduled remarketing date, through the issuance of convertible debt or another form of equity-linked security, possibly combined with a share lending facility modeled after the Share Lending Agreement we entered into on September 30, 2004. We may also consider using our common stock to effect stock-for-debt exchanges with, or to raise cash to fund the purchase of HIGH TIDES from, some of the existing holders of the outstanding HIGH TIDES.

      We cannot assure you that our business will generate sufficient cash flow from operations or that future borrowings will be available to us in an amount sufficient to enable us to pay our indebtedness when due, or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness, on or before maturity. While we believe we will be successful in repaying or refinancing all of our debt on or before maturity, we cannot assure you that we will be able to do so.

      We may not have sufficient cash to service our indebtedness and other liquidity requirements. Our ability to make payments on and to refinance our indebtedness, and to fund planned capital expenditures and research and development efforts, will depend on our ability to generate cash in the future. To date, we have obtained cash from our operations; borrowings under credit facilities; issuance of debt, equity, trust preferred securities and convertible debentures and contingent convertible notes; proceeds from sale/leaseback transactions; sale or partial sale of certain assets; contract monetizations and project financing. Taking into account our construction program and other planned capital expenditures and research and development, our debt service and repayment obligations and our bond repurchase obligations described above, we are currently projecting that unrestricted cash on hand together with cash from operations will not by itself be sufficient to meet our cash and liquidity needs for the year. We have therefore continued, and expanded, our liquidity-enhancing program, which program includes the possible sale or monetization of certain of our assets. The success of this liquidity program will depend on our being able to complete these anticipated asset sale and monetization transactions, which may in turn be impacted by a number of factors, including general economic and capital market conditions; conditions in energy markets; regulatory approvals and developments; limitations imposed by our existing agreements; and other factors, many of which are beyond our control. See also “— We may be unable to secure additional financing in the future.” Some of the anticipated liquidity transactions involve the monetization or prepayment of future revenues and could therefore negatively impact cash flow in future years. While we believe we will be successful in completing a sufficient number of these anticipated transactions, we cannot assure you that we will be able to do so. Accordingly, we may not be able to generate sufficient cash to meet all of our commitments.

      We may be unable to secure additional financing in the future. Each power generation facility that we acquire or develop will require substantial capital investment. Our ability to arrange financing (including any extension or refinancing) and the cost of the financing are dependent upon numerous factors. Access to capital (including any extension or refinancing) for participants in the energy sector, including for us, has been significantly restricted since late 2001. Other factors include:

      We have financed our existing power generation facilities using a variety of leveraged financing structures, consisting of senior secured and unsecured indebtedness, including construction financing, project financing, revolving credit facilities, term loans and lease obligations. As of December 31, 2004, we had approximately $18.0 billion of total consolidated funded debt, consisting of $5.2 billion of secured construction/project

financing, $0.3 billion of capital lease obligations, $9.2 billion in senior notes and institutional term loans, $1.3 billion in convertible senior notes, $0.5 billion in preferred interests, $0.5 billion of trust preferred securities and $1.0 billion of secured and unsecured notes payable and borrowings under lines of credit. Additionally, we had operating leases with an aggregate present value of future minimum lease payments of $1.3 billion. Each project financing and lease obligation is structured to be fully paid out of cash flow provided by the facility or facilities financed or leased. In the event of a default under a financing agreement which we do not cure, the lenders or lessors would generally have rights to the facility and any related assets. In the event of foreclosure after a default, we might not retain any interest in the facility. While we intend to utilize non-recourse or lease financing when appropriate, market conditions and other factors may prevent similar financing for future facilities. It is possible that we may be unable to obtain the financing required to develop our power generation facilities on terms satisfactory to us. In addition, if new debt is added to our current debt levels, the risks associate with our substantial leverage that we now face could intensify.

      We have from time to time guaranteed certain obligations of our subsidiaries and other affiliates. Our lenders or lessors may also seek to have us guarantee the indebtedness for future facilities. Guarantees render our general corporate funds vulnerable in the event of a default by the facility or related subsidiary. Additionally, certain of our indentures may restrict our ability to guarantee future debt, which could adversely affect our ability to fund new facilities. Our indentures generally do not limit the ability of our subsidiaries to incur non-recourse or lease financing or to issue preferred stock for investment in new facilities.

      Our credit ratings have been downgraded and could be downgraded further. On September 23, 2004, Standard & Poor’s (“S&P”) assigned our first priority senior secured debt a rating of B+ and reaffirmed their ratings on our second priority senior secured debt at B, our corporate rating at B (with outlook negative), our senior unsecured debt rating at CCC+, and our preferred stock rating at CCC.

      On October 4, 2004, Fitch, Inc. assigned our first priority senior secured debt a rating of BB-. At that time, Fitch also downgraded our second priority senior secured debt from BB- to B+, downgraded our senior unsecured debt rating from B- to CCC+, and reconfirmed our preferred stock rating at CCC. Fitch’s rating outlook for the Company is stable.

      Moody’s Investors Service currently has a senior implied rating on the Company of B2 (with a stable outlook), and rates our senior unsecured debt at Caa1 and our preferred stock at Caa3.

      Many other issuers in the power generation sector have also been downgraded by one or more of the ratings agencies during this period. Such downgrades can have a negative impact on our liquidity by reducing attractive financing opportunities and increasing the amount of collateral required by trading counterparties. We cannot assure you that Moody’s, Fitch and S&P will not further downgrade our credit ratings in the future. If our credit ratings are downgraded, we could be required to, among other things, pay additional interest under our credit agreements, or provide additional guarantees, collateral, letters of credit or cash for credit support obligations, and it could increase our cost of capital, make our efforts to raise capital more difficult and have an adverse impact on our subsidiaries’ and our business, financial condition and results of operations.

      In light of our current credit ratings, many of our customers and counterparties are requiring that our and our subsidiaries’ obligations be secured by letters of credit or cash. Banks issuing letters of credit for our or our subsidiaries’ accounts are similarly requiring that the reimbursement obligations be cash-collateralized. In a typical commodities transaction, the amount of security that must be posted can change depending on the mark-to-market value of the transaction. These letter of credit and cash collateral requirements increase our cost of doing business and could have an adverse impact on our overall liquidity, particularly if there were a call for a large amount of additional cash or letter of credit collateral due to an unexpectedly large movement in the market price of a commodity. We are exploring with counterparties and financial institutions various alternative approaches to credit support, including the utilization of liens on our generating facilities and other assets to secure our subsidiaries’ obligations under certain power purchase agreements and other commercial arrangements, in lieu of cash collateral or letter of credit posting requirements. Such alternative arrangements could, however, also add to our cost of doing business.

      Our ability to repay our debt depends upon the performance of our subsidiaries. Almost all of our operations are conducted through our subsidiaries and other affiliates. As a result, we depend almost entirely upon their earnings and cash flow to service our indebtedness, including our ability to pay the interest and principal of our senior notes. The financing agreements of certain of our subsidiaries and other affiliates generally restrict their ability to pay dividends, make distributions, or otherwise transfer funds to us prior to the payment of their other obligations, including their outstanding debt, operating expenses, lease payments and reserves. While certain of our indentures and other debt instruments limit our ability to enter into agreements that restrict our ability to receive dividends and other distributions from our subsidiaries, these limitations are subject to a number of significant exceptions (including exceptions permitting such restrictions arising out of subsidiary financings).

      We may utilize project financing, preferred equity and other types of subsidiary financing transactions when appropriate in the future. Our indentures and other debt instruments place limitations on our ability and the ability of our subsidiaries to incur additional indebtedness. However, they permit our subsidiaries to incur additional construction/project financing indebtedness and to issue preferred stock to finance the acquisition and development of new power generation facilities and to engage in certain types of non-recourse financings and issuance of preferred stock. If new subsidiary debt and preferred stock is added to our current debt levels, the risks associated with our substantial leverage that we now face could intensify.

      Our senior notes and our other senior debt are effectively subordinated to all indebtedness and other liabilities of our subsidiaries and other affiliates and may be effectively subordinated to our secured debt to the extent of the assets securing such debt. Our subsidiaries and other affiliates are separate and distinct legal entities and, except in limited circumstances, have no obligation to pay any amounts due with respect to our indebtedness or indebtedness of other subsidiaries or affiliates, and do not guarantee the payment of interest on or principal of such indebtedness. In the event of our bankruptcy, liquidation or reorganization (or the bankruptcy, liquidation or reorganization of a subsidiary or affiliate), such subsidiaries’ or other affiliates’ creditors, including trade creditors and holders of debt issued by such subsidiaries or affiliates, will generally be entitled to payment of their claims from the assets of those subsidiaries or affiliates before any assets are made available for distribution to us or the holders of our indebtedness. In addition, we are also permitted to reorganize our subsidiaries in a manner that allows creditors of one subsidiary to collect against assets currently held by another subsidiary. As a result, holders of our indebtedness will be effectively subordinated to all present and future debts and other liabilities (including trade payables) of our subsidiaries and affiliates, and holders of debt of one of our subsidiaries or affiliates will effectively be so subordinated with respect to all of our other subsidiaries and affiliates. As of December 31, 2004, our subsidiaries had $5.2 billion of secured construction/project financing (including the Calpine Construction Finance Company, L.P. (“CCFC I”) and Calpine Generating Company, LLC (“CalGen”), formerly Calpine Construction Finance Company II, LLC (“CCFC II”), financings described below). We may incur additional project financing indebtedness in the future, which will be effectively senior to our other secured and unsecured debt.

      In addition, our unsecured notes and our other unsecured debt are effectively subordinated to all of our secured indebtedness to the extent of the value of the assets securing such indebtedness. Our secured indebtedness includes our $785 million first-priority senior secured notes and our $3.7 billion second-priority senior secured term loans and notes. These notes and term loans are secured by, respectively, first-priority and second-priority liens on, among other things, substantially all of the assets owned directly by Calpine Corporation, including its natural gas and power plant assets and the equity in all of the subsidiaries directly owned by Calpine Corporation. Our $786.8 million of CCFC I secured institutional term loans and notes is secured by the assets and contracts associated with the seven natural gas-fired electric generating facilities owned by CCFC I and its subsidiaries (as adjusted for approved dispositions and acquisitions, such as the completed sale of Lost Pines Power Project and the acquisition of the Brazos Valley Power Plant) and the CCFC I lenders’ and note holders’ recourse is limited to such security. Our $2.6 billion of CalGen secured institutional term loans, notes and revolving credit facility are secured, through a combination of direct and indirect stock pledges and asset liens, by CalGen’s 14 power generating facilities and related assets located throughout the United States, and the CalGen lenders’ and note holders’ recourse is limited to such security. We have additional non-recourse project financings, secured in each case by the assets of the project being

financed. We may incur additional secured indebtedness in the future, which will be effectively senior, to the extent of the assets securing that debt, to our unsecured debt and to our other secured debt not secured by those assets.

Operations

      Revenue may be reduced significantly upon expiration or termination of our PSAs. Some of the electricity we generate from our existing portfolio is sold under long-term PSAs that expire at various times. We also sell power under short to intermediate term (one to five year) contracts. When the terms of each of these various PSAs expire, it is possible that the price paid to us for the generation of electricity under subsequent arrangements may be reduced significantly.

      Our power sales contracts have an aggregate value in excess of current market prices (measured over the next five years) of approximately $3.3 billion at December 31, 2004. We are at risk of loss in margins to the extent that these contracts expire or are terminated and we are unable to replace them on comparable terms. We have two customers with which we have multiple contracts that, when combined, constitute greater than 10% of this value: CDWR, $1.4 billion, and PG&E, $0.4 billion. The values by customer are comprised of these multiple individual contracts that expire beginning in 2009 and contain termination provisions standard to contracts in our industry such as negligence, performance default or prolonged events of force majeure.

      Use of commodity contracts, including standard power and gas contracts (many of which constitute derivatives), can create volatility in earnings and may require significant cash collateral. During 2004 we recognized $13.5 million in mark-to-market gains on electric power and natural gas derivatives after recognizing $26.4 million in losses in 2003. Additionally, we recognized as a cumulative effect of a change in accounting principle, an after-tax gain of approximately $181.9 million from the adoption of Derivatives Implementation Group (“DIG”) Issue No. C20, “Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature” (“DIG Issue No. C20”) on October 1, 2003. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Application of Critical Accounting Policies” for a detailed discussion of the accounting requirements relating to electric power and natural gas derivatives. In addition, U.S. generally accepted accounting principles (“GAAP”) treatment of derivatives in general, and particularly in our industry, continues to evolve. We may enter into other transactions in future periods that require us to mark various derivatives to market through earnings. The nature of the transactions that we enter into and the volatility of natural gas and electric power prices will determine the volatility of earnings that we may experience related to these transactions.

      As a result, in part, of the fallout from Enron’s declaration of bankruptcy on December 2, 2001, companies using derivatives, many of which are commodity contracts, have become more sensitive to the inherent risks of such transactions. Consequently (and for us, as a result of our recent downgrades), many companies, including us, are required to post cash collateral for certain commodity transactions in excess of what was previously required. As of December 31, 2004, we had $248.9 million in margin deposits with counterparties, net of deposits posted by counterparties with us, $78.0 million in prepaid gas and power payments and had posted $115.9 million of letters of credit, compared to $188.0 million, $60.6 million and $14.5 million, respectively, at December 31, 2003. Future cash collateral requirements may increase based on the extent of our involvement in commodity transactions and movements in commodity prices and also based on our credit ratings and general perception of creditworthiness in this market.

      We may be unable to obtain an adequate supply of natural gas in the future. To date, our fuel acquisition strategy has included various combinations of our own gas reserves, gas prepayment contracts, short-, medium-and long-term supply contracts and gas hedging transactions. In our gas supply arrangements, we attempt to match the fuel cost with the fuel component included in the facility’s PSAs in order to minimize a project’s exposure to fuel price risk. In addition, the focus of CES is to manage the spark spread for our portfolio of generating plants and we actively enter into hedging transactions to lock in gas costs and spark spreads. We believe that there will be adequate supplies of natural gas available at reasonable prices for each of our facilities when current gas supply agreements expire. However, gas supplies may not be available for the

full term of the facilities’ PSAs, and gas prices may increase significantly. Additionally, our credit ratings may inhibit our ability to procure gas supplies from third parties. If gas is not available, or if gas prices increase above the level that can be recovered in electricity prices, there could be a negative impact on our results of operations or financial condition.

      As of December 31, 2004, we obtained approximately 7% of our physical natural gas supply needs through owned natural gas reserves. We obtain the remainder of our physical natural gas supply from the market and utilize the natural gas financial markets to hedge our exposures to natural gas price risk. Our current less than investment grade credit rating increases the amount of collateral that certain of our suppliers require us to post for purchases of physical natural gas supply and hedging instruments. To the extent that we do not have cash or other means of posting credit, we may be unable to procure an adequate supply of natural gas or natural gas hedging instruments. In addition, the fact that our deliveries of natural gas depend upon the natural gas pipeline infrastructure in markets where we operate power plants exposes us to supply disruptions in the unusual event that the pipeline infrastructure is damaged or disabled.

      Our power project development and acquisition activities may not be successful. The development of power generation facilities is subject to substantial risks. In connection with the development of a power generation facility, we must generally obtain:

      We may be unsuccessful in accomplishing any of these matters or in doing so on a timely basis. In addition, project development is subject to various environmental, engineering and construction risks relating to cost-overruns, delays and performance. Although we may attempt to minimize the financial risks in the development of a project by securing a favorable power sales agreement, obtaining all required governmental permits and approvals, and arranging adequate financing prior to the commencement of construction, the development of a power project may require us to expend significant sums for preliminary engineering, permitting, legal and other expenses before we can determine whether a project is feasible, economically attractive or financeable. If we are unable to complete the development of a facility, we might not be able to recover our investment in the project. The process for obtaining initial environmental, siting and other governmental permits and approvals is complicated and lengthy, often taking more than one year, and is subject to significant uncertainties. We cannot assure you that we will be successful in the development of power generation facilities in the future or that we will be able to successfully complete construction of our facilities currently in development, nor can we assure you that any of these facilities will be profitable or have value equal to the investment in them even if they do achieve commercial operation.

      We have grown substantially in recent years partly as a result of acquisitions of interests in power generation facilities, geothermal steam fields and natural gas reserves and facilities. The integration and consolidation of our acquisitions with our existing business requires substantial management, financial and other resources and, ultimately, our acquisitions may not be successfully integrated. In addition, as we transition from a development company to an operating company, we are not likely to continue to grow at historical rates due to reduced acquisition activities in the near future. We have also substantially curtailed our development efforts in response to our reduced liquidity. Although the domestic power industry is continuing to undergo consolidation and may offer acquisition opportunities at favorable prices, we believe that we are likely to confront significant competition for those opportunities and, due to the constriction in the availability of capital resources for acquisitions and other expansion, to the extent that any opportunities are identified, we

may be unable to effect any acquisitions. Similarly, to the extent we seek to divest assets, we may not be able to do so at attractive prices.

      Our projects under construction may not commence operation as scheduled. The commencement of operation of a newly constructed power generation facility involves many risks, including:

      New plants have no operating history and may employ recently developed and technologically complex equipment. Insurance (including a layer of insurance provided by a captive insurance subsidiary) is maintained to protect against certain risks, warranties are generally obtained for limited periods relating to the construction of each project and its equipment in varying degrees, and contractors and equipment suppliers are obligated to meet certain performance levels. The insurance, warranties or performance guarantees, however, may not be adequate to cover lost revenues or increased expenses. As a result, a project may be unable to fund principal and interest payments under its financing obligations and may operate at a loss. A default under such a financing obligation, unless cured, could result in our losing our interest in a power generation facility.

      In certain situations, PSAs entered into with a utility early in the development phase of a project may enable the utility to terminate the PSA or to retain security posted as liquidated damages under the PSA. Currently, six of our 11 projects under construction are party to PSAs containing such provisions and could be materially affected if these provisions were triggered. The six projects are our Freeport, Valladolid, Mankato, Bethpage, Fox and Otay Mesa facilities. The situations that could allow a utility to terminate a PSA or retain posted security as liquidated damages include:

      Our power generation facilities may not operate as planned. Upon completion of our projects currently under construction, we will operate 100 of the 103 power plants in which we will have an interest. The continued operation of power generation facilities, including, upon completion of construction, the facilities owned directly by us, involves many risks, including the breakdown or failure of power generation equipment, transmission lines, pipelines or other equipment or processes, and performance below expected levels of output or efficiency. From time to time our power generation facilities have experienced equipment breakdowns or failures, and in 2004 we recorded expenses totaling approximately $54.3 million for these breakdowns or failures compared to $11.0 million in 2003. Continued high failure rates of Siemens Westinghouse (“SW”) provided equipment represent the highest risk for such breakdowns, although we have programs in place that we believe will eventually substantially reduce these failures and provide plants with SW equipment availability factors competitive with plants using other manufacturers’ equipment.

      Although our facilities contain various redundancies and back-up mechanisms, a breakdown or failure may prevent the affected facility from performing under any applicable PSAs. Although insurance is maintained to partially protect against operating risks, the proceeds of insurance may not be adequate to cover lost revenues or increased expenses. As a result, we could be unable to service principal and interest payments under our financing obligations which could result in losing our interest in one or more power generation facility.

      We cannot assure you that our estimates of oil and gas reserves are accurate. Estimates of proved oil and gas reserves and the future net cash flows attributable to those reserves are prepared by independent petroleum and geological engineers. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and cash flows attributable to such reserves, including factors beyond our control and that of our engineers. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to such reserves, is a function of the available data, assumptions regarding future oil and gas prices and expenditures for future development and exploitation activities, and of engineering and geological interpretation and judgment. Additionally, reserves and future cash flows may be subject to material downward or upward revisions, based upon production history, development and exploration activities and prices of oil and gas. Actual future production, revenue, taxes, development expenditures, operating expenses, underlying information, quantities of recoverable reserves and the value of cash flows from such reserves may vary significantly from the assumptions and underlying information set forth herein. In addition, different reserve engineers may make different estimates of reserves and cash flows based on the same available data. We recorded impairment charges of $202.1 million related to reduced proved reserve projections at year end 2004 based on the year-end independent engineer’s report.

      Our geothermal energy reserves may be inadequate for our operations. The development and operation of geothermal energy resources are subject to substantial risks and uncertainties similar to those experienced in the development of oil and gas resources. The successful exploitation of a geothermal energy resource ultimately depends upon:

      In connection with each geothermal power plant, we estimate the productivity of the geothermal resource and the expected decline in productivity. The productivity of a geothermal resource may decline more than anticipated, resulting in insufficient reserves being available for sustained generation of the electrical power capacity desired. An incorrect estimate by us or an unexpected decline in productivity could, if material, adversely affect our results of operations or financial condition.

      Geothermal reservoirs are highly complex. As a result, there exist numerous uncertainties in determining the extent of the reservoirs and the quantity and productivity of the steam reserves. Reservoir engineering is an inexact process of estimating underground accumulations of steam or fluids that cannot be measured in any precise way, and depends significantly on the quantity and accuracy of available data. As a result, the estimates of other reservoir specialists may differ materially from ours. Estimates of reserves are generally revised over time on the basis of the results of drilling, testing and production that occur after the original estimate was prepared. We cannot assure you that we will be able to successfully manage the development and operation of our geothermal reservoirs or that we will accurately estimate the quantity or productivity of our steam reserves.

Market

      Competition could adversely affect our performance. The power generation industry is characterized by intense competition, and we encounter competition from utilities, industrial companies, marketing and trading companies, and other IPPs. In recent years, there has been increasing competition among generators in an effort to obtain PSAs, and this competition has contributed to a reduction in electricity prices in certain markets. In addition, many states are implementing or considering regulatory initiatives designed to increase competition in the domestic power industry. For instance, the California Public Utilities Commission (“CPUC”) issued decisions that provided that all California electric users taking service from a regulated public utility could elect to receive direct access service commencing April 1998; however, the CPUC suspended the offering of direct access to any customer not receiving direct access service as of September 20, 2001, due to the problems experienced in the California energy markets during 2000 and 2001. As a result, uncertainty exists as to the future course for direct access in California in the aftermath of the energy crisis in that state. In Texas, legislation phased in a deregulated power market, which commenced on January 1, 2001. This competition has put pressure on electric utilities to lower their costs, including the cost of purchased electricity, and increasing competition in the supply of electricity in the future will increase this pressure.

      Our international investments may face uncertainties. We have investments in operating power projects in Canada, an investment in an energy service business in the Netherlands, an investment in a power generation facility in construction in Mexico, and an investment in a power generation facility in the U.K. that is in operation and is being evaluated for possible sale (see “Recent Developments” above). We may pursue additional international investments in the future subject to the limitations on our expansion plans due to current capital market constraints. International investments are subject to unique risks and uncertainties relating to the political, social and economic structures of the countries in which we invest. Risks specifically related to investments in non-United States projects may include:

California Power Market

      The volatility in the California power market from mid-2000 through mid-2001 has produced significant unanticipated results, and as described in the following risk factors, the unresolved issues arising in that market, where 42 of our 103 power plants are located, could adversely affect our performance.

      We may be required to make refund payments to the CalPX and CAISO as a result of the California Refund Proceeding. On August 2, 2000, the California Refund Proceeding was initiated by a complaint made at FERC by SDG&E under Section 206 of the FPA alleging, among other things, that the markets operated by the CAISO and the California Power Exchange (“CalPX”) were dysfunctional. FERC established a refund effective period of October 2, 2000, to June 19, 2001 (the “Refund Period”), for sales made into those markets.

      On December 12, 2002, an Administrative Law Judge issued a Certification of Proposed Finding on California Refund Liability (“December 12 Certification”) making an initial determination of refund liability. On March 26, 2003, FERC issued an order (the “March 26 Order”) adopting many of the findings set forth in the December 12 Certification. In addition, as a result of certain findings by the FERC staff concerning the unreliability or misreporting of certain reported indices for gas prices in California during the Refund Period, FERC ordered that the basis for calculating a party’s potential refund liability be modified by substituting a gas proxy price based upon gas prices in the producing areas plus the tariff transportation rate for the California gas price indices previously adopted in the California Refund Proceeding. We believe, based on the information that we have analyzed to date, that any refund liability that may be attributable to us could total

approximately $9.9 million (plus interest, if applicable), after taking the appropriate set-offs for outstanding receivables owed by the CalPX and CAISO to Calpine. We believe we have appropriately reserved for the refund liability that by our current analysis would potentially be owed under the refund calculation clarification in the March 26 Order. The final determination of the refund liability and the allocation of payment obligations among the numerous buyers and sellers in the California markets is subject to further Commission proceedings. It is possible that there will be further proceedings to require refunds from certain sellers for periods prior to the originally designated Refund Period. In addition, the FERC orders concerning the Refund Period, the method for calculating refund liability and numerous other issues are pending on appeal before the U.S. Court of Appeals for the Ninth Circuit. At this time, we are unable to predict the timing of the completion of these proceedings or the final refund liability. Thus, the impact on our business is uncertain.

      We have been mentioned in a show cause order in connection with the FERC investigation into western markets regarding the CalPX and CAISO tariffs and may be found liable for payments thereunder. On February 13, 2002, FERC initiated an investigation of potential manipulation of electric and natural gas prices in the western United States. This investigation was initiated as a result of allegations that Enron and others used their market position to distort electric and natural gas markets in the West. The scope of the investigation is to consider whether, as a result of any manipulation in the short-term markets for electric energy or natural gas or other undue influence on the wholesale markets by any party since January 1, 2000, the rates of the long-term contracts subsequently entered into in the West are potentially unjust and unreasonable. On August 13, 2002, the FERC staff issued the Initial Report on Company-Specific Separate Proceedings and Generic Reevaluations; Published Natural Gas Price Data; and Enron Trading Strategies (the “Initial Report”), summarizing its initial findings in this investigation. There were no findings or allegations of wrongdoing by Calpine set forth or described in the Initial Report. On March 26, 2003, the FERC staff issued a final report in this investigation (the “Final Report”). In the Final Report, the FERC staff recommended that FERC issue a show cause order to a number of companies, including Calpine, regarding certain power scheduling practices that may have been in violation of the CAISO’s or CalPX’s tariff. The Final Report also recommended that FERC modify the basis for determining potential liability in the California Refund Proceeding discussed above. Calpine believes that it did not violate these tariffs and that, to the extent that such a finding could be made, any potential liability would not be material.

      Also, on June 25, 2003, FERC issued a number of orders associated with these investigations, including the issuance of two show cause orders to certain industry participants. FERC did not subject Calpine to either of the show cause orders. FERC also issued an order directing the FERC Office of Markets and Investigations to investigate further whether market participants who bid a price in excess of $250 per MWh hour into markets operated by either the CAISO or the CalPX during the period of May 1, 2000, to October 2, 2000, may have violated CAISO and CalPX tariff prohibitions. No individual market participant was identified. We believe that we did not violate the CAISO and CalPX tariff prohibitions referred to by FERC in this order; however, we are unable to predict at this time the final outcome of this proceeding or its impact on Calpine.

      The energy payments made to us during a certain period under our QF contracts with PG&E may be retroactively adjusted downward as a result of a CPUC proceeding. Our QF contracts with PG&E provide that the CPUC has the authority to determine the appropriate utility “avoided cost” to be used to set energy payments by determining the short run avoided cost (“SRAC”) energy price formula. In mid-2000 our QF facilities elected the option set forth in Section 390 of the California Public Utilities Code, which provided QFs the right to elect to receive energy payments based on the CalPX market clearing price instead of the SRAC price administratively determined by the CPUC. Having elected such option, our QF facilities were paid based upon the CalPX zonal day-ahead clearing price (“CalPX Price”) for various periods commencing in the summer of 2000 until January 19, 2001, when the CalPX ceased operating a day-ahead market. The CPUC has conducted proceedings (R.99-11-022) to determine whether the CalPX Price was the appropriate price for the energy component upon which to base payments to QFs which had elected the CalPX-based pricing option. One CPUC Commissioner at one point issued a proposed decision to the effect that the CalPX Price was the appropriate energy price to pay QFs who selected the pricing option then offered by Section 390. No final decision, however, has been issued to date. Therefore, it is possible that the CPUC could order a

payment adjustment based on a different energy price determination. On January 10, 2001, PG&E filed an emergency motion (the “Emergency Motion”) requesting that the CPUC issue an order that would retroactively change the energy payments received by QFs based on CalPX-based pricing for electric energy delivered during the period commencing during June 2000 and ending on January 18, 2001. On April 29, 2004, PG&E, the Utility Reform Network, a consumer advocacy group, and the Office of Ratepayer Advocates, an independent consumer advocacy department of the CPUC (collectively, the “PG&E Parties”), filed a Motion for Briefing Schedule Regarding True-Up of Payments to QF Switchers (the “April 2004 Motion”). The April 2004 Motion requests that the CPUC set a briefing schedule in R.99-11-022 to determine what is the appropriate price that should be paid to the QFs that had switched to the CalPX Price. The PG&E Parties allege that the appropriate price should be determined using the methodology that has been developed thus far in the California Refund Proceeding discussed above. Supplemental pleadings have been filed on the April 2004 Motion, but neither the CPUC nor the assigned administrative law judge has issued any rulings with respect to either the April 2004 Motion or the initial Emergency Motion. We believe that the CalPX Price was the appropriate price for energy payments for our QFs during this period, but there can be no assurance that this will be the outcome of the CPUC proceedings.

      The availability payments made to us under our Geysers’ Reliability Must Run contracts have been challenged by certain buyers as having been not just and reasonable. CAISO, California Electricity Oversight Board, Public Utilities Commission of the State of California, PG&E, SDG&E, and Southern California Edison Company (collectively referred to as the “Buyers Coalition”) filed a complaint on November 2, 2001 at FERC requesting the commencement of a FPA Section 206 proceeding to challenge one component of a number of separate settlements previously reached on the terms and conditions of “reliability must run” contracts (“RMR Contracts”) with certain generation owners, including Geysers Power Company, LLC, which settlements were also previously approved by FERC. RMR Contracts require the owner of the specific generation unit to provide energy and ancillary services when called upon to do so by the ISO to meet local transmission reliability needs or to manage transmission constraints. The Buyers Coalition has asked FERC to find that the availability payments under these RMR Contracts are not just and reasonable. Geysers Power Company, LLC filed an answer to the complaint in November 2001. To date, FERC has not established a Section 206 proceeding. The outcome of this litigation and the impact on our business cannot be determined at the present time.

Government Regulation

      We are subject to complex government regulation which could adversely affect our operations. Our activities are subject to complex and stringent energy, environmental and other governmental laws and regulations. The construction and operation of power generation facilities and oil and gas exploration and production require numerous permits, approvals and certificates from appropriate foreign, federal, state and local governmental agencies, as well as compliance with environmental protection legislation and other regulations. While we believe that we have obtained the requisite approvals and permits for our existing operations and that our business is operated in accordance with applicable laws, we remain subject to a varied and complex body of laws and regulations that both public officials and private individuals may seek to enforce. Existing laws and regulations may be revised or reinterpreted, or new laws and regulations may become applicable to us that may have a negative effect on our business and results of operations. We may be unable to obtain all necessary licenses, permits, approvals and certificates for proposed projects, and completed facilities may not comply with all applicable permit conditions, statutes or regulations. In addition, regulatory compliance for the construction of new facilities is a costly and time-consuming process. Intricate and changing environmental and other regulatory requirements may necessitate substantial expenditures to obtain and maintain permits. If a project is unable to function as planned due to changing requirements or local opposition, it may create expensive delays, extended periods of non-operation or significant loss of value in a project.

      Environmental regulations have had and will continue to have an impact on our cost of doing business and our investment decisions. For example, the existing market-based cap-and-trade emissions allowance system in Texas requires operators to either reduce NOx emissions or purchase additional NOx allowances in

the marketplace. Rather than purchase additional allowances, we have chosen to install additional NOx emission controls as part of a $31 million steam capacity upgrade at our Texas City facility and to retrofit our Clear Lake, Texas facility with similar technology at a cost of approximately $17 million. These new emission control systems will allow us to meet our thermal customers’ needs while reducing the need to purchase allowances for our facilities in Texas.

      Our operations are potentially subject to the provisions of various energy laws and regulations, including PURPA, PUHCA, the FPA, and state and local regulations. PUHCA provides for the extensive regulation of public utility holding companies and their subsidiaries. PURPA provides QFs (as defined under PURPA) and owners of QFs exemptions from certain federal and state regulations, including rate and financial regulations. The FPA regulates wholesale sales of power, as well as electric transmission in interstate commerce.

      Under current federal law, we are not subject to regulation as a holding company under PUHCA, and will not be subject to such regulation as long as the plants in which we have an interest (1) qualify as QFs, (2) are subject to another exemption or waiver or (3) are owned or operated by an EWG under the Energy Policy Act of 1992. In order to be a QF, a facility must be not more than 50% owned by one or more electric utility companies, electric utility holding companies, or any combination thereof. Generally, any geothermal power facility which produces not more than 80 MW of electricity and meets PURPA ownership requirements qualifies for QF status. In addition, a QF that is a cogeneration facility, such as the plants in which we currently have interests, must produce electricity as well as thermal energy for use in an industrial or commercial process in specified minimum proportions. The QF also must meet certain minimum energy efficiency standards.

      If any of the plants in which we have an interest lose their QF status or if amendments to PURPA are enacted that substantially reduce the benefits currently afforded QFs, we could become a public utility holding company, which could subject us to significant federal, state and local regulation, including rate regulation. If we become a holding company, which could be deemed to occur prospectively or retroactively to the date that any of our plants loses its QF status, all of our other QF power plants could lose QF status because, under FERC regulations, no more than 50% of a QF’s equity can be owned by an electric utility, electric utility holding company, or any combination thereof. In addition, a loss of QF status could, depending on the particular power purchase agreement, allow the power purchaser to cease taking and paying for electricity or to seek refunds of past amounts paid and thus could cause the loss of some or all contract revenues or otherwise impair the value of a project. If a power purchaser were to cease taking and paying for electricity, there can be no assurance that the costs incurred in connection with the project could be recovered through sales to other purchasers. Such events could adversely affect our ability to service our indebtedness. See “Item 1 — Business — Government Regulation — Federal Energy Regulation — Federal Power Act Regulation.” A cogeneration QF could lose its QF status if it does not continue to meet FERC’s operating and efficiency requirements. Such possible loss of QF status could occur, for example, if the QF’s steam host, typically an industrial facility, fails for operating, permit or economic reasons to use sufficient quantities of the QF’s steam output. We cannot assure you that all of our steam hosts will continue to take and use sufficient quantities of their respective QF’s steam output.

      In light of the experiences in the California electricity and natural gas markets in 2000 and 2001, and the PG&E and Enron bankruptcy filings in 2001, among other events in recent years, there are a number of federal legislative and regulatory initiatives that could result in changes in how the energy markets are regulated. For example, Congress has considered proposed legislation that would repeal PUHCA, and would amend PURPA, among other ways, by, in certain circumstances, limiting its mandatory purchase obligation to existing contracts. We do not know whether these legislative or regulatory initiatives will be adopted or, if adopted, what form they may take. We cannot provide assurance that any legislation or regulation ultimately adopted would not adversely affect our existing projects.

      In addition, many states are implementing or considering regulatory initiatives designed to increase competition in the domestic power generation industry and increase access to electric utilities’ transmission and distribution systems for IPPs and electricity consumers. However, in light of the circumstances in the California electricity and natural gas markets and the bankruptcies of both PG&E and Enron, the pace and

direction of further deregulation at the state level in many jurisdictions is uncertain. See “California Power Market” risk factors.

Other Risk Factors

      We depend on our management and employees. Our success is largely dependent on the skills, experience and efforts of our people. While we believe that we have excellent depth throughout all levels of management and in all key skill levels of our employees, the loss of the services of one or more members of our senior management or of numerous employees with critical skills could have a negative effect on our business, financial conditions and results of operations and future growth. We have an employment agreement with our Chief Executive Officer.

      Seismic disturbances could damage our projects. Areas where we operate and are developing many of our geothermal and gas-fired projects are subject to frequent low-level seismic disturbances. More significant seismic disturbances are possible. Our existing power generation facilities are built to withstand relatively significant levels of seismic disturbances, and we believe we maintain adequate insurance protection. However, earthquake, property damage or business interruption insurance may be inadequate to cover all potential losses sustained in the event of serious seismic disturbances. Additionally, insurance for these risks may not continue to be available to us on commercially reasonable terms.

      Our results are subject to quarterly and seasonal fluctuations. Our quarterly operating results have fluctuated in the past and may continue to do so in the future as a result of a number of factors, including:

      Additionally, because we receive the majority of capacity payments under some of our PSAs during the months of May through October, our revenues and results of operations are, to some extent, seasonal.

      The ultimate outcome of the legal proceedings relating to our activities cannot be predicted. Any adverse determination could have a material adverse effect on our financial condition and results of operations. We are party to various litigation matters arising out of the normal course of business, the more significant of which are summarized in Note 25 of the Notes to Consolidated Financial Statements. These matters include securities class action lawsuits, such as Hawaii Structural Ironworkers Pension Fund v. Calpine et al., which relates to our April 2002 equity offering and also named the underwriters of that offering as defendants. The ultimate outcome of each of these matters cannot presently be determined, nor can the liability that may potentially result from a negative outcome be reasonably estimated presently for every case. The liability we may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued with respect to such matters and, as a result, these matters may potentially be material to our financial condition and results of operations.

      The price of our common stock is volatile. The market price for our common stock has been volatile in the past, and several factors could cause the price to fluctuate substantially in the future. These factors include without limitation:

      The market price of our common stock may fluctuate significantly in the future, and these fluctuations may be unrelated to our performance. General market price declines or market volatility in the future could adversely affect the price of our common stock, and the current market price may not be indicative of future market prices.

EMPLOYEES

      As of December 31, 2004, we employed 3,505 people, of whom 62 were represented by collective bargaining agreements. We have never experienced a work stoppage or strike, and we consider relations with our employees to be good. Although we are an asset-based company, we are successful because of the talents, intelligence, resourcefulness and energy level of our employees. As discussed throughout this business section, our employee knowledge base enables us to optimize the value and profitability of our electricity production and prudently manage the risks inherent in our business.

SUMMARY OF KEY ACTIVITIES

      See Item 1. “Business — Recent Developments” for 2005 developments.

      Election of Ann B. Curtis, Kenneth T. Derr and Gerald Greenwald as Class II Directors for a three-year term expiring 2007

      The three-year terms of Class I and Class III Directors continued after the Annual Meeting and will expire in 2006 and 2005, respectively. The Class I Directors are Jeffrey E. Garten, George J. Stathakis and John O. Wilson. The Class III Directors are Peter Cartwright, Susan C. Schwab and Susan Wang.

NYSE CERTIFICATION

      The annual certification of our Chief Executive Officer, Peter Cartwright, required to be furnished to the New York Stock Exchange pursuant to Section 303A.12(a) of the NYSE Listed Company Manual was previously filed with the New York Stock Exchange in May 2004. The certification confirmed that he was unaware of any violation by the Company of NYSE’s corporate governance listing standards.

      Our principal executive office located in San Jose, California is held under leases that expire through 2014, and we also lease offices, with leases expiring through 2014, in Dublin, Sacramento and Folsom, California; Houston and Pasadena, Texas; Boston, Massachusetts; Washington, D.C.; Calgary, Alberta; and Tampa and Jupiter, Florida. We hold additional leases for other satellite offices.

      We either lease or own the land upon which our power-generating facilities are built. We believe that our properties are adequate for our current operations. A description of our power-generating facilities is included under Item 1. “Business.”

      We have leasehold interests in 105 leases comprising 25,944 acres of federal, state and private geothermal resource lands in The Geysers area in northern California. In the Glass Mountain and Medicine Lake areas in northern California, we hold leasehold interests in 41 leases comprising approximately 46,400 acres of federal geothermal resource lands.

      In general, under these leases, we have the exclusive right to drill for, produce and sell geothermal resources from these properties and the right to use the surface for all related purposes. Each lease requires the payment of annual rent until commercial quantities of geothermal resources are established. After such time, the leases require the payment of minimum advance royalties or other payments until production commences, at which time production royalties are payable. Such royalties and other payments are payable to landowners, state and federal agencies and others, and vary widely as to the particular lease. The leases are generally for initial terms varying from 10 to 20 years or for so long as geothermal resources are produced and sold. Certain of the leases contain drilling or other exploratory work requirements. In certain cases, if a requirement is not fulfilled, the lease may be terminated and in other cases additional payments may be required. We believe that our leases are valid and that we have complied with all the requirements and conditions material to the continued effectiveness of the leases. A number of our leases for undeveloped properties may expire in any given year. Before leases expire, we perform geological evaluations in an effort to determine the resource potential of the underlying properties. We can make no assurance that we will decide to renew any expiring leases.

      Based on independent petroleum engineering reports of Netherland, Sewell & Associates Inc., as of December 31, 2004, utilizing year end product prices and costs held constant, our proved oil, natural gas, and natural gas liquids (“NGLs”) reserve volumes, in millions of barrels (“MMBbls”) and billions of cubic feet (“Bcf”) are as follows:

      Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Estimated future development costs associated with proved producing and non-producing plus proved undeveloped reserves as of December 31, 2004, totaled approximately $189.4 million. No estimates of total, proved net oil or gas reserves were filed with or included in reports to any other federal authority or agency (other than the SEC) since January 1, 2004.

      The following table sets forth our interest in undeveloped acreage, developed acreage and productive wells in which we own a working interest as of December 31, 2004. Gross represents the total number of acres or wells in which we own a working interest. Net represents our proportionate working interest resulting from our ownership in the gross acres or wells. Productive wells are wells in which we have a working interest and are capable of producing oil or natural gas.